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Sample records for oil reservoirs technical

  1. Chemical Flooding in Heavy-Oil Reservoirs: From Technical Investigation to Optimization Using Response Surface Methodology

    Directory of Open Access Journals (Sweden)

    Si Le Van

    2016-09-01

    Full Text Available Heavy-oil resources represent a large percentage of global oil and gas reserves, however, owing to the high viscosity, enhanced oil recovery (EOR techniques are critical issues for extracting this type of crude oil from the reservoir. According to the survey data in Oil & Gas Journal, thermal methods are the most widely utilized in EOR projects in heavy oil fields in the US and Canada, and there are not many successful chemical flooding projects for heavy oil reported elsewhere in the world. However, thermal methods such as steam injection might be restricted in cases of thin formations, overlying permafrost, or reservoir depths over 4500 ft, for which chemical flooding becomes a better option for recovering crude oil. Moreover, owing to the considerable fluctuations in the oil price, chemical injection plans should be employed consistently in terms of either technical or economic viewpoints. The numerical studies in this work aim to clarify the predominant chemical injection schemes among the various combinations of chemical agents involving alkali (A, surfactant (S and polymer (P for specific heavy-oil reservoir conditions. The feasibilities of all potential injection sequences are evaluated in the pre-evaluation stage in order to select the most efficient injection scheme according to the variation in the oil price which is based on practical market values. Finally, optimization procedures in the post-evaluation stage are carried out for the most economic injection plan by an effective mathematic tool with the purpose of gaining highest Net Present Value (NPV of the project. In technical terms, the numerical studies confirm the predominant performances of sequences in which alkali-surfactant-polymer (ASP solution is injected after the first preflushing water whereby the recovery factor can be higher than 47%. In particular, the oil production performances are improved by injecting a buffering viscous fluid right after the first chemical slug

  2. Increased oil production and reserves utilizing secondary/tertiary recovery techniques on small reservoirs in the Paradox basin, Utah. Final technical progress report, October 1--December 31, 1995

    Energy Technology Data Exchange (ETDEWEB)

    Allison, M.L.

    1996-01-15

    The primary objective of this project is to enhance domestic petroleum production by demonstration and technology transfer of an advanced oil recovery technology in the Paradox basin, southeastern Utah. If this project can demonstrate technical and economic feasibility, the technique can be applied to approximately 100 additional small fields in the Paradox basin alone, and result in increased recovery of 150 to 200 million barrels of oil. This project is designed to characterize five shallow-shelf carbonate reservoirs in the Pennsylvanian (Desmoinesian) Paradox Formation and choose the best candidate for a pilot demonstration project for either a waterflood or carbon dioxide-(CO{sub 2}) flood project. The field demonstration, monitoring of field performance, and associated validation activities will take place in the Paradox basin within the Navajo Nation. The results of this project will be transferred to industry and other researchers through a petroleum extension service, creation of digital databases for distribution, technical workshops and seminars, field trips, technical presentations at national and regional professional meeting, and publication in newsletters and various technical or trade journals. Five activities continued this quarter as part of the geological and reservoir characterization of carbonate mound buildups in the Paradox basin: (1) regional facies evaluation, (2) evaluation of outcrop analogues, (3) field-scale geologic analysis, (4) reservoir analysis, and (5) technology transfer.

  3. Increasing heavy oil reservers in the Wilmington oil Field through advanced reservoir characterization and thermal production technologies, technical progress report, October 1, 1996--December 31, 1996

    Energy Technology Data Exchange (ETDEWEB)

    Hara, S. [Tidelands Oil Production Co., Long Beach, CA (United States)], Casteel, J. [USDOE Bartlesville Project Office, OK (United States)

    1997-05-11

    The project involves improving thermal recovery techniques in a slope and basin clastic (SBC) reservoir in the Wilmington field, Los Angeles Co., Calif. using advanced reservoir characterization and thermal production technologies. The existing steamflood in the Tar zone of Fault Block (FB) 11-A has been relatively inefficient because of several producibility problems which are common in SBC reservoirs. Inadequate characterization of the heterogeneous turbidite sands, high permeability thief zones, low gravity oil, and nonuniform distribution of remaining oil have all contributed to poor sweep efficiency, high steam-oil ratios, and early steam breakthrough. Operational problems related to steam breakthrough, high reservoir pressure, and unconsolidated formation sands have caused premature well and downhole equipment failures. In aggregate, these reservoir and operational constraints have resulted in increased operating costs and decreased recoverable reserves. The advanced technologies to be applied include: (1) Develop three-dimensional (3-D) deterministic and stochastic geologic models. (2) Develop 3-D deterministic and stochastic thermal reservoir simulation models to aid in reservoir management and subsequent development work. (3) Develop computerized 3-D visualizations of the geologic and reservoir simulation models to aid in analysis. (4) Perform detailed study on the geochemical interactions between the steam and the formation rock and fluids. (5) Pilot steam injection and production via four new horizontal wells (2 producers and 2 injectors). (6) Hot water alternating steam (WAS) drive pilot in the existing steam drive area to improve thermal efficiency. (7) Installing a 2100 foot insulated, subsurface harbor channel crossing to supply steam to an island location. (8) Test a novel alkaline steam completion technique to control well sanding problems and fluid entry profiles. (9) Advanced reservoir management through computer-aided access to production and

  4. 1996 SPE annual technical conference and exhibition: Reservoir engineering

    Energy Technology Data Exchange (ETDEWEB)

    NONE

    1996-12-31

    This document contains the Proceedings of the 1996 Society of Petroleum Engineers Annual Technical Conference and Exhibition, Reservoir Engineering section. Topics covered in this section include the evaluation of reservoir engineering and resource management techniques for oil and natural gas fields, description of problems and maintenance techniques for fluid flow in oil wells and pipelines, and technology assessment of enhanced recovery techniques for increasing production from oil and gas fields.

  5. Increased oil production and reserves utilizing secondary/tertiary recovery techniques on small reservoirs in the Paradox Basin, Utah. Technical progress report, January 1--March 31, 1996

    Energy Technology Data Exchange (ETDEWEB)

    Allison, M.L.

    1996-04-30

    The primary objective of this project is to enhance domestic petroleum production by demonstration and technology transfer of an advanced oil recovery technology in the Paradox basin, southeastern Utah. If this project can demonstrate technical and economic feasibility, the technique can be applied to approximately 100 additional small fields in the Paradox basin alone, and result in increased recovery of 150 to 200 million barrels of oil. This project is designed to characterize five shallow-shelf carbonate reservoirs in the Pennsylvanian (Desmoinesian) Paradox Formation and choose the best candidate for a pilot demonstration project for either a waterflood or carbon dioxide-(CO{sub 2}-)flood project. The field demonstration, monitoring of field performance, and associated validation activities will take place in the Paradox basin within the Navajo Nation. The results of this project will be transferred to industry and other researchers through a petroleum extension service, creation of digital databases for distribution, technical workshops and seminars, field trips, technical presentations at national and regional professional meetings, and publication in newsletters and various technical or trade journals.

  6. Reservoir engineering. 1995 SPE annual technical conference and exhibition

    Energy Technology Data Exchange (ETDEWEB)

    NONE

    1995-12-31

    This document contains the proceedings of the Annual Technical Conference and Exhibition of the Society of Petroleum Engineers which was held on October 22-25, 1995 in Dallas, Texas. This volume contains the presentations regarding Reservoir Engineering. The topics covered in these presentations include: resource management and reservoir engineering of oil, natural gas and gas condensate fields, mathematical models and computerized simulation of fluid flow in reservoir rock, geochemistry of reservoir fluids, and enhanced recovery of oil and natural gas using waterflooding and other secondary recovery methods.

  7. Identification and evaluation of fluvial-dominated deltaic (class 1 oil) reservoirs in Oklahoma. Quarterly technical progress report, July 1, 1993--September 30, 1993

    Energy Technology Data Exchange (ETDEWEB)

    Mankin, C.J. [Oklahoma Geological Survey, Norman, OK (United States); Banken, M.K. [Oklahoma Univ., Norman, OK (United States)

    1994-04-28

    The Oklahoma Geological Survey (OGS), the Geological Information Systems department, and the School of Petroleum and Geological Engineering at the University of Oklahoma are engaging in a program to identify and address Oklahoma`s oil recovery opportunities in fluvial-dominated deltaic (FDD) reservoirs. This program includes the systematic and comprehensive collection and evaluation of information on all of Oklahoma`s FDD reservoirs and the recovery technologies that have been (or could be) applied to those reservoirs with commercial success. This data collection and evaluation effort will be the foundation for an aggressive, multifaceted technology transfer program that is designed to support all of Oklahoma`s oil industry, with particular emphasis on smaller companies and independent operators in their attempts to maximize the economic producibility of FDD reservoirs. Specifically, this project will identify all FDD oil reservoirs in the State; group those reservoirs into plays that have similar depositional and subsequent geologic histories; collect, organize and analyze all available data; conduct characterization and simulation studies on selected reservoirs in each play; and implement a technology transfer program targeted to the operators of FDD reservoirs to sustain the life expectancy of existing wells with the ultimate objective of increasing oil recovery.

  8. Opportunities to improve oil productivity in unstructured deltaic reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    1991-01-01

    This report contains presentations presented at a technical symposium on oil production. Chapter 1 contains summaries of the presentations given at the Department of Energy (DOE)-sponsored symposium and key points of the discussions that followed. Chapter 2 characterizes the light oil resource from fluvial-dominated deltaic reservoirs in the Tertiary Oil Recovery Information System (TORIS). An analysis of enhanced oil recovery (EOR) and advanced secondary recovery (ASR) potential for fluvial-dominated deltaic reservoirs based on recovery performance and economic modeling as well as the potential resource loss due to well abandonments is presented. Chapter 3 provides a summary of the general reservoir characteristics and properties within deltaic deposits. It is not exhaustive treatise, rather it is intended to provide some basic information about geologic, reservoir, and production characteristics of deltaic reservoirs, and the resulting recovery problems.

  9. Oil exploration. Oil reservoir engineering; Sekiyu no kaihatsu. Choryuso kogaku

    Energy Technology Data Exchange (ETDEWEB)

    Takeda, H. [Teikoku Oil Co. Ltd., Tokyo (Japan)

    1998-09-01

    This study is to estimate the amount of oil/gas economically producible and to discuss the increase of the amount. The reservoir rock is stuffed with rock particles, and there are impermeable and dense rocks called cap rock on the side wall and top board. Since the size of void of the reservoir is very small, the volume which oil can actually occupy largely decreases because of the existence of surface tension and water film (20-40% of the volume is occupied by water). The rate of the fluid occupying in reservoir space is called the fluid saturation rate. The primitive reserve is a static volume, but the minable reserve, which is related to economical efficiency, is a dynamic volume which changes according to conditions such as the technical progress. To predict a minable reserve is to predict a production amount under a developmental plan, estimate an income, and find out the time of disposal of the oil/gas field (economical limit). To ask for a certain level of accuracy, it is indispensable to simulate the reservoir. To add an element of time to the material balance, the equation of flow including the permeability rate is solved. The paper also described measures to increase minable reserves

  10. 4. International reservoir characterization technical conference

    Energy Technology Data Exchange (ETDEWEB)

    NONE

    1997-04-01

    This volume contains the Proceedings of the Fourth International Reservoir Characterization Technical Conference held March 2-4, 1997 in Houston, Texas. The theme for the conference was Advances in Reservoir Characterization for Effective Reservoir Management. On March 2, 1997, the DOE Class Workshop kicked off with tutorials by Dr. Steve Begg (BP Exploration) and Dr. Ganesh Thakur (Chevron). Tutorial presentations are not included in these Proceedings but may be available from the authors. The conference consisted of the following topics: data acquisition; reservoir modeling; scaling reservoir properties; and managing uncertainty. Selected papers have been processed separately for inclusion in the Energy Science and Technology database.

  11. Discussion of the feasibility of air injection for enhanced oil recovery in shale oil reservoirs

    Directory of Open Access Journals (Sweden)

    Hu Jia

    2017-06-01

    Full Text Available Air injection in light oil reservoirs has received considerable attention as an effective, improved oil recovery process, based primarily on the success of several projects within the Williston Basin in the United States. The main mechanism of air injection is the oxidation behavior between oxygen and crude oil in the reservoir. Air injection is a good option because of its wide availability and low cost. Whether air injection can be applied to shale is an interesting topic from both economic and technical perspectives. This paper initiates a comprehensive discussion on the feasibility and potential of air injection in shale oil reservoirs based on state-of-the-art literature review. Favorable and unfavorable effects of using air injection are discussed in an analogy analysis on geology, reservoir features, temperature, pressure, and petrophysical, mineral and crude oil properties of shale oil reservoirs. The available data comparison of the historically successful air injection projects with typical shale oil reservoirs in the U.S. is summarized in this paper. Some operation methods to improve air injection performance are recommended. This paper provides an avenue for us to make use of many of the favorable conditions of shale oil reservoirs for implementing air injection, or air huff ‘n’ puff injection, and the low cost of air has the potential to improve oil recovery in shale oil reservoirs. This analysis may stimulate further investigation.

  12. Advances in China's Oil Reservoir Description Technique

    Institute of Scientific and Technical Information of China (English)

    Mu Longxin; Huang Shiyan; Jia Ailin; Rong Jiashu

    1997-01-01

    @@ Oil reservoir description in China has undergone rapid development in recent years. Extensive research carried out at various oilfields and petroleum universities has resulted in the formulation of comprehensive oil reservoir description techniques and methods uniquely suited to the various development phases of China's continental facies. The new techniques have the following characteristics:

  13. Increasing Waterflooding Reservoirs in the Wilmington Oil Field through Improved Reservoir Characterization and Reservoir Management

    Energy Technology Data Exchange (ETDEWEB)

    Koerner, Roy; Clarke, Don; Walker, Scott

    1999-11-09

    The objectives of this quarterly report was to summarize the work conducted under each task during the reporting period April - June 1998 and to report all technical data and findings as specified in the ''Federal Assistance Reporting Checklist''. The main objective of this project is the transfer of technologies, methodologies, and findings developed and applied in this project to other operators of Slope and Basin Clastic Reservoirs. This project will study methods to identify sands with high remaining oil saturation and to recomplete existing wells using advanced completion technology.

  14. Production Optimization of Oil Reservoirs

    DEFF Research Database (Denmark)

    Völcker, Carsten

    with emphasis on optimal control of water ooding with the use of smartwell technology. We have implemented immiscible ow of water and oil in isothermal reservoirs with isotropic heterogenous permeability elds. We use the method of lines for solution of the partial differential equation (PDE) system that governs...... the uid ow. We discretize the the two-phase ow model spatially using the nite volume method (FVM), and we use the two point ux approximation (TPFA) and the single-point upstream (SPU) scheme for computing the uxes. We propose a new formulation of the differential equation system that arise...... as a consequence of the spatial discretization of the two-phase ow model. Upon discretization in time, the proposed equation system ensures the mass conserving property of the two-phase ow model. For the solution of the spatially discretized two-phase ow model, we develop mass conserving explicit singly diagonally...

  15. Identifying and Evaluating of Oil Reservoir

    Institute of Scientific and Technical Information of China (English)

    Yang Haixia

    2002-01-01

    The identification and evaluation of oil reservoir with logging data are one of most important ways in geologic logging services. For the last decades, with the further development of the oil & gas exploration, great advances have been achieved in techniques on the acquisition, processing and interpretative evaluation of logging data. How to identify fluid characteristics and evaluate the productivity in light oil reservoir (the crude density being between 0.74g/cm3 and 0.82g/cm3)has become one of the difficulties.With the establishment of the regional interpretation criterion of the study blocks, the optimized logging parameters that reflect the reservoir characteristics have been used to establish the chart for the interpretation of oil-water reservoir combining with well logging parameters. Then, to begin with geologic reserves of crude in single well, we establish evaluation criterion for productivity in oil reservoir with determining lower limit value of the reservoir and applying the relationship between chart parameters. The techniques are verified in production and get better effect.On the basis of the reservoir characteristics analysis of both basin A and B, We established the evaluation method of static productivity on light oil reservoir with getting quantitative evaluation parameters after quantitatively evaluating the date of core, pyrolysis chromatogram and gas chromatogram. It provides new technique 7 for new well interpretation and old well review, as well as evidence for project.design of well testing.

  16. NMPC for Oil Reservoir Production Optimization

    DEFF Research Database (Denmark)

    Völcker, Carsten; Jørgensen, John Bagterp; Thomsen, Per Grove

    2011-01-01

    In this paper, we use nonlinear model predictive control (NMPC) to maximize secondary oil recovery from an oil reservoir by controlling two-phase subsurface porous flow using adjustable down-hole control valves. The resulting optimal control problem is nonlinear and large-scale. We solve this pro......In this paper, we use nonlinear model predictive control (NMPC) to maximize secondary oil recovery from an oil reservoir by controlling two-phase subsurface porous flow using adjustable down-hole control valves. The resulting optimal control problem is nonlinear and large-scale. We solve...

  17. Post waterflood CO{sub 2} miscible flood in light oil fluvial dominated deltaic reservoirs. Second quarterly technical progress report, [January 1, 1995--March 31, 1995

    Energy Technology Data Exchange (ETDEWEB)

    NONE

    1995-07-01

    Production from the Marg Area 1 at Port Neches is averaging 392 barrels of oil per day (BOPD) for this quarter. The production drop is due to fluctuation in both GOR and BS&W on various producing well, coupled with low water injectivity in the reservoir. We were unable to inject any tangible amount of water in the reservoir since late January. Both production and injection problems are currently being evaluated to improve reservoir performance. Well Kuhn (No. 6) was stimulated with 120 MMCF of CO{sub 2}, and was placed on production in February 1, 1995. The well was shut in for an additional month after producing dry CO{sub 2} initially. The well was opened again in early April and is currently producing about 40 BOPD. CO{sub 2} injection averaged 11.3 MMCFD including 4100 MMCFD purchased from Cardox, while water injection averaged 1000 BWPD with most of the injection occurring in the month of January.

  18. Increased oil production and reserves utilizing secondary/tertiary recovery techniques on small reservoirs in the Paradox basin, Utah. Quarterly technical progress report, April 1, 1996--June 30, 1996

    Energy Technology Data Exchange (ETDEWEB)

    Allison, M.L.

    1996-08-01

    The primary objective of this project is to enhance domestic petroleum production by demonstration and technology transfer of an advanced oil recovery technology in the Paradox basin, southeastern Utah. If this project can demonstrate technical and economic feasibility, the technique can be applied to approximately 100 additional small fields in the Paradox basin alone, and result in increased recovery of 150 to 200 million barrels of oil. This project is designed to characterize five shallow-shelf carbonate reservoirs in the Pennsylvanian (Desmoinesian) Paradox Formation and choose the best candidate for a pilot demonstration project for either a waterflood or carbon dioxide (CO{sub 2}-)flood project. The field demonstration, monitoring of field performance, and associated validation activities will take place in the Paradox basin within the Navajo Nation. The results of this project will be transferred to industry and other researchers through a petroleum extension service, creation of digital databases for distribution, technical workshops and seminars, field trips, technical presentations at national and regional professional meetings, and publication in newsletters and various technical or trade journals.

  19. Reservoir characterization and enhanced oil recovery research

    Energy Technology Data Exchange (ETDEWEB)

    Lake, L.W.; Pope, G.A.; Schechter, R.S.

    1992-03-01

    The research in this annual report falls into three tasks each dealing with a different aspect of enhanced oil recovery. The first task strives to develop procedures for accurately modeling reservoirs for use as input to numerical simulation flow models. This action describes how we have used a detail characterization of an outcrop to provide insights into what features are important to fluid flow modeling. The second task deals with scaling-up and modeling chemical and solvent EOR processes. In a sense this task is the natural extension of task 1 and, in fact, one of the subtasks uses many of the same statistical procedures for insight into the effects of viscous fingering and heterogeneity. The final task involves surfactants and their interactions with carbon dioxide and reservoir minerals. This research deals primarily with phenomena observed when aqueous surfactant solutions are injected into oil reservoirs.

  20. Oil Reservoir Production Optimization using Optimal Control

    DEFF Research Database (Denmark)

    Völcker, Carsten; Jørgensen, John Bagterp; Stenby, Erling Halfdan

    2011-01-01

    Practical oil reservoir management involves solution of large-scale constrained optimal control problems. In this paper we present a numerical method for solution of large-scale constrained optimal control problems. The method is a single-shooting method that computes the gradients using the adjo......Practical oil reservoir management involves solution of large-scale constrained optimal control problems. In this paper we present a numerical method for solution of large-scale constrained optimal control problems. The method is a single-shooting method that computes the gradients using...... the adjoint method. We use an Explicit Singly Diagonally Implicit Runge-Kutta (ESDIRK) method for the integration and a quasi-Newton Sequential Quadratic Programming (SQP) algorithm for the constrained optimization. We use this algorithm in a numerical case study to optimize the production of oil from an oil...... reservoir using water ooding and smart well technology. Compared to the uncontrolled case, the optimal operation increases the Net Present Value of the oil field by 10%....

  1. Characterization of oil and gas reservoir heterogeneity

    Energy Technology Data Exchange (ETDEWEB)

    1991-01-01

    The objective of the cooperative research program is to characterize Alaskan reservoirs in terms of their reserves, physical and chemical properties, geologic configuration and structure, and the development potential. The tasks completed during this period include: (1) geologic reservoir description of Endicott Field; (2) petrographic characterization of core samples taken from selected stratigraphic horizons of the West Sak and Ugnu (Brookian) wells; (3) development of a polydispersed thermodynamic model for predicting asphaltene equilibria and asphaltene precipitation from crude oil-solvent mixtures, and (4) preliminary geologic description of the Milne Point Unit.

  2. Advanced oil recovery technologies for improved recovery from slope basin clastic reservoirs, Nash Draw Brushy Canyon Pool, Eddy County, NM. Quarterly technical progress report, October 1--December 31, 1996 (fifth quarter)

    Energy Technology Data Exchange (ETDEWEB)

    NONE

    1997-01-31

    The overall objective of this project is to demonstrate that a development program--based on advanced reservoir management methods--can significantly improve oil recovery. The plan includes developing a control area using standard reservoir management techniques while comparing its performance to an area developed using advanced reservoir management methods. Specific goals are (1) to demonstrate that an advanced development drilling and pressure maintenance program, can significantly improve oil recovery compared to existing technology applications and (2) to transfer these advanced methodologies to oil and gas producers in the Permian Basin and elsewhere throughout the US oil and gas industry. Results so far are described on geology, engineering, 3-D seismic, reservoir characterization and simulation, and technology transfer.

  3. Mathematical simulation of oil reservoir properties

    Energy Technology Data Exchange (ETDEWEB)

    Ramirez, A. [Instituto Politecnico Nacional (SEPI-ESQIE-UPALM-IPN), Unidad Profesional Zacatenco, Laboratorio de Analisis Met., Edif. ' Z' y Edif. 6 planta baja., Mexico City c.p. 07300 (Mexico)], E-mail: adalop123@mailbanamex.com; Romero, A.; Chavez, F. [Instituto Politecnico Nacional (SEPI-ESQIE-UPALM-IPN), Unidad Profesional Zacatenco, Laboratorio de Analisis Met., Edif. ' Z' y Edif. 6 planta baja., Mexico City c.p. 07300 (Mexico); Carrillo, F. [Instituto Politecnico Nacional (CICATA-IPN, Altamira Tamaulipas) (Mexico); Lopez, S. [Instituto Mexicano del Petroleo - Molecular Engineering Researcher (Mexico)

    2008-11-15

    The study and computational representation of porous media properties are very important for many industries where problems of fluid flow, percolation phenomena and liquid movement and stagnation are involved, for example, in building constructions, ore processing, chemical industries, mining, corrosion sciences, etc. Nevertheless, these kinds of processes present a noneasy behavior to be predicted and mathematical models must include statistical analysis, fractal and/or stochastic procedures to do it. This work shows the characterization of sandstone berea core samples which can be found as a porous media (PM) in natural oil reservoirs, rock formations, etc. and the development of a mathematical algorithm for simulating the anisotropic characteristics of a PM based on a stochastic distribution of some of their most important properties like porosity, permeability, pressure and saturation. Finally a stochastic process is used again to simulated the topography of an oil reservoir.

  4. Research on oil recovery mechanisms in heavy oil reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Kovscek, Anthony R.; Brigham, William E., Castanier, Louis M.

    2000-03-16

    The research described here was directed toward improved understanding of thermal and heavy-oil production mechanisms and is categorized into: (1) flow and rock properties, (2) in-situ combustion, (3) additives to improve mobility control, (4) reservoir definition, and (5) support services. The scope of activities extended over a three-year period. Significant work was accomplished in the area of flow properties of steam, water, and oil in consolidated and unconsolidated porous media, transport in fractured porous media, foam generation and flow in homogeneous and heterogeneous porous media, the effects of displacement pattern geometry and mobility ratio on oil recovery, and analytical representation of water influx.

  5. RESEARCH OIL RECOVERY MECHANISMS IN HEAVY OIL RESERVOIRS

    Energy Technology Data Exchange (ETDEWEB)

    Anthony R. Kovscek; William E. Brigham

    1999-06-01

    The United States continues to rely heavily on petroleum fossil fuels as a primary energy source, while domestic reserves dwindle. However, so-called heavy oil (10 to 20{sup o}API) remains an underutilized resource of tremendous potential. Heavy oils are much more viscous than conventional oils. As a result, they are difficult to produce with conventional recovery methods such as pressure depletion and water injection. Thermal recovery is especially important for this class of reservoirs because adding heat, usually via steam injection, generally reduces oil viscosity dramatically. This improves displacement efficiency. The research described here was directed toward improved understanding of thermal and heavy-oil production mechanisms and is categorized into: (1) flow and rock properties; (2) in-situ combustion; (3) additives to improve mobility control; (4) reservoir definition; and (5) support services. The scope of activities extended over a three-year period. Significant work was accomplished in the area of flow properties of steam, water, and oil in consolidated and unconsolidated porous media, transport in fractured porous media, foam generation and flow in homogeneous and heterogeneous porous media, the effects of displacement pattern geometry and mobility ratio on oil recovery, and analytical representation of water influx. Significant results are described.

  6. Perchlorate reduction by microbes inhabiting oil reservoirs

    Science.gov (United States)

    Liebensteiner, Martin; Stams, Alfons; Lomans, Bart

    2014-05-01

    Microbial perchlorate and chlorate reduction is a unique type of anaerobic respiration as during reduction of (per)chlorate chlorite is formed, which is then split into chloride and molecular oxygen. In recent years it was demonstrated that (per)chlorate-reducing bacteria may employ oxygenase-dependent pathways for the degradation of aromatic and aliphatic hydrocarbons. These findings suggested that (per)chlorate may be used as oxygen-releasing compound in anoxic environments that contain hydrocarbons, such as polluted soil sites and oil reservoirs. We started to study perchlorate reduction by microbes possibly inhabiting oil reservoirs. One of the organisms studied was Archaeoglobus fulgidus. This extremely thermophilic archaeon is known as a major contributor to souring in hot oil reservoirs. A. fulgidus turned out to be able to use perchlorate as terminal electron acceptor for growth with lactate (Liebensteiner et al 2013). Genome based physiological experiments indicated that A. fulgidus possesses a novel perchlorate reduction pathway. Perchlorate is first reduced to chlorite, but chlorite is not split into chloride and molecular oxygen as occurs in bacteria. Rather, chlorite reacts chemically with sulfide, forming oxidized sulfur compounds, which are reduced to sulfide in the electron transport chain by the archaeon. The dependence of perchlorate reduction on sulfur compounds could be shown. The implications of our findings as novel strategy for microbiological enhanced oil recovery and for souring mitigation are discussed. Liebensteiner MG, Pinkse MWH, Schaap PJ, Stams AJM and Lomans BP (2013) Archaeal (per)chlorate reduction at high temperature, a matter of abiotic-biotic reactions. Science 340: 85-87

  7. Bioemulsan Production by Iranian Oil Reservoirs Microorganisms

    Directory of Open Access Journals (Sweden)

    A Amiriyan, M Mazaheri Assadi, VA Saggadian, A Noohi

    2004-10-01

    Full Text Available The biosurfactants are believed to be surface active components that are shed into the surrounding medium during the growth of the microorganisms. The oil degrading microorganism Acinetobacter calcoaceticus RAG-1 produces a poly-anionic biosurfactant, hetero-polysaccharide bioemulsifier termed as emulsan which forms and stabilizes oil-water emulsions with a variety of hydrophobic substrates. In the present paper results of the possibility of biosurfactant (Emulsan production by microorganisms isolated from Iranian oil reservoirs is presented. Fourthy three gram negative and gram positive, non fermentative, rod bacilli and coccobacilli shaped baceria were isolated from the oil wells of Bibi Hakimeh, Siri, Maroon, Ilam , East Paydar and West Paydar. Out of the isolated strains, 39 bacterial strains showed beta haemolytic activity, further screening revealed the emulsifying activity and surface tension. 11 out of 43 tested emulsifiers were identified as possible biosurfactant producers and two isolates produced large surface tension reduction, indicating the high probability of biosurfactant production. Further investigation revealed that, two gram negative, oxidase negative, aerobic and coccoid rods isolates were the best producers and hence designated as IL-1, PAY-4. Whole culture broth of isolates reduced surface tension from 68 mN /m to 30 and 29.1mN/m, respectively, and were stable during exposure to high salinity (10%NaCl and elevated temperatures(120C for 15 min .

  8. Improving reservoir history matching of EM heated heavy oil reservoirs via cross-well seismic tomography

    KAUST Repository

    Katterbauer, Klemens

    2014-01-01

    Enhanced recovery methods have become significant in the industry\\'s drive to increase recovery rates from oil and gas reservoirs. For heavy oil reservoirs, the immobility of the oil at reservoir temperatures, caused by its high viscosity, limits the recovery rates and strains the economic viability of these fields. While thermal recovery methods, such as steam injection or THAI, have extensively been applied in the field, their success has so far been limited due to prohibitive heat losses and the difficulty in controlling the combustion process. Electromagnetic (EM) heating via high-frequency EM radiation has attracted attention due to its wide applicability in different environments, its efficiency, and the improved controllability of the heating process. While becoming a promising technology for heavy oil recovery, its effect on overall reservoir production and fluid displacements are poorly understood. Reservoir history matching has become a vital tool for the oil & gas industry to increase recovery rates. Limited research has been undertaken so far to capture the nonlinear reservoir dynamics and significantly varying flow rates for thermally heated heavy oil reservoir that may notably change production rates and render conventional history matching frameworks more challenging. We present a new history matching framework for EM heated heavy oil reservoirs incorporating cross-well seismic imaging. Interfacing an EM heating solver to a reservoir simulator via Andrade’s equation, we couple the system to an ensemble Kalman filter based history matching framework incorporating a cross-well seismic survey module. With increasing power levels and heating applied to the heavy oil reservoirs, reservoir dynamics change considerably and may lead to widely differing production forecasts and increased uncertainty. We have shown that the incorporation of seismic observations into the EnKF framework can significantly enhance reservoir simulations, decrease forecasting

  9. Expanding solvent SAGD in heavy oil reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Govind, P.A. [Society of Petroleum Engineers, Canadian Section, Calgary, AB (Canada)]|[ConocoPhillips Canada Resources Corp., Calgary, AB (Canada); Das, S.; Wheeler, T.J. [Society of Petroleum Engineers, Richardson, TX (United States)]|[ConocoPhillips Co., Houston, TX (United States); Srinivasan, S. [Society of Petroleum Engineers, Richardson, TX (United States)]|[Texas Univ., Austin, TX (United States)

    2008-10-15

    Steam assisted gravity drainage (SAGD) projects have proven effective for the recovery of oil and bitumen. Expanding solvent (ES) SAGD pilot projects have also demonstrated positive results of improved performance. This paper presented the results of a simulation study that investigated several important factors of the ES-SAGD process, including solvent types; concentration; operating pressure; and injection strategy. The objectives of the study were to examine the effectiveness of the ES-SAGD process in terms of production acceleration and energy requirements; to optimize solvent selection; to understand the effect of dilation in unconsolidated oil sands and the directional impact on reservoir parameters and oil production rate in ES-SAGD; and to understand the impact of operating conditions such as pressure, solvent concentration, circulation preheating period and the role of conduction heating and grid size in this process. The advantages of ES-SAGD over SAGD were also outlined. The paper presented results of sensitivity studies that were conducted on these four factors. Conclusions and recommendations for operating strategy were also offered. It was concluded that dilation is an important factor for SAGD performance at high operating pressure. 8 refs., 15 figs.

  10. Seismic monitoring of heavy oil reservoirs: Rock physics and finite element modelling

    Science.gov (United States)

    Theune, Ulrich

    In the past decades, remote monitoring of subsurface processes has attracted increasing attention in geophysics. With repeated geophysical surveys one attempts to detect changes in the physical properties in the underground without directly accessing the earth. This technique has been proven to be very valuable for monitoring enhanced oil recovery programs. This thesis presents an modelling approach for the feasibility analysis for monitoring of a thermal enhanced oil recovery technique applied to heavy oil reservoirs in the Western Canadian Sedimentary Basin. In order to produce heavy oil from shallow reservoirs thermal oil recovery techniques such as the Steam Assisted Gravity Drainage (SAGD) are often employed. As these techniques are expensive and technically challenging, early detection of operational problems is without doubt of great value. However, the feasibility of geophysical monitoring depends on many factors such as the changes in the rock physical properties of the target reservoir. In order to access the feasibility of seismic monitoring for heavy oil reservoirs, a fluid-substitutional rock physical study has been carried out to simulate the steam injection. The second modelling approach is based on a modified finite element algorithm to simulate the propagation of elastic waves in the earth, which has been developed independently in the framework of this thesis. The work summarized in this thesis shows a possibility to access the feasibility of seismic monitoring for heavy oil reservoirs through an extensive rock-physical study. Seismic monitoring is a useful tool in reservoir management decision process. However, the work reported here suggests that seismic monitoring of SAGD processes in the heavy oil reservoirs of the Western Canadian Sedimentary Basin is only feasible in shallow, unconsolidated deposits. For deeper, but otherwise geological similar reservoirs, the SAGD does not create a sufficient change in the rock physical properties to be

  11. USE OF POLYMERS TO RECOVER VISCOUS OIL FROM UNCONVENTIONAL RESERVOIRS

    Energy Technology Data Exchange (ETDEWEB)

    Randall Seright

    2011-09-30

    This final technical progress report summarizes work performed the project, 'Use of Polymers to Recover Viscous Oil from Unconventional Reservoirs.' The objective of this three-year research project was to develop methods using water soluble polymers to recover viscous oil from unconventional reservoirs (i.e., on Alaska's North Slope). The project had three technical tasks. First, limits were re-examined and redefined for where polymer flooding technology can be applied with respect to unfavorable displacements. Second, we tested existing and new polymers for effective polymer flooding of viscous oil, and we tested newly proposed mechanisms for oil displacement by polymer solutions. Third, we examined novel methods of using polymer gels to improve sweep efficiency during recovery of unconventional viscous oil. This report details work performed during the project. First, using fractional flow calculations, we examined the potential of polymer flooding for recovering viscous oils when the polymer is able to reduce the residual oil saturation to a value less than that of a waterflood. Second, we extensively investigated the rheology in porous media for a new hydrophobic associative polymer. Third, using simulation and analytical studies, we compared oil recovery efficiency for polymer flooding versus in-depth profile modification (i.e., 'Bright Water') as a function of (1) permeability contrast, (2) relative zone thickness, (3) oil viscosity, (4) polymer solution viscosity, (5) polymer or blocking-agent bank size, and (6) relative costs for polymer versus blocking agent. Fourth, we experimentally established how much polymer flooding can reduce the residual oil saturation in an oil-wet core that is saturated with viscous North Slope crude. Finally, an experimental study compared mechanical degradation of an associative polymer with that of a partially hydrolyzed polyacrylamide. Detailed results from the first two years of the project may be

  12. An electrochemical approach to oil reservoir souring

    Energy Technology Data Exchange (ETDEWEB)

    Marsland, S.D.; Dawe, R.A.; Kelsall, G.H. (Imperial Coll., London (GB). Dept. of Mineral Resources Engineering)

    1990-07-01

    The objective of this work was to establish the feasibility of using an Ag{sub 2}S/Ag ring electrode of a rotating ring-disc electrode system as a linear amperometric sensor for the local H{sub 2}S concentration generated by the combined chemical and electrochemical decomposition of a pyrrhotite (FeS{sub 1+x}) disc electrode. This enabled a more detailed investigation of the non-oxidative dissolution of 'FeS'. The results indicate that, provided iron sulphides are present in an oil reservoir, the decomposition of iron sulphides due to operator-imposed changes in the aqueous environment is a probable source of H{sub 2}S. (author).

  13. Design of a lube oil reservoir by using flow calculations

    Energy Technology Data Exchange (ETDEWEB)

    Rinkinen, J.; Alfthan, A. [Institute of Hydraulics and Automation IHA, Tampere University of Technology, Tampere (Finland)] Suominen, J. [Institute of Energy and Process Engineering, Tampere University of Technology, Tampere (Finland); Airaksinen, A.; Antila, K. [R and D Engineer Safematic Oy, Muurame (Finland)

    1997-12-31

    The volume of usual oil reservoir for lubrication oil systems is designed by the traditional rule of thumb so that the total oil volume is theoretically changed in every 30 minutes by rated pumping capacity. This is commonly used settling time for air, water and particles to separate by gravity from the oil returning of the bearings. This leads to rather big volumes of lube oil reservoirs, which are sometimes difficult to situate in different applications. In this presentation traditionally sized lube oil reservoir (8 m{sup 3}) is modelled in rectangular coordinates and laminar oil flow is calculated by using FLUENT software that is based on finite difference method. The results of calculation are velocity and temperature fields inside the reservoir. The velocity field is used to visualize different particle paths through the reservoir. Particles that are studied by the model are air bubbles and water droplets. The interest of the study has been to define the size of the air bubbles that are released and the size of the water droplets that are separated in the reservoir. The velocity field is also used to calculate the modelled circulating time of the oil volume which is then compared with the theoretical circulating time that is obtained from the rated pump flow. These results have been used for designing a new lube oil reservoir. This reservoir has also been modelled and optimized by the aid of flow calculations. The best shape of the designed reservoir is constructed in real size for empirical measurements. Some results of the oil flow measurements are shown. (orig.) 7 refs.

  14. Profiles of Reservoir Properties of Oil-Bearing Plays for Selected Petroleum Provinces in the United States

    Science.gov (United States)

    Freeman, P.A.; Attanasi, E.D.

    2015-11-05

    Profiles of reservoir properties of oil-bearing plays for selected petroleum provinces in the United States were developed to characterize the database to be used for a potential assessment by the U.S. Geological Survey (USGS) of oil that would be technically recoverable by the application of enhanced oil recovery methods using injection of carbon dioxide (CO2-EOR). The USGS assessment methodology may require reservoir-level data for the purposes of screening conventional oil reservoirs and projecting CO2-EOR performance in terms of the incremental recoverable oil. The information used in this report is based on reservoir properties from the “Significant Oil and Gas Fields of the United States Database” prepared by Nehring Associates, Inc. (2012). As described by Nehring Associates, Inc., the database “covers all producing provinces (basins) in the United States except the Appalachian Basin and the Cincinnati Arch.”

  15. Advanced oil recovery technologies for improved recovery from slope basin clastic reservoirs, Nash Draw Brushy Canyon Pool, Eddy County, NM. Second annual technical progress report, October 1, 1996--September 30, 1997

    Energy Technology Data Exchange (ETDEWEB)

    NONE

    1998-09-01

    The Nash Draw Brushy Canyon Pool in Eddy County, New Mexico is a field demonstration in the US Department of Energy Class III Program. Advanced reservoir characterization techniques are being used at the Nash Draw project to develop reservoir management strategies for optimizing oil recovery from this Delaware reservoir. Analysis, interpretation, and integration of recently acquired geological, geophysical, and engineering data revealed that the initial reservoir description was too simplistic to capture the critical features of this complex formation. As a result of the analysis, a proposed pilot area was reconsidered. Comparison of seismic data and engineering data have shown evidence of discontinuities in the area surrounding the proposed injector. Analysis of the 3-D seismic has shown that wells in the proposed pilot are in an area of poor quality amplitude development. The implication is that since amplitude attenuation is a function of porosity, then this is not the best area to be attempting a pilot pressure maintenance project. Because the original pilot area appears to be compartmentalized, the lateral continuity between the pilot wells could be reduced. The 3-D seismic interpretation indicates other areas may be better suited for the initial pilot area. Therefore, the current focus has shifted more to targeted drilling, and the pilot injection will be considered in a more continuous area of the NDP in the future. Results of reservoir simulation studies indicate that pressure maintenance should be started early when reservoir pressure is still high.

  16. Geological and Geochemical Studies of Heavy Oil Reservoirs in China

    Institute of Scientific and Technical Information of China (English)

    胡见义; 徐树宝; 等

    1989-01-01

    Thickened heavy oils in China are genetically characteristic of continenta .As to their physico-chemical properties,these oils are very high in viscosity and low in sulphur and trace element con-tents.In the group constituents,the concentrations of non-hydrocarbons and asphaltene are very high but those of saturated hydrocarbons and aromatics are very low.The gas chromatograms of alkanes show that these heavy oils have high abundances of iso-alkanes and cyclic hydrocarbons.In all the steroids and terpenoids ,bicyclic sesquiterpenoids,tricyclic diterpenoids,re-arranged steranes and gammacerane are strongly bildegradation-resistent.The formation of heavy oil reservoirs is controlled mainly by late basin ascendance,biodegradation,flushing by meteoric water and oxidation in the oil-bearing formations.Ac-cording to their formation mechanisms,heavy oil reservoirs can be classified as four categories:weathering and denudation,marginal oxidation,secondary migration and thickening of bottom water .Spacially,heavy thick oil reservoirs are distributed regularly:they usually show some paragenetic relationships with normal oil reservoirs.Heavy oil reservoirs often occur in structural highs or in overlying younger strata.Their burial depth is about 200m.Horizontally,most of them are distributed on the margins of basins or depressions.

  17. Increasing Waterflood Reserves in the Wilmington Oil Field Through Reservoir Characterization and Reservoir Management

    Energy Technology Data Exchange (ETDEWEB)

    Chris Phillips; Dan Moos; Don Clarke; John Nguyen; Kwasi Tagbor; Roy Koerner; Scott Walker

    1997-04-10

    This project is intended to increase recoverable waterflood reserves in slope and basin reservoirs through improved reservoir characterization and reservoir management. The particular application of this project is in portions of Fault Blocks IV and V of the Wilmington Oil Field, in Long Beach, California, but the approach is widely applicable in slope and basin reservoirs. Transferring technology so that it can be applied in other sections of the Wilmington Field and by operators in other slope and basin reservoirs is a primary component of the project.

  18. Crude-oil biodegradation via methanogenesis in subsurface petroleum reservoirs.

    Science.gov (United States)

    Jones, D M; Head, I M; Gray, N D; Adams, J J; Rowan, A K; Aitken, C M; Bennett, B; Huang, H; Brown, A; Bowler, B F J; Oldenburg, T; Erdmann, M; Larter, S R

    2008-01-10

    Biodegradation of crude oil in subsurface petroleum reservoirs has adversely affected the majority of the world's oil, making recovery and refining of that oil more costly. The prevalent occurrence of biodegradation in shallow subsurface petroleum reservoirs has been attributed to aerobic bacterial hydrocarbon degradation stimulated by surface recharge of oxygen-bearing meteoric waters. This hypothesis is empirically supported by the likelihood of encountering biodegraded oils at higher levels of degradation in reservoirs near the surface. More recent findings, however, suggest that anaerobic degradation processes dominate subsurface sedimentary environments, despite slow reaction kinetics and uncertainty as to the actual degradation pathways occurring in oil reservoirs. Here we use laboratory experiments in microcosms monitoring the hydrocarbon composition of degraded oils and generated gases, together with the carbon isotopic compositions of gas and oil samples taken at wellheads and a Rayleigh isotope fractionation box model, to elucidate the probable mechanisms of hydrocarbon degradation in reservoirs. We find that crude-oil hydrocarbon degradation under methanogenic conditions in the laboratory mimics the characteristic sequential removal of compound classes seen in reservoir-degraded petroleum. The initial preferential removal of n-alkanes generates close to stoichiometric amounts of methane, principally by hydrogenotrophic methanogenesis. Our data imply a common methanogenic biodegradation mechanism in subsurface degraded oil reservoirs, resulting in consistent patterns of hydrocarbon alteration, and the common association of dry gas with severely degraded oils observed worldwide. Energy recovery from oilfields in the form of methane, based on accelerating natural methanogenic biodegradation, may offer a route to economic production of difficult-to-recover energy from oilfields.

  19. Simulation of CO2-Distribution in Fractured Oil Reservoir

    OpenAIRE

    Furuvik, Nora; Halvorsen, Britt

    2015-01-01

    Deep geologic injections and storage of Carbon dioxide (CO2) for enhanced oil recovery (EOR) are an upcoming combination due to the potential for increased oil production from depleted oilfields at the same time reducing the carbon footprint from industrial sources. CO2-EOR refers to a technique for injection of supercritical-dense CO2 into an oil reservoir. Remaining oil, not producible by primary and secondary techniques, has been successfully produced using EOR with CO2 since early 1970??....

  20. A Sand Control System for Light Oil Reservoir

    Institute of Scientific and Technical Information of China (English)

    Xiang Yuzhang

    1996-01-01

    @@ Over 30-year water flooding in light oil sandstone reservoirs with loose argillaceous cement in Karamay oilfield results in severe sand production, varying from well to well with the different date of well completion.

  1. Technical Breakthrough for Fracturing Gas Reservoir

    Institute of Scientific and Technical Information of China (English)

    Gao Dakang

    1996-01-01

    @@ Huamei-Halliburton Petroleum Technical Service Co., Ltd. is the joint venture company established by CNPC and HALLIBURTON Companies. This company was approved by MOFERT and registered at SAFIAC on April 1, 1994 in Beijing.The scope of business is to provide well completion service, cementing service, fracturing service, acidizing service and supplies as well as consulting, contracting, and evaluation services to the hydrocarbon exploration and production industry operation.

  2. Heavy oil reservoirs recoverable by thermal technology. Annual report

    Energy Technology Data Exchange (ETDEWEB)

    Kujawa, P.

    1981-02-01

    The purpose of this study was to compile data on reservoirs that contain heavy oil in the 8 to 25/sup 0/ API gravity range, contain at least ten million barrels of oil currently in place, and are non-carbonate in lithology. The reservoirs within these constraints were then analyzed in light of applicable recovery technology, either steam-drive or in situ combustion, and then ranked hierarchically as candidate reservoirs. The study is presented in three volumes. Volume I presents the project background and approach, the screening analysis, ranking criteria, and listing of candidate reservoirs. The economic and environmental aspects of heavy oil recovery are included in appendices to this volume. This study provides an extensive basis for heavy oil development, but should be extended to include carbonate reservoirs and tar sands. It is imperative to look at heavy oil reservoirs and projects on an individual basis; it was discovered that operators, and industrial and government analysts will lump heavy oil reservoirs as poor producers, however, it was found that upon detailed analysis, a large number, so categorized, were producing very well. A study also should be conducted on abandoned reservoirs. To utilize heavy oil, refiners will have to add various unit operations to their processes, such as hydrotreaters and hydrodesulfurizers and will require, in most cases, a lighter blending stock. A big problem in producing heavy oil is that of regulation; specifically, it was found that the regulatory constraints are so fluid and changing that one cannot settle on a favorable recovery and production plan with enough confidence in the regulatory requirements to commit capital to the project.

  3. Increasing Waterflood Reserves in the Wilmington Oil Field through Improved Reservoir Characterization and Reservoir Management

    Energy Technology Data Exchange (ETDEWEB)

    Clarke, D.; Koerner, R.; Moos D.; Nguyen, J.; Phillips, C.; Tagbor, K.; Walker, S.

    1999-04-05

    This project used advanced reservoir characterization tools, including the pulsed acoustic cased-hole logging tool, geologic three-dimensional (3-D) modeling software, and commercially available reservoir management software to identify sands with remaining high oil saturation following waterflood. Production from the identified high oil saturated sands was stimulated by recompleting existing production and injection wells in these sands using conventional means as well as a short radius redrill candidate.

  4. Influence of Oil Reservoir on Earthquake (IORE Theory

    Directory of Open Access Journals (Sweden)

    Mohammad Mehdi Masoumi

    2012-09-01

    Full Text Available The effect of oil reservoirs on intensity of earthquake has been discussed in this paper. The data for this research have been obtained from IRIS Earthquake Browser which has given earthquake data for South West of Iran, where there are high pressure oil fields. In this article, attempt has been made to show seismicity of oil fields that has been changing with time. Some simple simulation experiments were also performed to get a relation between mechanical vibration through some compact soil in a box and absorption of these vibrations by a water bag which was placed underneath the soil, inside the box. The results were used to explain absorption of an earthquake impact by an oil reservoir and oil reservoirs work as dampers.

  5. Heavy oil reservoirs recoverable by thermal technology. Annual report

    Energy Technology Data Exchange (ETDEWEB)

    Kujawa, P.

    1981-02-01

    This volume contains reservoir, production, and project data for target reservoirs which contain heavy oil in the 8 to 25/sup 0/ API gravity range and are susceptible to recovery by in situ combustion and steam drive. The reservoirs for steam recovery are less than 2500 feet deep to comply with state-of-the-art technology. In cases where one reservoir would be a target for in situ combustion or steam drive, that reservoir is reported in both sections. Data were collectd from three source types: hands-on (A), once-removed (B), and twice-removed (C). In all cases, data were sought depicting and characterizing individual reservoirs as opposed to data covering an entire field with more than one producing interval or reservoir. The data sources are listed at the end of each case. This volume also contains a complete listing of operators and projects, as well as a bibliography of source material.

  6. Play-level distributions of estimates of recovery factors for a miscible carbon dioxide enhanced oil recovery method used in oil reservoirs in the conterminous United States

    Science.gov (United States)

    Attanasi, E.D.; Freeman, P.A.

    2016-03-02

    In a U.S. Geological Survey (USGS) study, recovery-factor estimates were calculated by using a publicly available reservoir simulator (CO2 Prophet) to estimate how much oil might be recovered with the application of a miscible carbon dioxide (CO2) enhanced oil recovery (EOR) method to technically screened oil reservoirs located in onshore and State offshore areas in the conterminous United States. A recovery factor represents the percentage of an oil reservoir’s original oil in place estimated to be recoverable by the application of a miscible CO2-EOR method. The USGS estimates were calculated for 2,018 clastic and 1,681 carbonate candidate reservoirs in the “Significant Oil and Gas Fields of the United States Database” prepared by Nehring Associates, Inc. (2012).

  7. Play-level distributions of estimates of recovery factors for a miscible carbon dioxide enhanced oil recovery method used in oil reservoirs in the conterminous United States

    Science.gov (United States)

    Attanasi, E.D.; Freeman, P.A.

    2016-03-02

    In a U.S. Geological Survey (USGS) study, recovery-factor estimates were calculated by using a publicly available reservoir simulator (CO2 Prophet) to estimate how much oil might be recovered with the application of a miscible carbon dioxide (CO2) enhanced oil recovery (EOR) method to technically screened oil reservoirs located in onshore and State offshore areas in the conterminous United States. A recovery factor represents the percentage of an oil reservoir’s original oil in place estimated to be recoverable by the application of a miscible CO2-EOR method. The USGS estimates were calculated for 2,018 clastic and 1,681 carbonate candidate reservoirs in the “Significant Oil and Gas Fields of the United States Database” prepared by Nehring Associates, Inc. (2012).

  8. Development of Layered Treatment Technique for Multiple Heavy Oil Reservoirs

    Institute of Scientific and Technical Information of China (English)

    Hu Zhimian; Wu Dehua

    1995-01-01

    @@ In order to solve the problems that there is steam absorbing inhomogeneity in various layers of well in heavy oil reservoirs during steam injection, and upperlayers and high permeability layers repeat steam absorption, as well as middle or low permeability layers absorb little steam or no steam, we have studied and developed seperate-layer treatment techniques for huff and puff wells in recent years. By test and application,these techniques have been proved successful in increasing steam stimulated effect and recovery efficiency in the period of cyclic steam stimulations of oil wells in multilayer heavy oil reservoirs.

  9. INCREASING WATERFLOOD RESERVES IN THE WILMINGTON OIL FIELD THROUGH IMPROVED RESERVOIR CHARACTERIZATION AND RESERVOIR MANAGEMENT

    Energy Technology Data Exchange (ETDEWEB)

    Scott Walker; Chris Phillips; Roy Koerner; Don Clarke; Dan Moos; Kwasi Tagbor

    2002-02-28

    This project increased recoverable waterflood reserves in slope and basin reservoirs through improved reservoir characterization and reservoir management. The particular application of this project is in portions of Fault Blocks IV and V of the Wilmington Oil Field, in Long Beach, California, but the approach is widely applicable in slope and basin reservoirs. Transferring technology so that it can be applied in other sections of the Wilmington Field and by operators in other slope and basin reservoirs is a primary component of the project. This project used advanced reservoir characterization tools, including the pulsed acoustic cased-hole logging tool, geologic three-dimensional (3-D) modeling software, and commercially available reservoir management software to identify sands with remaining high oil saturation following waterflood. Production from the identified high oil saturated sands was stimulated by recompleting existing production and injection wells in these sands using conventional means as well as a short radius redrill candidate. Although these reservoirs have been waterflooded over 40 years, researchers have found areas of remaining oil saturation. Areas such as the top sand in the Upper Terminal Zone Fault Block V, the western fault slivers of Upper Terminal Zone Fault Block V, the bottom sands of the Tar Zone Fault Block V, and the eastern edge of Fault Block IV in both the Upper Terminal and Lower Terminal Zones all show significant remaining oil saturation. Each area of interest was uncovered emphasizing a different type of reservoir characterization technique or practice. This was not the original strategy but was necessitated by the different levels of progress in each of the project activities.

  10. Isotopic insights into microbial sulfur cycling in oil reservoirs

    Directory of Open Access Journals (Sweden)

    Christopher G Hubbard

    2014-09-01

    Full Text Available Microbial sulfate reduction in oil reservoirs (biosouring is often associated with secondary oil production where seawater containing high sulfate concentrations (~28 mM is injected into a reservoir to maintain pressure and displace oil. The sulfide generated from biosouring can cause corrosion of infrastructure, health exposure risks, and higher production costs. Isotope monitoring is a promising approach for understanding microbial sulfur cycling in reservoirs, enabling early detection of biosouring, and understanding the impact of souring. Microbial sulfate reduction is known to result in large shifts in the sulfur and oxygen isotope compositions of the residual sulfate, which can be distinguished from other processes that may be occurring in oil reservoirs, such as precipitation of sulfate and sulfide minerals. Key to the success of this method is using the appropriate isotopic fractionation factors for the conditions and processes being monitored. For a set of batch incubation experiments using a mixed microbial culture with crude oil as the electron donor, we measured a sulfur fractionation factor for sulfate reduction of -30‰. We have incorporated this result into a simplified 1D reservoir reactive transport model to highlight how isotopes can help discriminate between biotic and abiotic processes affecting sulfate and sulfide concentrations. Modeling results suggest that monitoring sulfate isotopes can provide an early indication of souring for reservoirs with reactive iron minerals that can remove the produced sulfide, especially when sulfate reduction occurs in the mixing zone between formation waters containing elevated concentrations of volatile fatty acids and injection water containing elevated sulfate. In addition, we examine the role of reservoir thermal, geochemical, hydrological, operational and microbiological conditions in determining microbial souring dynamics and hence the anticipated isotopic signatures.

  11. Interaction of oil components and clay minerals in reservoir sandstones

    Energy Technology Data Exchange (ETDEWEB)

    Changchun Pan; Linping Yu; Guoying Sheng; Jiamo Fu [Chinese Academy of Sciences, State Key Lab. of Organic Geochemistry, Wushan, Guangzhou (China); Jianhui Feng; Yuming Tian [Chinese Academy of Sciences, State Key Lab. of Organic Geochemistry, Wushan, Guangzhou (China); Zhongyuan Oil Field Co., Puyang, Henan (China); Xiaoping Luo [Zhongyuan Oil Field Co., Puyang, Henan (China)

    2005-04-15

    The free oil (first Soxhlet extract) and adsorbed oil (Soxhlet extract after the removal of minerals) obtained from the clay minerals in the <2 {mu}m size fraction as separated from eight hydrocarbon reservoir sandstone samples, and oil inclusions obtained from the grains of seven of these eight samples were studied via GC, GC-MS and elemental analyses. The free oil is dominated by saturated hydrocarbons (61.4-87.5%) with a low content of resins and asphaltenes (6.0-22.0% in total) while the adsorbed oil is dominated by resins and asphaltenes (84.8-98.5% in total) with a low content of saturated hydrocarbons (0.6-9.5%). The inclusion oil is similar to the adsorbed oil in gross composition, but contains relatively more saturated hydrocarbons (16.87-31.88%) and less resins and asphaltenes (62.30-78.01% in total) as compared to the latter. Although the amounts of both free and adsorbed oils per gram of clay minerals varies substantially, the residual organic carbon content in the clay minerals of the eight samples, after the free oil extraction, is in a narrow range between 0.537% and 1.614%. From the decrease of the percentage of the extractable to the total of this residual organic matter of the clay minerals with burial depth it can be inferred that polymerization of the adsorbed polar components occurs with the increase of the reservoir temperature. The terpane and sterane compositions indicate that the oil adsorbed onto the clay surfaces appears to be more representative of the initial oil charging the reservoir than do the oil inclusions. This phenomenon could possibly demonstrate that the first oil charge preferentially interacts with the clay minerals occurring in the pores and as coatings around the grains. Although the variation of biomarker parameters between the free and adsorbed oils could be ascribed to the compositional changes of oil charges during the filling process and/or the differential maturation behaviors of these two types of oils after oil

  12. A strategy for low cost development of incremental oil in legacy reservoirs

    Science.gov (United States)

    Attanasi, E.D.

    2016-01-01

    The precipitous decline in oil prices during 2015 has forced operators to search for ways to develop low-cost and low-risk oil reserves. This study examines strategies to low cost development of legacy reservoirs, particularly those which have already implemented a carbon dioxide enhanced oil recovery (CO2 EOR) program. Initially the study examines the occurrence and nature of the distribution of the oil resources that are targets for miscible and near-miscible CO2 EOR programs. The analysis then examines determinants of technical recovery through the analysis of representative clastic and carbonate reservoirs. The economic analysis focusses on delineating the dominant components of investment and operational costs. The concluding sections describe options to maximize the value of assets that the operator of such a legacy reservoir may have that include incremental expansion within the same producing zone and to producing zones that are laterally or stratigraphically near main producing zones. The analysis identified the CO2 recycle plant as the dominant investment cost item and purchased CO2 and liquids management as a dominant operational cost items. Strategies to utilize recycle plants for processing CO2 from multiple producing zones and multiple reservoir units can significantly reduce costs. Industrial sources for CO2 should be investigated as a possibly less costly way of meeting EOR requirements. Implementation of tapered water alternating gas injection schemes can partially mitigate increases in fluid lifting costs.

  13. Reservoir Screening Criteria for Heavy Oil Thermal Recovery in Liaohe Oilfield

    Institute of Scientific and Technical Information of China (English)

    Lin Yuqiu; Zhang Yali

    2009-01-01

    @@ Characteristics of heavy oil reservoirsin Liaohe Oilfield Liaohe Oilfield is rich in heavy oil and is the largest base of heavy oil recovery in China. Its heavy oil reservoirs have following characteristics:

  14. Post waterflood CO{sub 2} miscible flood in light oil, fluvial: Dominated deltaic reservoir. First quarterly technical progress report, Fiscal year 1994, October 1, 1993--December 31, 1993

    Energy Technology Data Exchange (ETDEWEB)

    1994-01-15

    Production from the Port Neches CO{sub 2} project was initiated on December 6, 1993 after having been shut-in since the start of CO{sub 2} injection on September 22, 1993 to allow reservoir pressure to build. Rates were established at 236 barrels of oil per day (BOPD) from two wells in the 235 acre waterflood project area, which before project initiation had produced only 80 BOPD from the entire area. These wells are flowing large amounts of fluid due to the high reservoir pressure and their oil percentages are increasing as a result of the CO{sub 2} contacting the residual oil. One well, the H. J. Kuhn No. 15-R is flowing 217 BOPD, 1139 BWPD, and 2500 MCFPD of CO{sub 2} at a flowing tubing pressure (FTP) of 890 psi. The other producing well, the H. J. Kuhn No. 33, is currently flowing 19 BOPD, 614 BWPD, and 15 MCFPD at a FTP of 400 psi. Unexpectedly high rates of CO{sub 2} production are being made from Well No. 15-R and from the W. R. Stark ``B`` No. 8. This No. 8 well produced 7 BOPD, 697 BWPD, and 15 MCFPD prior to being shut-in during September to allow for the reservoir pressure to build by injecting CO{sub 2}, but when opened on December 6, the well flowed dry CO{sub 2} at a rate of 400 MCFPD for a two day test period. More sustained production tests will be obtained after all wells are tied into the new production facility. Many difficulties occurred in the drilling of the horizontal CO{sub 2} injection well but a successful completion across 2501 of sand has finally been accomplished. A formation dip of 11--14 degrees in the area where the well was being drilled made the proposed 1500{prime} horizontal sand section too difficult to accomplish. The shale section directly above the sand caused sticking problems on two separate occasions resulting in two sidetracks of the well around stuck pipe. The well will be tied into the facility and CO{sub 2} injection into the well will begin before February 1, 1994.

  15. Microbial Enhanced Oil Recovery - Advanced Reservoir Simulation

    DEFF Research Database (Denmark)

    Nielsen, Sidsel Marie

    In this project, a generic model has been set up to include the two main mechanisms in the microbial enhanced oil recovery (MEOR) process; reduction of the interfacial tension (IFT) due to surfactant production, and microscopic fluid diversion as a part of the overall fluid diversion mechanism due......, bacterial growth, substrate consumption, and surfactant production in one dimension. The system comprises oil, water, bacteria, substrate, and surfactant. There are two flowing phases: Water and oil. We introduce the partition of surfactant between these two phases determined by a partitioning constant......, the curve levels off. Partitioning of surfactant between the oil and water phase is a novel effect in the context of microbial enhanced oil recovery. The partitioning coefficient determines the time lag before the surfactant effect can be seen. The surfactant partitioning does not change final recovery...

  16. Experiences with linear solvers for oil reservoir simulation problems

    Energy Technology Data Exchange (ETDEWEB)

    Joubert, W.; Janardhan, R. [Los Alamos National Lab., NM (United States); Biswas, D.; Carey, G.

    1996-12-31

    This talk will focus on practical experiences with iterative linear solver algorithms used in conjunction with Amoco Production Company`s Falcon oil reservoir simulation code. The goal of this study is to determine the best linear solver algorithms for these types of problems. The results of numerical experiments will be presented.

  17. Increase of heavy oil reservoir recovery using chemical injection

    Directory of Open Access Journals (Sweden)

    Mohammad Amin Alishvandi

    2016-12-01

    Full Text Available Due to thermal properties, Nano fluids may be new generation of thermal transfer fluids that would be used invarious industries. Energy carrier Nano fluids as waters, lubricants and ethylene glycol include of particles with dimensions of 100 nm as metal, metal oxid or carbon Nano tubes. Based on evaluation, with increase of viscosity of Nano fluid surfactant, absorbed dispersion materials would be increased and Nano particles dispersion and stability and thermal transfer would be developed. Using chemical injection to reservoirs, surfactant is cause of oil entrapment based on decrease of surface tension force, self generate- emulation and change of wetting. According to reservoir temperature,by Nano fluid and surfactant, thermal properties would be achieved to heat oil and decrease viscosity without any change of reservoir stone wetting.

  18. Technical and economic feasibility study of flue gas injection in an Iranian oil field

    Directory of Open Access Journals (Sweden)

    Mohammad Ali Ahmadi

    2015-09-01

    The main aim of this research is to investigate various gas injection methods (N2, CO2, produced reservoir gas, and flue gas in one of the northern Persian gulf oil fields by a numerical simulation method. Moreover, for each scenario of gas injection technical and economical considerations are took into account. Finally, an economic analysis is implemented to compare the net present value (NPV of the different gas injection scenarios in the aforementioned oil field.

  19. Modification of reservoir chemical and physical factors in steamfloods to increase heavy oil recovery

    Energy Technology Data Exchange (ETDEWEB)

    Yortsos, Y.C.

    1996-12-31

    Thermal methods, and particularly steam injection, are currently recognized as the most promising for the efficient recovery of heavy oil. Despite significant progress, however, important technical issues remain open. Specifically, still inadequate is our knowledge of the complex interaction between porous media and the various fluids of thermal recovery (steam, water, heavy oil, gases, and chemicals). While, the interplay of heat transfer and fluid flow with pore- and macro-scale heterogeneity is largely unexplored. The objectives of this contract are to continue previous work and to carry out new fundamental studies in the following areas of interest to thermal recovery: displacement and flow properties of fluids involving phase change (condensation-evaporation) in porous media; flow properties of mobility control fluids (such as foam); and the effect of reservoir heterogeneity on thermal recovery. The specific projects are motivated by and address the need to improve heavy oil recovery from typical reservoirs as well as less conventional fractured reservoirs producing from vertical or horizontal wells. During this past quarter, work continued on: the development of relative permeabilities during steam displacement; the optimization of recovery processes in heterogeneous reservoirs by using optical control methods; and in the area of chemical additives, work continued on the behavior of non-Newtonian fluid flow and on foam displacements in porous media.

  20. Modification of reservoir chemical and physical factors in steamfloods to increase heavy oil recovery

    Energy Technology Data Exchange (ETDEWEB)

    NONE

    1996-12-31

    Thermal methods, and particularly steam injection, are currently recognized as the most promising for the efficient recovery of heavy oil. Despite significant progress, however, important technical issues remain open. Specifically, still inadequate is our knowledge of the complex interaction between porous media and the various fluids of thermal recovery (steam, water, heavy oil, gases, and chemicals). While, the interplay of heat transfer and fluid flow with pore- and macro-scale heterogeneity is largely unexplored. The objectives of this contract are to continue previous work and to carry out new fundamental studies in the following areas of interest to thermal recovery: displacement and flow properties of fluids involving phase change (condensation-evaporation) in porous media; flow properties of mobility control fluids (such as foam); and the effect of reservoir heterogeneity on thermal recovery. The specific projects are motivated by and address the need to improve heavy oil recovery from typical reservoirs as well as less conventional fractured reservoirs producing from vertical or horizontal wells. During this quarter work continued on: development of relative permeabilities during steam injection; optimization of recovery processes in heterogeneous reservoirs by using optimal control methods; and behavior of non-Newtonian fluid flow and on foam displacements in porous media.

  1. Heavy oil reservoirs recoverable by thermal technology. Annual report

    Energy Technology Data Exchange (ETDEWEB)

    Kujawa, P.

    1981-02-01

    This volume contains reservoir, production, and project data for target reservoirs thermally recoverable by steam drive which are equal to or greater than 2500 feet deep and contain heavy oil in the 8 to 25/sup 0/ API gravity range. Data were collected from three source types: hands-on (A), once-removed (B), and twice-removed (C). In all cases, data were sought depicting and characterizing individual reservoirs as opposed to data covering an entire field with more than one producing interval or reservoir. The data sources are listed at the end of each case. This volume also contains a complete listing of operators and projects, as well as a bibliography of source material.

  2. Proceedings of the world heavy oil congress : 2009 business and technical conference

    Energy Technology Data Exchange (ETDEWEB)

    NONE

    2009-07-01

    This international conference provided a forum for collaborative examination of issues facing the heavy oil industry. The complete heavy oil value chain was examined in order to define short-term and long-term challenges and supply solutions. Leading experts were linked with the latest technologies for the unconventional oil industry. Participants from Venezuela, Canada, China, Brazil, France, Italy, Mexico, Netherlands, Norway, Russia, the United Kingdom and the United States presented case studies and field results, along with numerical simulation and laboratory investigations. The topics ranged from innovative oil sands processing and upgrading technologies; reservoir exploitation strategies; produced water treatment; sand control; reservoir monitoring; cementing design; geomechanics; and recovery processes such as cold heavy oil production with sand (CHOPS), chemical flooding, steam assisted gravity drainage, in-situ combustion and toe-to-heel air injection (THAI). The technical conference featured sessions on drilling and completions; fuels and upgrading; thermal recovery operations; field development; enhanced oil recovery and emerging recovery technologies; reservoir characterization; oil and water treatment; processing and transportation; production facilities; upgrading technology; and production technology. All 100 papers from the technical sessions have been catalogued separately for inclusion in this database. refs., tabs., figs.

  3. On the economics of improved oil recovery. The optimal recovery factor from oil and gas reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Nystad, A.N.

    1985-06-01

    We investigate an oil company's optimal depletion of oil and gas reservoirs, taking into account that the depletion policy itself influences the recoverable reserves (recovery factor) and that we have up-front capital costs. The depletion policy is defined by the amount of investment in production and in injection projects. 6 refs., 8 figs., 2 tabs.

  4. A CUDA based parallel multi-phase oil reservoir simulator

    Science.gov (United States)

    Zaza, Ayham; Awotunde, Abeeb A.; Fairag, Faisal A.; Al-Mouhamed, Mayez A.

    2016-09-01

    Forward Reservoir Simulation (FRS) is a challenging process that models fluid flow and mass transfer in porous media to draw conclusions about the behavior of certain flow variables and well responses. Besides the operational cost associated with matrix assembly, FRS repeatedly solves huge and computationally expensive sparse, ill-conditioned and unsymmetrical linear system. Moreover, as the computation for practical reservoir dimensions lasts for long times, speeding up the process by taking advantage of parallel platforms is indispensable. By considering the state of art advances in massively parallel computing and the accompanying parallel architecture, this work aims primarily at developing a CUDA-based parallel simulator for oil reservoir. In addition to the initial reported 33 times speed gain compared to the serial version, running experiments showed that BiCGSTAB is a stable and fast solver which could be incorporated in such simulations instead of the more expensive, storage demanding and usually utilized GMRES.

  5. Real Time Oil Reservoir Evaluation Using Nanotechnology

    Science.gov (United States)

    Li, Jing (Inventor); Meyyappan, Meyya (Inventor)

    2011-01-01

    A method and system for evaluating status and response of a mineral-producing field (e.g., oil and/or gas) by monitoring selected chemical and physical properties in or adjacent to a wellsite headspace. Nanotechnology sensors and other sensors are provided for one or more underground (fluid) mineral-producing wellsites to determine presence/absence of each of two or more target molecules in the fluid, relative humidity, temperature and/or fluid pressure adjacent to the wellsite and flow direction and flow velocity for the fluid. A nanosensor measures an electrical parameter value and estimates a corresponding environmental parameter value, such as water content or hydrocarbon content. The system is small enough to be located down-hole in each mineral-producing horizon for the wellsite.

  6. IMPROVING CO2 EFFICIENCY FOR RECOVERING OIL IN HETEROGENEOUS RESERVOIRS

    Energy Technology Data Exchange (ETDEWEB)

    Reid B. Grigg

    2003-10-31

    The second annual report of ''Improving CO{sub 2} Efficiency for Recovery Oil in Heterogeneous Reservoirs'' presents results of laboratory studies with related analytical models for improved oil recovery. All studies have been undertaken with the intention to optimize utilization and extend the practice of CO{sub 2} flooding to a wider range of reservoirs. Many items presented in this report are applicable to other interest areas: e.g. gas injection and production, greenhouse gas sequestration, chemical flooding, reservoir damage, etc. Major areas of studies include reduction of CO{sub 2} mobility to improve conformance, determining and understanding injectivity changes in particular injectivity loses, and modeling process mechanisms determined in the first two areas. Interfacial tension (IFT) between a high-pressure, high-temperature CO{sub 2} and brine/surfactant and foam stability are used to assess and screen surfactant systems. In this work the effects of salinity, pressure, temperature, surfactant concentration, and the presence of oil on IFT and CO{sub 2} foam stability were determined on the surfactant (CD1045{trademark}). Temperature, pressure, and surfactant concentration effected both IFT and foam stability while oil destabilized the foam, but did not destroy it. Calcium lignosulfonate (CLS) can be used as a sacrificial and an enhancing agent. This work indicates that on Berea sandstone CLS concentration, brine salinity, and temperature are dominant affects on both adsorption and desorption and that adsorption is not totally reversible. Additionally, CLS adsorption was tested on five minerals common to oil reservoirs; it was found that CLS concentration, salinity, temperature, and mineral type had significant effects on adsorption. The adsorption density from most to least was: bentonite > kaolinite > dolomite > calcite > silica. This work demonstrates the extent of dissolution and precipitation from co-injection of CO{sub 2} and

  7. New boundary conditions for oil reservoirs with fracture

    Science.gov (United States)

    Andriyanova, Elena; Astafev, Vladimir

    2017-06-01

    Based on the fact that most of oil fields are on the late stage of field development, it becomes necessary to produce hard-to-extract oil, which can be obtained only by use of enhance oil recovery methods. For example many low permeable or shale formations can be developed only with application of massive hydraulic fracturing technique. In addition, modern geophysical researches show that mostly oil bearing formations are complicated with tectonic faults of different shape and permeability. These discontinuities exert essential influence on the field development process and on the well performance. For the modeling of fluid flow in the reservoir with some area of different permeability, we should determine the boundary conditions. In this article for the first time the boundary conditions for the problem of fluid filtration in the reservoir with some discontinuity are considered. This discontinuity represents thin but long area, which can be hydraulic fracturing of tectonic fault. The obtained boundary condition equations allow us to take into account pressure difference above and below the section and different values of permeability.

  8. Conversion of Crude Oil to Methane by a Microbial Consortium Enriched From Oil Reservoir Production Waters

    Directory of Open Access Journals (Sweden)

    Carolina eBerdugo-Clavijo

    2014-05-01

    Full Text Available The methanogenic biodegradation of crude oil is an important process occurring in petroleum reservoirs and other oil-containing environments such as contaminated aquifers. In this process, syntrophic bacteria degrade hydrocarbon substrates to products such as acetate, and/or H2 and CO2 that are then used by methanogens to produce methane in a thermodynamically dependent manner. We enriched a methanogenic crude oil-degrading consortium from production waters sampled from a low temperature heavy oil reservoir. Alkylsuccinates indicative of fumarate addition to C5 and C6 n-alkanes were identified in the culture (above levels found in controls, corresponding to the detection of an alkyl succinate synthase gene (assA in the culture. In addition, the enrichment culture was tested for its ability to produce methane from residual oil in a sandstone-packed column system simulating a mature field. Methane production rates of up 5.8 μmol CH4/g of oil/day were measured in the column system. Amounts of produced methane were in relatively good agreement with hydrocarbon loss showing depletion of more than 50% of saturate and aromatic hydrocarbons. Microbial community analysis revealed that the enrichment culture was dominated by members of the genus Smithella, Methanosaeta, and Methanoculleus. However, a shift in microbial community occurred following incubation of the enrichment in the sandstone columns. Here, Methanobacterium sp. were most abundant, as were bacterial members of the genus Pseudomonas and other known biofilm forming organisms. Our findings show that microorganisms enriched from petroleum reservoir waters can bioconvert crude oil components to methane both planktonically and in sandstone-packed columns as test systems. Further, the results suggest that different organisms may contribute to oil biodegradation within different phases (e.g., planktonic versus sessile within a subsurface crude oil reservoir.

  9. Identifying Oil, Oil-water and Water Reservoirs by the Method of Grey Poly-category

    Institute of Scientific and Technical Information of China (English)

    Lu Huangsheng

    1994-01-01

    @@ Grey Poly-category is a branch of Grey System belonging to System Theory. According to the System Theory, a fully determinable figure is called White Figure, a fully undeterminable figure is called Black Figure, and the figure between them is called Grey Figure. On the same principle, a fully determinable system,a fully undeterminable, and a partial determinable and partial undeterminable system are called White, Black and Grey System respectively. For the oil, oil-water and water reservoirs, each type of reservoirs has its different log response values. These values are grey figures, not a fixed figure, and then, the system made of the figures is a Grey System.

  10. Electro-magnetic heating in viscous oil reservoir

    Energy Technology Data Exchange (ETDEWEB)

    Das, S. [Society of Petroleum Engineers, Richardson, TX (United States)]|[Marathon Oil Corp., Houston, TX (United States)

    2008-10-15

    This paper discussed electromagnetic (EM) heating techniques for primary and secondary enhanced oil recovery (EOR) processes. Ohmic, induction, and formation resistive heating techniques were discussed. Issues related to energy equivalence and hardware requirements were reviewed. Challenges related to heat losses in vertical wellbores, well integrity, and galvanic corrosion were also outlined. A pair of 1500 foot horizontal wells in a heavy oil reservoir were then modelled in order to optimize EM recovery processes. DC current was used in a base case water flood run. Electrical conductivities were measured. The model was converted to a homogenous model in order to study injector and producer electrodes. The study showed that reservoir resistance was low, and most of the heating took place near the electrode area where electric lines diverged or converged. Results of the study suggested that EM heating in formations is not as efficient as steam-based processes. Accurate simulations of EM heating processes within reservoirs are difficult to obtain, as the amounts of estimated heat input are sensitive to grid refinement. It was concluded that hot spots in the EM electrodes have also caused failures in other field applications and studies. 11 refs., 12 figs.

  11. Increased Oil Production and Reserves Utilizing Secondary/Terriary Recovery Techniques on Small Reservoirs in the Paradox Basin, Utah

    Energy Technology Data Exchange (ETDEWEB)

    David E. Eby; Thomas C. Chidsey, Jr.

    1998-04-08

    The primary objective of this project is to enhance domestic petroleum production by demonstration and technology transfer of an advanced oil recovery technology in the Paradox basin, southeastern Utah. If this project can demonstrate technical and economic feasibility, the technique can be applied to about 100 additional small fields in the Paradox basin alone, and result in increased recovery of 150 to 200 million barrels of oil. This project is designed to characterize five shallow-shelf carbonate reservoirs in the Pennsylvanian (Desmoinesian) Paradox Formation and choose the best candidate for a pilot demonstration project for either a waterflood or carbon dioxide-(CO -) 2 flood project. The field demonstration, monitoring of field performance, and associated validation activities will take place in the Paradox basin within the Navajo Nation. Two activities continued this quarter as part of the geological and reservoir characterization of productive carbonate buildups in the Paradox basin: (1) diagenetic characterization of project field reservoirs, and (2) technology transfer.

  12. Spatial analysis of oil reservoirs using DFA of geophysical data

    Directory of Open Access Journals (Sweden)

    R. A. Ribeiro

    2014-04-01

    Full Text Available We employ Detrended Fluctuation Analysis (DFA technique to investigate spatial properties of an oil reservoir. This reservoir is situated at Bacia de Namorados, RJ, Brazil. The data corresponds to well logs of the following geophysical quantities: sonic, gamma ray, density, porosity and electrical resistivity, measured in 56 wells. We tested the hypothesis of constructing spatial models using data from fluctuation analysis over well logs. To verify this hypothesis we compare the matrix of distances among well logs with the differences among DFA-exponents of geophysical quantities using spatial correlation function and Mantel test. Our data analysis suggests that sonic profile is a good candidate to represent spatial structures. Then, we apply the clustering analysis technique to the sonic profile to identify these spatial patterns. In addition we use the Mantel test to search for correlation among DFA-exponents of geophysical quantities.

  13. Detection of brine plumes in an oil reservoir using the geoelectric method

    Science.gov (United States)

    Bongiovanni, María Victoria; Osella, Ana; de la Vega, Matías; Tichno, Adrián

    2013-08-01

    During water injection in a reservoir at the secondary recovery phase, oil is replaced by salt water, producing different saturation zones in the formation containing this reservoir. This process could be optimized if the direction of the fluids is monitored. Since there are large contrasts in the electric conductivity between salt water and oil, geoelectrical methods could provide a water saturation map at any given moment of the production. The case we study here corresponds to a rather shallow reservoir (between 500 and 600 m in depth). As the wells are in production, electrodes for borehole measurements cannot be introduced. Hence, our objectives are to determine the possibilities of detecting the channelling direction of saline water between injection and producing wells, and applying the method of placing electrodes on the surface or even burying them, but at depths corresponding to shallow layers. We design an electrical model of the reservoir and then numerically simulate the geoelectrical response in order to determine the conditions under which the anomaly, i.e. the accumulation of brine in a reduced area, can be detected. We find that the channelling of the brine can be detected for the reservoir studied here if the electrodes are placed at 180 m depth. The Wenner configuration using 16 electrodes provides the best resolution. Therefore, monitoring the voltage at a number of electrodes embedded at rather shallow depths (from a technical-logistic point of view) could give information about the direction of the saline channelling even if a quantitative image of the subsoil cannot be obtained due to the reduced number of electrodes used in the study.

  14. Nurturing the geology-reservoir engineering team: Vital for efficient oil and gas recovery

    Energy Technology Data Exchange (ETDEWEB)

    Sessions, K.P.; Lehman, D.H. (Exxon Co., Houston, TX (USA))

    1990-05-01

    Of an estimated 482 billion bbl (76.6 Gm{sup 3}) of in-place oil discovered in the US, 158 billion (25.1 Gm{sup 3}) can be recovered with existing technology and economic conditions. The cost-effective recovery through infill drilling and enhanced oil recovery methods to recover any portion of the remaining 323 billion bbl (51.4 Gm3) will require a thorough understanding of reservoirs and the close cooperation of production geologists and reservoir engineers. This paper presents the concept of increased interaction between geologists and reservoir engineers through multifunctional teams and cross-training between the disciplines. A discussion of several factors supporting this concept is covered, including educational background, technical manpower trends, employee development, and job satisfaction. There are several ways from an organizational standpoint to achieve this cross-training, with or without a formal change in job assignment. This paper outlines three approaches, including case histories where each of the approaches has been implemented and the resulting benefits.

  15. Potential evaluation of CO2 storage and enhanced oil recovery of tight oil reservoir in the Ordos Basin, China.

    Science.gov (United States)

    Tian, Xiaofeng; Cheng, Linsong; Cao, Renyi; Zhang, Miaoyi; Guo, Qiang; Wang, Yimin; Zhang, Jian; Cui, Yu

    2015-07-01

    Carbon -di-oxide (CO2) is regarded as the most important greenhouse gas to accelerate climate change and ocean acidification. The Chinese government is seeking methods to reduce anthropogenic CO2 gas emission. CO2 capture and geological storage is one of the main methods. In addition, injecting CO2 is also an effective method to replenish formation energy in developing tight oil reservoirs. However, exiting methods to estimate CO2 storage capacity are all based on the material balance theory. This was absolutely correct for normal reservoirs. However, as natural fractures widely exist in tight oil reservoirs and majority of them are vertical ones, tight oil reservoirs are not close. Therefore, material balance theory is not adaptive. In the present study, a new method to calculate CO2 storage capacity is presented. The CO2 effective storage capacity, in this new method, consisted of free CO2, CO2 dissolved in oil and CO2 dissolved in water. Case studies of tight oil reservoir from Ordos Basin was conducted and it was found that due to far lower viscosity of CO2 and larger solubility in oil, CO2 could flow in tight oil reservoirs more easily. As a result, injecting CO2 in tight oil reservoirs could obviously enhance sweep efficiency by 24.5% and oil recovery efficiency by 7.5%. CO2 effective storage capacity of Chang 7 tight oil reservoir in Longdong area was 1.88 x 10(7) t. The Chang 7 tight oil reservoir in Ordos Basin was estimated to be 6.38 x 10(11) t. As tight oil reservoirs were widely distributed in Songliao Basin, Sichuan Basin and so on, geological storage capacity of CO2 in China is potential.

  16. Evaluation of Reservoir Wettability and its Effect on Oil Recovery.

    Energy Technology Data Exchange (ETDEWEB)

    Buckley, J.S.

    1998-01-15

    We report on the first year of the project, `Evaluation of Reservoir Wettability and its Effect on Oil Recovery.` The objectives of this five-year project are (1) to achieve improved understanding of the surface and interfacial properties of crude oils and their interactions with mineral surfaces, (2) to apply the results of surface studies to improve predictions of oil production from laboratory measurements, and (3) to use the results of this research to recommend ways to improve oil recovery by waterflooding. During the first year of this project we have focused on understanding the interactions between crude oils and mineral surfaces that establish wetting in porous media. As background, mixed-wetting and our current understanding of the influence of stable and unstable brine films are reviewed. The components that are likely to adsorb and alter wetting are divided into two groups: those containing polar heteroatoms, especially organic acids and bases; and the asphaltenes, large molecules that aggregate in solution and precipitate upon addition of n-pentane and similar agents. Finally, the test procedures used to assess the extent of wetting alteration-tests of adhesion and adsorption on smooth surfaces and spontaneous imbibition into porous media are introduced. In Part 1, we report on studies aimed at characterizing both the acid/base and asphaltene components. Standard acid and base number procedures were modified and 22 crude oil samples were tested. Our approach to characterizing the asphaltenes is to focus on their solvent environment. We quantify solvent properties by refractive index measurements and report the onset of asphaltene precipitation at ambient conditions for nine oil samples. Four distinct categories of interaction mechanisms have been identified that can be demonstrated to occur when crude oils contact solid surfaces: polar interactions can occur on dry surfaces, surface precipitation is important if the oil is a poor solvent for its

  17. The research and practice of boosting oil production by duplicated horizontal wells in thick super heavy oil reservoir

    Energy Technology Data Exchange (ETDEWEB)

    Peiwu, Li; Yang Jing, Wangping; Ping, Yuan [Exploration and Development Research Institute of Liaohe Oilfield Company, PetroChina, P.R.China , 124010 (China)

    2011-07-01

    In the oil industry, the extraction of heavy oil and super heavy oil from reservoirs is difficult and production decline and sand production are some of the numerous challenges it faces. The aim of this paper is to show how secondary development can address these issues. A preliminary study was conducted and then a plan of secondary development was applied to M6 Block which is a massive extra-ultra heavy oil reservoir. The plan included 154 wells with 30 new horizontal wells. Results proved SAGD to be a good technique for high oil recovery results with improved production from M6 Block. After the implementation of the secondary development, oil recovery improved by 36.3%. This technique also solved the sand production problem. This study showed that secondary development can be a solution to obtain a better performance from heavy oil reservoirs and provides guidance to other similar reservoir.

  18. Feasibility of Gas Drive in Fang-48 Fault Block Oil Reservoir

    Institute of Scientific and Technical Information of China (English)

    Cui Lining; Hou Jirui; Yin Xiangwen

    2007-01-01

    The Fang-48 fault block oil reservoir is an extremely low permeability reservoir, and it is difficult to produce such a reservoir by waterflooding. Laboratory analysis of reservoir oil shows that the minimum miscibility pressure for CO2 drive in Fang-48 fault block oil reservoir is 29 MPa, lower than the formation fracture pressure of 34 MPa, so the displacement mechanism is miscible drive. The threshold pressure gradient for gas injection is less than that for waterflooding, and the recovery by gas drive is higher than waterflooding. Furthermore, the threshold pressure gradient for carbon dioxide injection is smaller than that for hydrocarbon gas, and the oil recovery by carbon dioxide drive is higher than that by hydrocarbon gas displacement, so carbon dioxide drive is recommended for the development of the Fang-48 fault block oil reservoir.

  19. SIMULATION AND OPTIMIZATION OF THE HYDRAULIC FRACTURING OPERATION IN A HEAVY OIL RESERVOIR IN SOUTHERN IRAN

    Directory of Open Access Journals (Sweden)

    REZA MASOOMI

    2017-01-01

    Full Text Available Extraction of oil from some Iranian reservoirs due to high viscosity of their oil or reducing the formation permeability due to asphaltene precipitation or other problems is not satisfactory. Hydraulic fracturing method increases production in the viscous oil reservoirs that the production rate is low. So this is very important for some Iranian reservoirs that contain these characteristics. In this study, hydraulic fracturing method has been compositionally simulated in a heavy oil reservoir in southern Iran. In this study, the parameters of the fracture half length, the propagation direction of the cracks and the depth of fracturing have been considered in this oil reservoir. The aim of this study is to find the best scenario which has the highest recovery factor in this oil reservoir. For this purpose the parameters of the length, propagation direction and depth of fracturing have been optimized in this reservoir. Through this study the cumulative oil production has been evaluated with the compositional simulation for the next 10 years in this reservoir. Also at the end of this paper, increasing the final production of this oil reservoir caused by optimized hydraulic fracturing has been evaluated.

  20. Molecular correlation of free oil and inclusion oil of reservoir rocks in the Junggar Basin, China

    Energy Technology Data Exchange (ETDEWEB)

    Changchun Pan; Jiamo Fu; Guoying Sheng [Chinese Academy of Sciences, Guangdong (China). State Key Laboratory of Organic Geochemistry; Jianqiang Yang [Research Institute of Exploration and Development, Xinjiang (China)

    2003-03-01

    Free oils and inclusion oils (oil-bearing fluid inclusions) of 12 samples collected from the sandstone reservoir formations in the central, eastern and northern areas of the Junggar Basin, northwest China, were analyzed by GC and GC-MS. Analytical results indicate very similar biomarker distributions within each of the free oils and their associated inclusion oils in the two samples collected, respectively, from the northwestern and eastern border of the Junggar Basin. The free oil and inclusion oil of sample MD1-1, collected from the northwestern border, correlate well with the Permian source rock of the Fencheng Formation, while those of sample DN1-1 from the eastern border correlate with the Permian source rock of the Pingdiquan Formation. In contrast, in the central area, the free and inclusion oils vary significantly in most cases, which suggests variations of sources for oil charges during the filling process. These data, and the correlation between the free and inclusion oils, are consistent with the field and seismic data, which show that in areas where samples MD1-1 and DN1-1 are located, only one available source rock exists, while in the central area, multiple source rocks are present. (author)

  1. Laboratory investigation of novel oil recovery method for carbonate reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Yousef, A.A.; Al-Saleh, S.; Al-Kaabi, A.; Al-Jawfi, M. [Saudi Aramco, Riyadh (Saudi Arabia)

    2010-07-01

    This paper described a core flooding laboratory study conducted using composite rock samples from a carbonate reservoir. The aim of the study was to investigate the impact of salinity and ionic composition on oil, brine and rock interactions. Experimental parameters and procedures were designed to replicate reservoir conditions and current field injection practices. Results of the study demonstrated that alterations in the salinity and ionic composition of injected water can have a significant impact on the wettability of the rock surface. Nuclear magnetic resonance (NMR) studies confirmed that injecting different salinity slugs of seawater in carbonate core samples can cause a significant alteration in the surface charges of the rock, and lead to increased interactions with water molecules. The constant reduction of pressure drop across the composite cores with the injection of different diluted versions of water also provided proof of brine, oil and rock alterations. Results of the study indicated that the driving mechanism for waterflooding recovery processes is wettability alteration, which can be triggered by alterations in carbonate rock surface charges, and improvements in the connectivity between rock pore systems that coexist in carbonate rock samples. 41 refs., 8 tabs., 16 figs.

  2. Characteristics of remaining oil viscosity in water-and polymer-flooding reservoirs in Daqing Oilfield

    Institute of Scientific and Technical Information of China (English)

    2010-01-01

    The experimental analysis of 21 crude oil samples shows a good correlation between high molecular-weight hydrocarbon components (C 40+) and viscosity.Forty-four remaining oil samples extracted from oil sands of oilfield development coring wells were analyzed by high-temperature gas chromatography (HTGC),for the relative abundance of C 21-,C 21-C 40 and C 40+ hydrocarbons.The relationship between viscosity of crude oil and C 40+ (%) hydrocarbons abundance is used to expect the viscosity of remaining oil.The mobility characteristics of remaining oil,the properties of remaining oil,and the next displacement methods in reservoirs either water-flooded or polymer-flooded are studied with rock permeability,oil saturation of coring wells,etc.The experimental results show that the hydrocarbons composition,viscosity,and mobility of remaining oil from both polymer-flooding and water-flooding reservoirs are heterogeneous,especially the former.Relative abundance of C 21- and C 21-C 40 hydrocarbons in polymer-flooding reservoirs is lower than that of water-flooding,but with more abundance of C 40+ hydrocarbons.It is then suggested that polymer flooding must have driven more C 40- hydrocarbons out of reservoir,which resulted in relatively enriched C 40+,more viscous oils,and poorer mobility.Remaining oil in water-flooding reservoirs is dominated by moderate viscosity oil with some low viscosity oil,while polymer-flooding mainly contained moderate viscosity oil with some high viscosity oil.In each oilfield and reservoir,displacement methods of remaining oil,viscosity,and concentration by polymer-solution can be adjusted by current viscosity of remaining oil and mobility ratio in a favorable range.A new basis and methods are suggested for the further development and enhanced oil recovery of remaining oil.

  3. Integrating gravimetric and interferometric synthetic aperture radar data for enhancing reservoir history matching of carbonate gas and volatile oil reservoirs

    KAUST Repository

    Katterbauer, Klemens

    2016-08-25

    Reservoir history matching is assuming a critical role in understanding reservoir characteristics, tracking water fronts, and forecasting production. While production data have been incorporated for matching reservoir production levels and estimating critical reservoir parameters, the sparse spatial nature of this dataset limits the efficiency of the history matching process. Recently, gravimetry techniques have significantly advanced to the point of providing measurement accuracy in the microgal range and consequently can be used for the tracking of gas displacement caused by water influx. While gravity measurements provide information on subsurface density changes, i.e., the composition of the reservoir, these data do only yield marginal information about temporal displacements of oil and inflowing water. We propose to complement gravimetric data with interferometric synthetic aperture radar surface deformation data to exploit the strong pressure deformation relationship for enhancing fluid flow direction forecasts. We have developed an ensemble Kalman-filter-based history matching framework for gas, gas condensate, and volatile oil reservoirs, which synergizes time-lapse gravity and interferometric synthetic aperture radar data for improved reservoir management and reservoir forecasts. Based on a dual state-parameter estimation algorithm separating the estimation of static reservoir parameters from the dynamic reservoir parameters, our numerical experiments demonstrate that history matching gravity measurements allow monitoring the density changes caused by oil-gas phase transition and water influx to determine the saturation levels, whereas the interferometric synthetic aperture radar measurements help to improve the forecasts of hydrocarbon production and water displacement directions. The reservoir estimates resulting from the dual filtering scheme are on average 20%-40% better than those from the joint estimation scheme, but require about a 30% increase in

  4. Increasing Heavy Oil Reserves in the Wilmington Oil Field Through Advanced Reservoir Characterization and Thermal Production Technologies, Class III

    Energy Technology Data Exchange (ETDEWEB)

    City of Long Beach; Tidelands Oil Production Company; University of Southern California; David K. Davies and Associates

    2002-09-30

    The objective of this project was to increase the recoverable heavy oil reserves within sections of the Wilmington Oil Field, near Long Beach, California through the testing and application of advanced reservoir characterization and thermal production technologies. It was hoped that the successful application of these technologies would result in their implementation throughout the Wilmington Field and, through technology transfer, will be extended to increase the recoverable oil reserves in other slope and basin clastic (SBC) reservoirs.

  5. Linear vs. nonlinear porosity estimation of NMR oil reservoir data

    Directory of Open Access Journals (Sweden)

    Mohsen Abdou Abou Mandour

    2010-09-01

    Full Text Available Nuclear magnetic resonance is widely used to assess oil reservoir properties especially those that can not be evaluated using conventional techniques. In this regard, porosity determination and the related estimation of the oil present play a very important role in assessing the eco1nomic value of the oil wells. Nuclear Magnetic Resonance data is usually fit to the sum of decaying exponentials. The resulting distribution; i.e. T2 distribution; is directly related to porosity determination. In this work, three reservoir core samples (Tight Sandstone and two Carbonate samples were analyzed. Linear Least Square method (LLS and non-linear least square fitting using Levenberg-Marquardt method were used to calculate the T2 distribution and the resulting incremental porosity. Parametric analysis for the two methods was performed to evaluate the impact of number of exponentials, and effect of the regularization parameter (? on the smoothing of the solution. Effect of the type of solution on porosity determination was carried out. It was found that 12 exponentials is the optimum number of exponentials for both the linear and nonlinear solutions. In the mean time, it was shown that the linear solution begins to be smooth at α = 0.5 which corresponds to the standard industrial value for the regularization parameter. The order of magnitude of time needed for the linear solution is in the range of few minutes while it is in the range of few hours for the nonlinear solution. Regardless of the fact that small differences exist between the linear and nonlinear solutions, these small values make an appreciable difference in porosity. The nonlinear solution predicts 12% less porosity for the tight sandstone sample and 4.5 % and 13 % more porosity in the two carbonate samples respectively.

  6. Lessons learned from IOR steamflooding in a bitumen-light oil heterogeneous reservoir

    NARCIS (Netherlands)

    Al Mudhafar, W.J.M.; Hosseini Nasab, S.M.

    2015-01-01

    The Steamflooding was considered in this research to extract the discontinuous bitumen layers that are located at the oil-water contact for the heterogeneous light oil sandstone reservoir of South Rumaila Field. The reservoir heterogeneity and the bitumen layers impede water aquifer approaching into

  7. Reservoir characterization of hydraulic flow units in heavy-oil reservoirs at Petromonagas, eastern Orinoco belt, Venezuela

    Energy Technology Data Exchange (ETDEWEB)

    Merletti, G.D.; Hewitt, N.; Barrios, F.; Vega, V.; Carias, J. [BP Exploration, Houston, TX (United States); Bueno, J.C.; Lopez, L. [PDVSA Petroleos de Venezuela SA, Caracas (Venezuela, Bolivarian Republic of)

    2009-07-01

    An accurate integrated reservoir description is necessary in extra-heavy oil prospects where pore throat geometries are the ultimate control on hydrocarbon primary recovery. The key element in producing accurate oil reservoir descriptions and improving productivity is to determine relationships between core-derived pore-throat parameters and log-derived macroscopic attributes. This paper described the use of the flow zone indicator technique (FZI) to identify hydraulic units within depositional facies. It focused on a petrophysical analysis aimed at improving the description of reservoir sandstones containing heavy or extra heavy oil in the eastern Orinoco belt in Venezuela. The Petromonagas license area contains large volumes of crude oil in-place with an API gravity of 8. Production comes primarily from the lowermost stratigraphic unit of the Oficina Formation, the Miocene Morichal Member. Facies analysis has revealed various depositional settings and core measurements depict a wide range in reservoir quality within specific depositional facies. The reservoir is divided into 4 different rock qualities and 5 associated non-reservoir rocks. The use of the FZI technique provides a better understanding of the relationship between petrophysical rock types and depositional facies. 4 refs., 4 tabs., 8 figs.

  8. Developing Sand-Gravel Viscous Oil Reservoir in Le'an Oilfield

    Institute of Scientific and Technical Information of China (English)

    He Shenghou

    1995-01-01

    @@ The main oil-bearing series of Le'an Oilfield, Shengli Oil Province, which was discovered in 1970s are sand-gravel bodies on the base of the Eocene Guantao Formation. It is difficult to produce crude oil with conventional method from this thin reservoir due to its complicated lithology, extra viscous oil and edge water. We have conducted integrated study on geology, reservoir engineering, thermal production technology, horizontal drilling technology and comprehensive study. By five years' field experiment and operation, a prominent effect of development and good economic benefit have been achieved and an example has been set up for thermal recovery from extra viscous reservoir.

  9. Influence of nanomirelal phases on development processes of oil reservoirs in Volga-Ural region

    Science.gov (United States)

    Izotov, Victor; Sitdikova, Lyalya

    2010-05-01

    The optimisation of oil-field development by enhancing oil recovery is the most important target in further improvement of oil production processes. The resulting economic benefits often exceed those from discoveries of new fields, especially in hard-to-reach regions. Despite the wide use of enhanced oil recovery methods, their efficiency is in many cases not as high as expected. For instance, in terrigenous reservoirs of the Volga-Ural region oil recovery rarely exceeds 0.4, and in carbonate reservoirs with the complex structure, variability and high oil viscosity it can be as low as 0.15-0.20. In natural bitumen fields, the recovery factor is even lower. Analysis of the conducted EOR optimisation operations indicates that EOR methods mainly aim to change the hydrodynamic conditions in the reservoir under development or the physicochemical properties of oil, - for instance, to decrease its viscosity or to change its lyophilic behaviour. The impact of EOR methods on the reservoir's mineral component remains largely unstudied. It is generally believed that the mineral component of the reservoir, its matrix, is inert and remains unaffected by EOR methods. However, the analysis of oil-field development processes and the available studies allow the conclusion that natural hydrocarbon reservoirs are sensitive to any impact on both the near-wellbore zone and the whole reservoir. The authors' research in the reservoir's mineral phase dynamics has permitted the conclusion that the reservoir's fluid phases (including hydrocarbons) and the reservoir itself form a lithogeochemical system that remains in unstable equilibrium. Any external impact, such as the reservoir penetration or the use of EOR methods, disturbs this equilibrium and changes the filtration characteristics of the reservoir, the fluid chemistry and the reaction of the reservoir's mineral component to the impact. In order to characterise the processes in the reservoir in the course of its development, the

  10. Calculation of shocks in oil reservoir modeling and porous flow

    Energy Technology Data Exchange (ETDEWEB)

    Concus, P.

    1982-03-01

    For many enhanced recovery methods propagating fronts arise that may be steep or discontinuous. One example is the waterflooding of a petroleum reservoir, in which there is forced out residual oil that remains after outflow by decompression has declined. In this paper high-resolution numerical methods to solve porous flow problems having propagating discontinuities are discussed. The random choice method can track solution discontinuities sharply and accurately for one space dimension. The first phase of this study adapted this method for solving the Buckley-Leverett equation for immiscible displacement in one space dimension. Extensions to more than one space dimension for the random choice method were carried out subsequently by means of fractional splitting. Because inaccuracies could be introduced for some problems at dicontinuity fronts propagating obliquely to the splitting directions, efforts are currently being directed at investigating alternatives for multidimensional cases.

  11. Characterization of oil and gas reservoirs and recovery technology deployment on Texas State Lands

    Energy Technology Data Exchange (ETDEWEB)

    Tyler, R.; Major, R.P.; Holtz, M.H. [Univ. of Texas, Austin, TX (United States)] [and others

    1997-08-01

    Texas State Lands oil and gas resources are estimated at 1.6 BSTB of remaining mobile oil, 2.1 BSTB, or residual oil, and nearly 10 Tcf of remaining gas. An integrated, detailed geologic and engineering characterization of Texas State Lands has created quantitative descriptions of the oil and gas reservoirs, resulting in delineation of untapped, bypassed compartments and zones of remaining oil and gas. On Texas State Lands, the knowledge gained from such interpretative, quantitative reservoir descriptions has been the basis for designing optimized recovery strategies, including well deepening, recompletions, workovers, targeted infill drilling, injection profile modification, and waterflood optimization. The State of Texas Advanced Resource Recovery program is currently evaluating oil and gas fields along the Gulf Coast (South Copano Bay and Umbrella Point fields) and in the Permian Basin (Keystone East, Ozona, Geraldine Ford and Ford West fields). The program is grounded in advanced reservoir characterization techniques that define the residence of unrecovered oil and gas remaining in select State Land reservoirs. Integral to the program is collaboration with operators in order to deploy advanced reservoir exploitation and management plans. These plans are made on the basis of a thorough understanding of internal reservoir architecture and its controls on remaining oil and gas distribution. Continued accurate, detailed Texas State Lands reservoir description and characterization will ensure deployment of the most current and economically viable recovery technologies and strategies available.

  12. On the feasibility of inducing oil mobilization in existing reservoirs via wellbore harmonic fluid action

    KAUST Repository

    Jeong, Chanseok

    2011-03-01

    Although vibration-based mobilization of oil remaining in mature reservoirs is a promising low-cost method of enhanced oil recovery (EOR), research on its applicability at the reservoir scale is still at an early stage. In this paper, we use simplified models to study the potential for oil mobilization in homogeneous and fractured reservoirs, when harmonically oscillating fluids are injected/produced within a well. To this end, we investigate first whether waves, induced by fluid pressure oscillations at the well site, and propagating radially and away from the source in a homogeneous reservoir, could lead to oil droplet mobilization in the reservoir pore-space. We discuss both the fluid pore-pressure wave and the matrix elastic wave cases, as potential agents for increasing oil mobility. We then discuss the more realistic case of a fractured reservoir, where we study the fluid pore-pressure wave motion, while taking into account the leakage effect on the fracture wall. Numerical results show that, in homogeneous reservoirs, the rock-stress wave is a better energy-delivery agent than the fluid pore-pressure wave. However, neither the rock-stress wave nor the pore-pressure wave is likely to result in any significant residual oil mobilization at the reservoir scale. On the other hand, enhanced oil production from the fractured reservoir\\'s matrix zone, induced by cross-flow vibrations, appears to be feasible. In the fractured reservoir, the fluid pore-pressure wave is only weakly attenuated through the fractures, and thus could induce fluid exchange between the rock formation and the fracture space. The vibration-induced cross-flow is likely to improve the imbibition of water into the matrix zone and the expulsion of oil from it. © 2011 Elsevier B.V.

  13. Environmental Drivers of Differences in Microbial Community Structure in Crude Oil Reservoirs across a Methanogenic Gradient

    OpenAIRE

    Shelton, Jenna L.; Akob, Denise M.; Jennifer C McIntosh; Noah Fierer; Spear, John R.; Warwick, Peter D.; McCray, John E.

    2016-01-01

    Stimulating in situ microbial communities in oil reservoirs to produce natural gas is a potentially viable strategy for recovering additional fossil fuel resources following traditional recovery operations. Little is known about what geochemical parameters drive microbial population dynamics in biodegraded, methanogenic oil reservoirs. We investigated if microbial community structure was significantly impacted by the extent of crude oil biodegradation, extent of biogenic methane production, a...

  14. Western Shallow Oil Zone, Elk Hills Field, Kern County, California: General reservoir study, Appendix 4, Fourth Wilhelm sand

    Energy Technology Data Exchange (ETDEWEB)

    Carey, K.B.

    1987-09-01

    The general Reservoir Study of the Western Shallow Oil Zone was prepared by Evans, Carey and Crozier as Task Assignment 009 with the United States Department of Energy. This study, Appendix IV, addresses the Fourth Wilhelm Sand and its sub units and pools. Basic pressure, production and assorted technical data were provided by the US Department of Energy staff at Elk Hills. Basic pressure production and assorted technical data were provided by the US Department of Energy staff at Elk Hills. These data were accepted as furnished with no attempt being made by Evans, Carey and Crozier for independent verification. This study has identified the petrophysical properties and the past productive performance of the reservoir. Primary reserves have been determined and general means of enhancing future recovery have been suggested. It is hoped that this volume can now additionally serve as a take off point for exploitation engineers to develop specific programs toward the end. 12 figs., 9 tabs.

  15. Increasing Heavy Oil Reserves in the Wilmington Oil Field Through Advanced Reservoir Characterization and Thermal Production Technologies, Class III

    Energy Technology Data Exchange (ETDEWEB)

    City of Long Beach; Tidelands Oil Production Company; University of Southern California; David K. Davies and Associates

    2002-09-30

    The objective of this project was to increase the recoverable heavy oil reserves within sections of the Wilmington Oil Field, near Long Beach, California through the testing and application of advanced reservoir characterization and thermal production technologies. The successful application of these technologies would result in expanding their implementation throughout the Wilmington Field and, through technology transfer, to other slope and basin clastic (SBC) reservoirs.

  16. INCREASING HEAVY OIL RESERVES IN THE WILMINGTON OIL FIELD THROUGH ADVANCED RESERVOIR CHARACTERIZATION AND THERMAL PRODUCTION TECHNOLOGIES

    Energy Technology Data Exchange (ETDEWEB)

    Scott Hara

    2001-06-27

    The objective of this project is to increase the recoverable heavy oil reserves within sections of the Wilmington Oil Field, near Long Beach, California through the testing and application of advanced reservoir characterization and thermal production technologies. The successful application of these technologies will result in expanding their implementation throughout the Wilmington Field and, through technology transfer, to other slope and basin clastic (SBC) reservoirs. The existing steamflood in the Tar zone of Fault Block II-A (Tar II-A) has been relatively inefficient because of several producibility problems which are common in SBC reservoirs: inadequate characterization of the heterogeneous turbidite sands, high permeability thief zones, low gravity oil and non-uniform distribution of the remaining oil. This has resulted in poor sweep efficiency, high steam-oil ratios, and early steam breakthrough. Operational problems related to steam breakthrough, high reservoir pressure, and unconsolidated sands have caused premature well and downhole equipment failures. In aggregate, these reservoir and operational constraints have resulted in increased operating costs and decreased recoverable reserves. A suite of advanced reservoir characterization and thermal production technologies are being applied during the project to improve oil recovery and reduce operating costs.

  17. Sulfate-Reducing Prokaryotes from North Sea Oil reservoirs; organisms, distribution and origin

    Energy Technology Data Exchange (ETDEWEB)

    Beeder, Janiche

    1996-12-31

    During oil production in the North Sea, anaerobic seawater is pumped in which stimulates the growth of sulphate-reducing prokaryotes that produce hydrogen sulphide. This sulphide causes major health hazards, economical and operational problems. As told in this thesis, several strains of sulphate reducers have been isolated from North Sea oil field waters. Antibodies have been produced against these strains and used to investigate the distribution of sulphate reducers in a North Sea oil reservoir. The result showed a high diversity among sulphate reducers, with different strains belonging to different parts of the reservoir. Some of these strains have been further characterized. The physiological and phylogenetic characterization showed that strain 7324 was an archaean. Strain A8444 was a bacterium, representing a new species of a new genus. A benzoate degrading sulphate reducing bacterium was isolated from injection water, and later the same strain was detected in produced water. This is the first field observations indicating that sulphate reducers are able to penetrate an oil reservoir. It was found that the oil reservoir contains a diverse population of thermophilic sulphate reducers able to grow on carbon sources in the oil reservoir, and to live and grow in this extreme environment of high temperature and pressure. The mesophilic sulphate reducers are established in the injection water system and in the reservoir near the injection well during oil production. The thermophilic sulphate reducers are able to grow in the reservoir prior to, as well as during production. It appears that the oil reservoir is a natural habitat for thermophilic sulphate reducers and that they have been present in the reservoir long before production started. 322 refs., 9 figs., 11 tabs.

  18. Theoretical Analysis of the Mechanism of Fracture Network Propagation with Stimulated Reservoir Volume (SRV Fracturing in Tight Oil Reservoirs.

    Directory of Open Access Journals (Sweden)

    Yuliang Su

    Full Text Available Stimulated reservoir volume (SRV fracturing in tight oil reservoirs often induces complex fracture-network growth, which has a fundamentally different formation mechanism from traditional planar bi-winged fracturing. To reveal the mechanism of fracture network propagation, this paper employs a modified displacement discontinuity method (DDM, mechanical mechanism analysis and initiation and propagation criteria for the theoretical model of fracture network propagation and its derivation. A reasonable solution of the theoretical model for a tight oil reservoir is obtained and verified by a numerical discrete method. Through theoretical calculation and computer programming, the variation rules of formation stress fields, hydraulic fracture propagation patterns (FPP and branch fracture propagation angles and pressures are analyzed. The results show that during the process of fracture propagation, the initial orientation of the principal stress deflects, and the stress fields at the fracture tips change dramatically in the region surrounding the fracture. Whether the ideal fracture network can be produced depends on the geological conditions and on the engineering treatments. This study has both theoretical significance and practical application value by contributing to a better understanding of fracture network propagation mechanisms in unconventional oil/gas reservoirs and to the improvement of the science and design efficiency of reservoir fracturing.

  19. Theoretical Analysis of the Mechanism of Fracture Network Propagation with Stimulated Reservoir Volume (SRV) Fracturing in Tight Oil Reservoirs.

    Science.gov (United States)

    Su, Yuliang; Ren, Long; Meng, Fankun; Xu, Chen; Wang, Wendong

    2015-01-01

    Stimulated reservoir volume (SRV) fracturing in tight oil reservoirs often induces complex fracture-network growth, which has a fundamentally different formation mechanism from traditional planar bi-winged fracturing. To reveal the mechanism of fracture network propagation, this paper employs a modified displacement discontinuity method (DDM), mechanical mechanism analysis and initiation and propagation criteria for the theoretical model of fracture network propagation and its derivation. A reasonable solution of the theoretical model for a tight oil reservoir is obtained and verified by a numerical discrete method. Through theoretical calculation and computer programming, the variation rules of formation stress fields, hydraulic fracture propagation patterns (FPP) and branch fracture propagation angles and pressures are analyzed. The results show that during the process of fracture propagation, the initial orientation of the principal stress deflects, and the stress fields at the fracture tips change dramatically in the region surrounding the fracture. Whether the ideal fracture network can be produced depends on the geological conditions and on the engineering treatments. This study has both theoretical significance and practical application value by contributing to a better understanding of fracture network propagation mechanisms in unconventional oil/gas reservoirs and to the improvement of the science and design efficiency of reservoir fracturing.

  20. INCREASED OIL PRODUCTION AND RESERVES UTILIZING SECONDARY/TERTIARY RECOVERY TECHNIQUES ON SMALL RESERVOIRS IN THE PARADOX BASIN, UTAH

    Energy Technology Data Exchange (ETDEWEB)

    Thomas C. Chidsey, Jr.

    2002-11-01

    exhibits a characteristic set of reservoir properties obtained from outcrop analogs, cores, and geophysical logs. The Anasazi and Runway fields were selected for geostatistical modeling and reservoir compositional simulations. Models and simulations incorporated variations in carbonate lithotypes, porosity, and permeability to accurately predict reservoir responses. History matches tied previous production and reservoir pressure histories so that future reservoir performances could be confidently predicted. The simulation studies showed that despite most of the production being from the mound-core intervals, there were no corresponding decreases in the oil in place in these intervals. This behavior indicates gravity drainage of oil from the supra-mound intervals into the lower mound-core intervals from which the producing wells' major share of production arises. The key to increasing ultimate recovery from these fields (and similar fields in the basin) is to design either waterflood or CO{sub 2}-miscible flood projects capable of forcing oil from high-storage-capacity but low-recovery supra-mound units into the high-recovery mound-core units. Simulation of Anasazi field shows that a CO{sub 2} flood is technically superior to a waterflood and economically feasible. For Anasazi field, an optimized CO{sub 2} flood is predicted to recover a total 4.21 million barrels (0.67 million m3) of oil representing in excess of 89 percent of the original oil in place. For Runway field, the best CO{sub 2} flood is predicted to recover a total of 2.4 million barrels (0.38 million m3) of oil representing 71 percent of the original oil in place. If the CO{sub 2} flood performed as predicted, it is a financially robust process for increasing the reserves in the many small fields in the Paradox Basin. The results can be applied to other fields in the Rocky Mountain region, the Michigan and Illinois Basins, and the Midcontinent.

  1. Preconditioning methods to improve SAGD performance in heavy oil and bitumen reservoirs with variable oil phase viscosity

    Energy Technology Data Exchange (ETDEWEB)

    Gates, I.D. [Gushor Inc., Calgary, AB (Canada)]|[Calgary Univ., AB (Canada). Dept. of Chemical and Petroleum Engineering; Larter, S.R.; Adams, J.J.; Snowdon, L.; Jiang, C. [Gushor Inc., Calgary, AB (Canada)]|[Calgary Univ., Calgary, AB (Canada). Dept. of Geoscience

    2008-10-15

    This study investigated preconditioning techniques for altering reservoir fluid properties prior to steam assisted gravity drainage (SAGD) recovery processes. Viscosity-reducing agents were distributed in mobile reservoir water. Simulations were conducted to demonstrate the method's ability to modify oil viscosity prior to steam injection. The study simulated the action of water soluble organic solvents that preferentially partitioned in the oil phase. The solvent was injected with water into the reservoir in a slow waterflood that did not displace oil from the near wellbore region. A reservoir simulation model was used to investigate the technique. Shu's correlation was used to establish a viscosity correlation for the bitumen and solvent mixtures. Solvent injection was modelled by converting the oil phase viscosity through time. Over the first 2 years, oil rates of the preconditioned case were double that of the non-preconditioned case study. However, after 11 years, the preconditioned case's rates declined below rates observed in the non-preconditioned case. The model demonstrated that oil viscosity distributions were significantly altered using the preconditioners. The majority of the most viscous oil surrounding the production well was significantly reduced. It was concluded that accelerated steam chamber growth provided faster access to lower viscosity materials at the top of the reservoir. 12 refs., 9 figs.

  2. INCREASING HEAVY OIL RESERVES IN THE WILMINGTON OIL FIELD THROUGH ADVANCED RESERVOIR CHARACTERIZATION AND THERMAL PRODUCTION TECHNOLOGIES

    Energy Technology Data Exchange (ETDEWEB)

    Unknown

    2001-08-08

    The objective of this project is to increase the recoverable heavy oil reserves within sections of the Wilmington Oil Field, near Long Beach, California, through the testing and application of advanced reservoir characterization and thermal production technologies. The hope is that successful application of these technologies will result in their implementation throughout the Wilmington Field and, through technology transfer, will be extended to increase the recoverable oil reserves in other slope and basin clastic (SBC) reservoirs. The existing steamflood in the Tar zone of Fault Block II-A (Tar II-A) has been relatively inefficient because of several producibility problems which are common in SBC reservoirs: inadequate characterization of the heterogeneous turbidite sands, high permeability thief zones, low gravity oil and non-uniform distribution of the remaining oil. This has resulted in poor sweep efficiency, high steam-oil ratios, and early steam breakthrough. Operational problems related to steam breakthrough, high reservoir pressure, and unconsolidated sands have caused premature well and downhole equipment failures. In aggregate, these reservoir and operational constraints have resulted in increased operating costs and decreased recoverable reserves. A suite of advanced reservoir characterization and thermal production technologies are being applied during the project to improve oil recovery and reduce operating costs, including: (1) Development of three-dimensional (3-D) deterministic and stochastic reservoir simulation models--thermal or otherwise--to aid in reservoir management of the steamflood and post-steamflood phases and subsequent development work. (2) Development of computerized 3-D visualizations of the geologic and reservoir simulation models to aid reservoir surveillance and operations. (3) Perform detailed studies of the geochemical interactions between the steam and the formation rock and fluids. (4) Testing and proposed application of a

  3. Gradient-based methods for production optimization of oil reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Suwartadi, Eka

    2012-07-01

    Production optimization for water flooding in the secondary phase of oil recovery is the main topic in this thesis. The emphasis has been on numerical optimization algorithms, tested on case examples using simple hypothetical oil reservoirs. Gradientbased optimization, which utilizes adjoint-based gradient computation, is used to solve the optimization problems. The first contribution of this thesis is to address output constraint problems. These kinds of constraints are natural in production optimization. Limiting total water production and water cut at producer wells are examples of such constraints. To maintain the feasibility of an optimization solution, a Lagrangian barrier method is proposed to handle the output constraints. This method incorporates the output constraints into the objective function, thus avoiding additional computations for the constraints gradient (Jacobian) which may be detrimental to the efficiency of the adjoint method. The second contribution is the study of the use of second-order adjoint-gradient information for production optimization. In order to speedup convergence rate in the optimization, one usually uses quasi-Newton approaches such as BFGS and SR1 methods. These methods compute an approximation of the inverse of the Hessian matrix given the first-order gradient from the adjoint method. The methods may not give significant speedup if the Hessian is ill-conditioned. We have developed and implemented the Hessian matrix computation using the adjoint method. Due to high computational cost of the Newton method itself, we instead compute the Hessian-timesvector product which is used in a conjugate gradient algorithm. Finally, the last contribution of this thesis is on surrogate optimization for water flooding in the presence of the output constraints. Two kinds of model order reduction techniques are applied to build surrogate models. These are proper orthogonal decomposition (POD) and the discrete empirical interpolation method (DEIM

  4. ENHANCING RESERVOIR MANAGEMENT IN THE APPALACHIAN BASIN BY IDENTIFYING TECHNICAL BARRIER AND PREFERRED PRACTICES

    Energy Technology Data Exchange (ETDEWEB)

    Ronald R. McDowell; Khashayar Aminian; Katharine L. Avary; John M. Bocan; Michael Ed. Hohn; Douglas G. Patchen

    2003-09-01

    interviews and in the Workshop, as, perhaps, the key issue related to oil production in the Appalachian region - the price of a barrel of oil. Project members sought solutions to production problems from a number of sources. In general, the Petroleum Technology Transfer Council (PTTC) website, both regional and national, proved to be a fertile source of information. Technical issues included water production, paraffin accumulation, production practices, EOR and waterflooding were addressed in a number of SPE papers. Articles on reservoir characterization were found in both the AAPG Bulletin and in SPE papers. Project members extracted topical and keyword information from pertinent articles and websites and combined them in a database that was placed on the PUMP website. Because of difficulties finding potential members with the qualifications, interests, and flexibility of schedule to allow a long-term commitment, it was decided to implement the PMP Regional Council as a subcommittee of the Producer Advisory Group (PAG) sponsored by Appalachian Region PTTC. The advantages of this decision are that the PAG is in already in existence as a volunteer group interested in problem identification and implementation of solutions and that PAG members are unpaid, so no outside funds will be required to sustain the group. The PUMP website became active in October of 2002. The site is designed to evolve; as new information becomes available, it can be readily added to the site or the site can be modified to accommodate it. The site is interactive allowing users to search within the PUMP site, within the Appalachian Region PTTC site, or within the whole internet through the input of user-supplied key words for information on oil production problems and solutions. Since its inception in the Fall of 2002, the PUMP site has experienced a growing number of users of increasingly diverse nature and from an increasing geographic area. This indicates that the site is reaching its target audience

  5. Microbial conversion of higher hydrocarbons to methane in oil and coal reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Kruger, Martin; Beckmaann, Sabrina; Siegert, Michael; Grundger, Friederike; Richnow, Hans [Geomicrobiology Group, Federal Institute for Geosciences and Natural Resources (Germany)

    2011-07-01

    In recent years, oil production has increased enormously but almost half of the oil now remaining is heavy/biodegraded and cannot be put into production. There is therefore a need for new technology and for diversification of energy sources. This paper discusses the microbial conversion of higher hydrocarbons to methane in oil and coal reservoirs. The objective of the study is to identify microbial and geochemical controls on methanogenesis in reservoirs. A graph shows the utilization of methane for various purposes in Germany from 1998 to 2007. A degradation process to convert coal to methane is shown using a flow chart. The process for converting oil to methane is also given. Controlling factors include elements such as Fe, nitrogen and sulfur. Atmospheric temperature and reservoir pressure and temperature also play an important role. From the study it can be concluded that isotopes of methane provide exploration tools for reservoir selection and alkanes and aromatic compounds provide enrichment cultures.

  6. Oil and reservoir core extracts compositional variations in the Kerkennah Ouest fields, Tunisia

    Energy Technology Data Exchange (ETDEWEB)

    Ghenma, R. [ETAP, Belvedere (Tunisia); LaFargue, E. [IFP, Malmaison (France)

    1995-08-01

    A suite of oils and reservoir core extracts from the Kerkennah oil fields in Tunisia has been analyzed by various geochemical techniques to elucidate the geological processes which cause variations in oil and extracts composition and their resulting fingerprinting in the different reservoirs of the field. The results obtained greatly helped in the understanding of filling directions which is valuable for future exploration of satellite fields. The oil pools studied are parts of a large geologic province ({open_quotes}the pelagienne plateforme{close_quotes}) where the main oil fields are limited by NW-SE major faults. The two main reservoirs we encountered in the carbonate series of Turonian and Eocene ages and the best reservoir qualities are found in the packstone and grainstone Nummulites facies. Numerous fractures we observed through the fields and we could demonstrate their influence on the filling history of the different fields as well as on the present oil production. Detailed analysis of the light hydrocarbons (C{sub 20-}) as well as the complete study of the C{sub 15+} hydrocarbons indicate compositional variations between the hydrocarbons stored in the Eocene and Turonian reservoirs. The core extracts from the two reservoirs also shows some variations with in particular maturity differences. Apparently the only possible source rock in the area is represented by the Bahloul formation of Turonian age. Within this scenario, we proposed the hypothesis of different behaviours of the main faults over geological time: a first period where the faults acted as conduits for hydrocarbon migration towards both Turonian and Eocene reservoirs and a second period where the faults became impervious to the hydrocarbons moving towards the Eocene reservoirs thus resulting in the storage of more mature hydrocarbons in the Turonian reservoirs only. Also of interest is the observation of different levels of homogenization in the Turonian reservoirs from one field to another.

  7. On the evaluation of steam assisted gravity drainage in naturally fractured oil reservoirs

    Directory of Open Access Journals (Sweden)

    Seyed Morteza Tohidi Hosseini

    2017-06-01

    Full Text Available Steam Assisted Gravity Drainage (SAGD as a successful enhanced oil recovery (EOR process has been applied to extract heavy and extra heavy oils. Huge amount of global heavy oil resources exists in carbonate reservoirs which are mostly naturally fractured reservoirs. Unlike clastic reservoirs, few studies were carried out to determine the performance of SAGD in carbonate reservoirs. Even though SAGD is a highly promising technique, several uncertainties and unanswered questions still exist and they should be clarified for expansion of SAGD methods to world wide applications especially in naturally fractured reservoirs. In this communication, the effects of some operational and reservoir parameters on SAGD processes were investigated in a naturally fractured reservoir with oil wet rock using CMG-STARS thermal simulator. The purpose of this study was to investigate the role of fracture properties including fracture orientation, fracture spacing and fracture permeability on the SAGD performance in naturally fractured reservoirs. Moreover, one operational parameter was also studied; one new well configuration, staggered well pair was evaluated. Results indicated that fracture orientation influences steam expansion and oil production from the horizontal well pairs. It was also found that horizontal fractures have unfavorable effects on oil production, while vertical fractures increase the production rate for the horizontal well. Moreover, an increase in fracture spacing results in more oil production, because in higher fracture spacing model, steam will have more time to diffuse into matrices and heat up the entire reservoir. Furthermore, an increase in fracture permeability results in process enhancement and ultimate recovery improvement. Besides, diagonal change in the location of injection wells (staggered model increases the recovery efficiency in long-term production plan.

  8. IMPROVING CO2 EFFICIENCY FOR RECOVERING OIL IN HETEROGENEOUS RESERVOIRS

    Energy Technology Data Exchange (ETDEWEB)

    Reid B. Grigg; Robert K. Svec; Zhengwen Zeng; Baojun Bai; Yi Liu

    2004-09-27

    The third annual report of ''Improving CO{sub 2} Efficiency for Recovery Oil in Heterogeneous Reservoirs'' presents results of laboratory studies with related analytical models for improved oil recovery. All studies were designed to optimize utilization and extend the practice of CO{sub 2} flooding to a wider range of reservoirs. Chapter 1 describes the behavior at low concentrations of the surfactant Chaser International CD1045{trademark} (CD) versus different salinity, pressure and temperature. Results of studies on the effects of pH and polymer (hydrolyzed polyacrylamide?HPAM) and CO{sub 2} foam stability after adsorption in the core are also reported. Calcium lignosulfonate (CLS) transport mechanisms through sandstone, description of the adsorption of CD and CD/CLS onto three porous media (sandstone, limestone and dolomite) and five minerals, and the effect of adsorption on foam stability are also reported. In Chapter 2, the adsorption kinetics of CLS in porous Berea sandstone and non-porous minerals are compared by monitoring adsorption density change with time. Results show that adsorption requires a much longer time for the porous versus non-porous medium. CLS adsorption onto sandstone can be divided into three regions: adsorption controlled by dispersion, adsorption controlled by diffusion and adsorption equilibrium. NaI tracer used to characterize the sandstone had similar trends to earlier results for the CLS desorption process, suggesting a dual porosity model to simulate flow through Berea sandstone. The kinetics and equilibrium test for CD adsorption onto five non-porous minerals and three porous media are reported in Chapter 3. CD adsorption and desorption onto non-porous minerals can be established in less than one hour with adsorption densities ranging from 0.4 to 1.2 mg of CD per g of mineral in decreasing order of montmorillonite, dolomite, kaolinite, silica and calcite. The surfactant adsorption onto three porous media takes

  9. Sand Failure Mechanism and Sanding Parameters in Niger Delta Oil Reservoirs

    OpenAIRE

    Sunday Isehunwa,; Andrew Farotade

    2010-01-01

    Sand production is a major issue during oil and gas production from unconsolidated reservoirs. In predicting the onset of sand production, it is important to accurately determine the failure mechanism and the contributing parameters. The aim of this study was to determine sand failure mechanism in the Niger-Delta, identify themajor contributing parameters and evaluate their effects on sanding.Completion and production data from 78 strings completed on 22 reservoirs in a Niger Delta oil Field ...

  10. Modeling Reservoir Formation Damage due to Water Injection for Oil Recovery

    DEFF Research Database (Denmark)

    Yuan, Hao

    2010-01-01

    The elliptic equation for non-Fickian transport of suspension in porous media is applied to simulate the reservoir formation damage due to water injection for oil recovery. The deposition release (erosion of reservoir formation) and the suspension deposition (pore plugging) are both taken...

  11. Recent developments in reservoir engineering and their impact on oil and gas field development

    Energy Technology Data Exchange (ETDEWEB)

    Davies, R.H.; Niko, H. [Shell Internationale Petroleum Maatschappij BV, Den Haag (Netherlands)

    1996-12-31

    With much of the reservoir engineering development activities prior to 1986 being directed to new processes such as EOR, reservoir engineering of today has, like the other petroleum engineering disciplines, become part of an integrated effort to extract the maximum amount of oil from a reservoir. We will discuss some of the new developments in reservoir engineering which had a real impact on oil field operations in Shell and on the working practices of the individual reservoir engineers. Examples of recent advances in reservoir engineering are: (1) progress in the field of measuring residual oil saturations to water under representative conditions which will enable a more realistic assessment of trapped/bypassed oil in water floods such as those in large North Sea fields; (2) improved understanding of the production behaviour of horizontal wells based on analytical and numerical modelling which led to successful applications in Gabon and Oman; (3) advances in our understanding of production in naturally fractured reservoirs which provided the basis for a unique field experiment in the Natih Field in Oman; (4) understanding of the mechanism of fracturing in water injection wells, a process which has large cost-saving potential. The one factor largely responsible for the change in working practices of individual reservoir engineers is the availability of modern integrated IT technology. (author)

  12. Estimation of Oil Production Rates in Reservoirs Exposed to Focused Vibrational Energy

    KAUST Repository

    Jeong, Chanseok

    2014-01-01

    Elastic wave-based enhanced oil recovery (EOR) is being investigated as a possible EOR method, since strong wave motions within an oil reservoir - induced by earthquakes or artificially generated vibrations - have been reported to improve the production rate of remaining oil from existing oil fields. To date, there are few theoretical studies on estimating how much bypassed oil within an oil reservoir could be mobilized by such vibrational stimulation. To fill this gap, this paper presents a numerical method to estimate the extent to which the bypassed oil is mobilized from low to high permeability reservoir areas, within a heterogeneous reservoir, via wave-induced cross-flow oscillation at the interface between the two reservoir permeability areas. This work uses the finite element method to numerically obtain the pore fluid wave motion within a one-dimensional fluid-saturated porous permeable elastic solid medium embedded in a non-permeable elastic semi-infinite solid. To estimate the net volume of mobilized oil from the low to the high permeability area, a fluid flow hysteresis hypothesis is adopted to describe the behavior at the interface between the two areas. Accordingly, the fluid that is moving from the low to the high permeability areas is assumed to transport a larger volume of oil than the fluid moving in the opposite direction. The numerical experiments were conducted by using a prototype heterogeneous oil reservoir model, subjected to ground surface dynamic loading operating at low frequencies (1 to 50 Hz). The numerical results show that a sizeable amount of oil could be mobilized via the elastic wave stimulation. It is observed that certain wave frequencies are more effective than others in mobilizing the remaining oil. We remark that these amplification frequencies depend on the formation’s elastic properties. This numerical work shows that the wave-based mobilization of the bypassed oil in a heterogeneous oil reservoir is feasible, especially

  13. Increasing Heavy Oil Reserves in the Wilmington Oil Field through Advanced Reservoir Characterization and Thermal Production Technologies

    Energy Technology Data Exchange (ETDEWEB)

    City of Long Beach; David K.Davies and Associates; Tidelands Oil Production Company; University of Southern California

    1999-06-25

    The objective of this project is to increase the recoverable heavy oil reserves within sections of the Wilmington Oil Field, near Long Beach, California. This is realized through the testing and application of advanced reservoir characterization and thermal production technologies. It is hoped that the successful application of these technologies will result in their implementation throughout the Wilmington Field and through technology transfer, will be extended to increase the recoverable oil reserves in other slope and basin clastic (SBC) reservoirs. The existing steamflood in the Tar zone of Fault Block (FB) II-A has been relatively insufficient because of several producability problems which are common in SBC reservoir; inadequate characterization of the heterogeneous turbidite sands, high permeability thief zones, low gravity oil and non-uniform distribution of the remaining oil. This has resulted in poor sweep efficiency, high steam-oil ratios, and early breakthrough. Operational problems related to steam breakthrough, high reservoir pressure, and unconsolidated sands have caused premature well and downhole equipment failures. In aggregate, these reservoir and operational constraints have resulted in increased operating costs and decreased recoverable reserves.

  14. Brittleness index and seismic rock physics model for anisotropic tight-oil sandstone reservoirs

    Institute of Scientific and Technical Information of China (English)

    Huang Xin-Rui; Huang Jian-Ping; Li Zhen-Chun; Yang Qin-Yong; Sun Qi-Xing; Cui Wei

    2015-01-01

    Brittleness analysis becomes important when looking for sweet spots in tight-oil sandstone reservoirs. Hence, appropriate indices are required as accurate brittleness evaluation criteria. We construct a seismic rock physics model for tight-oil sandstone reservoirs with vertical fractures. Because of the complexities in lithology and pore structure and the anisotropic characteristics of tight-oil sandstone reservoirs, the proposed model is based on the solid components, pore connectivity, pore type, and fractures to better describe the sandstone reservoir microstructure. Using the model, we analyze the brittleness sensitivity of the elastic parameters in an anisotropic medium and establish a new brittleness index. We show the applicability of the proposed brittleness index for tight-oil sandstone reservoirs by considering the brittleness sensitivity, the rock physics response characteristics, and cross-plots. Compared with conventional brittleness indexes, the new brittleness index has high brittleness sensitivity and it is the highest in oil-bearing brittle zones with relatively high porosity. The results also suggest that the new brittleness index is much more sensitive to elastic properties variations, and thus can presumably better predict the brittleness characteristics of sweet spots in tight-oil sandstone reservoirs.

  15. IMPROVING CO2 EFFICIENCY FOR RECOVERING OIL IN HETEROGENEOUS RESERVOIRS

    Energy Technology Data Exchange (ETDEWEB)

    Reid B. Grigg; Robert K. Svec

    2002-12-20

    This document is the First Annual Report for the U.S. Department of Energy under contract No., a three-year contract entitled: ''Improving CO{sub 2} Efficiency for Recovering Oil in Heterogeneous Reservoirs.'' The research improved our knowledge and understanding of CO{sub 2} flooding and includes work in the areas of injectivity and mobility control. The bulk of this work has been performed by the New Mexico Petroleum Recovery Research Center, a research division of New Mexico Institute of Mining and Technology. This report covers the reporting period of September 28, 2001 and September 27, 2002. Injectivity continues to be a concern to the industry. During this period we have contacted most of the CO{sub 2} operators in the Permian Basin and talked again about their problems in this area. This report has a summary of what we found. It is a given that carbonate mineral dissolution and deposition occur in a formation in geologic time and are expected to some degree in carbon dioxide (CO{sub 2}) floods. Water-alternating-gas (WAG) core flood experiments conducted on limestone and dolomite core plugs confirm that these processes can occur over relatively short time periods (hours to days) and in close proximity to each other. Results from laboratory CO{sub 2}-brine flow experiments performed in rock core were used to calibrate a reactive transport simulator. The calibrated model is being used to estimate in situ effects of a range of possible sequestration options in depleted oil/gas reservoirs. The code applied in this study is a combination of the well known TOUGH2 simulator, for coupled groundwater/brine and heat flow, with the chemistry code TRANS for chemically reactive transport. Variability in response among rock types suggests that CO{sub 2} injection will induce ranges of transient and spatially dependent changes in intrinsic rock permeability and porosity. Determining the effect of matrix changes on CO{sub 2} mobility is crucial in

  16. Arrow Lakes Reservoir Fertilization Experiment, Technical Report 1999-2004.

    Energy Technology Data Exchange (ETDEWEB)

    Schindler, E.

    2007-02-01

    The Arrow Lakes food web has been influenced by several anthropogenic stressors during the past 45 years. These include the introduction of mysid shrimp (Mysis relicta) in 1968 and 1974 and the construction of large hydroelectric impoundments in 1969, 1973 and 1983. The construction of the impoundments affected the fish stocks in Upper and Lower Arrow lakes in several ways. The construction of Hugh Keenleyside Dam (1969) resulted in flooding that eliminated an estimated 30% of the available kokanee spawning habitat in Lower Arrow tributaries and at least 20% of spawning habitat in Upper Arrow tributaries. The Mica Dam (1973) contributed to water level fluctuations and blocked upstream migration of all fish species including kokanee. The Revelstoke Dam (1983) flooded 150 km of the mainstem Columbia River and 80 km of tributary streams which were used by kokanee, bull trout, rainbow trout and other species. The construction of upstream dams also resulted in nutrient retention which ultimately reduced reservoir productivity. In Arrow Lakes Reservoir (ALR), nutrients settled out in the Revelstoke and Mica reservoirs, resulting in decreased productivity, a process known as oligotrophication. Kokanee are typically the first species to respond to oligotrophication resulting from aging impoundments. To address the ultra-oligotrophic status of ALR, a bottom-up approach was taken with the addition of nutrients (nitrogen and phosphorus in the form of liquid fertilizer from 1999 to 2004). Two of the main objectives of the experiment were to replace lost nutrients as a result of upstream impoundments and restore productivity in Upper Arrow and to restore kokanee and other sport fish abundance in the reservoir. The bottom-up approach to restoring kokanee in ALR has been successful by replacing nutrients lost as a result of upstream impoundments and has successfully restored the productivity of Upper Arrow. Primary production rates increased, the phytoplankton community responded

  17. Analysis of Proppant Hydraulic Fracturing in a Sand Oil Reservoir in Southwest of Iran

    Directory of Open Access Journals (Sweden)

    Reza Masoomi

    2015-10-01

    Full Text Available Hydraulic fracturing is one way to increase the productivity of oil and gas wells. One of the most fundamental successes of hydraulic fracturing operation is selecting the proper size and type of proppants which are used during the process. The aim of this study is optimizing the type and size of used propant in hydraulic fracturing operation in a sand oil reservoir in southwest of Iran. In this study sand and ceramic (sintered bauxite have been considered as proppant type. Also the various types of resin-coated sand and resin-coated ceramic have been considered. Then the various scenarios have been designed to optimize the size and type of proppant used in hydraulic fracturing in a sand oil reservoir in southwest of Iran. Also in this study increasing the cumulative oil recovery in fractured and Non-fractured wells in a sand oil reservoir in southwest of Iran have been investigated.

  18. A study of relations between physicochemical properties of crude oils and microbiological characteristics of reservoir microflora

    Science.gov (United States)

    Yashchenko, I. G.; Polishchuk, Yu. M.; Peremitina, T. O.

    2015-10-01

    The dependence of the population and activity of reservoir microflora upon the chemical composition and viscosity of crude oils has been investigated, since it allows the problem of improvement in the technologies and enhancement of oil recovery as applied to production of difficult types of oils with anomalous properties (viscous, heavy, waxy, high resin) to be solved. The effect of the chemical composition of the oil on the number, distribution, and activity of reservoir microflora has been studied using data on the microbiological properties of reservoir water of 16 different fields in oil and gas basins of Russia, Mongolia, China, and Vietnam. Information on the physicochemical properties of crude oils of these fields has been obtained from the database created at the Institute of Petroleum Chemistry, Siberian Branch on the physicochemical properties of oils throughout the world. It has been found that formation water in viscous oil reservoirs is char acterized by a large population of heterotrophic and sulfate reducing bacteria and the water of oil fields with a high paraffin content, by population of denitrifying bacteria.

  19. OIL RESERVOIR CHARACTERIZATION AND CO2 INJECTION MONITORING IN THE PERMIAN BASIN WITH CROSSWELL ELECTROMAGNETIC IMAGING

    Energy Technology Data Exchange (ETDEWEB)

    Michael Wilt

    2004-02-01

    Substantial petroleum reserves exist in US oil fields that cannot be produced economically, at current prices, unless improvements in technology are forthcoming. Recovery of these reserves is vital to US economic and security interests as it lessens our dependence on foreign sources and keeps our domestic petroleum industry vital. Several new technologies have emerged that may improve the situation. The first is a series of new flooding techniques to re-pressurize reservoirs and improve the recovery. Of these the most promising is miscible CO{sub 2} flooding, which has been used in several US petroleum basins. The second is the emergence of new monitoring technologies to track and help manage this injection. One of the major players in here is crosswell electromagnetics, which has a proven sensitivity to reservoir fluids. In this project, we are applying the crosswell EM technology to a CO{sub 2} flood in the Permian Basin oil fields of New Mexico. With our partner ChevronTexaco, we are testing the suitability of using EM for tracking the flow of injected CO{sub 2} through the San Andreas reservoir in the Vacuum field in New Mexico. The project consisted of three phases, the first of which was a preliminary field test at Vacuum, where a prototype system was tested in oil field conditions including widely spaced wells with steel casing. The results, although useful, demonstrated that the older technology was not suitable for practical deployment. In the second phase of the project, we developed a much more powerful and robust field system capable of collecting and interpreting field data through steel-cased wells. The final phase of the project involved applying this system in field tests in the US and overseas. Results for tests in steam and water floods showed remarkable capability to image between steel wells and provided images that helped understand the geology and ongoing flood and helped better manage the field. The future of this technology is indeed bright

  20. Exploration Potential of Marine Source Rocks Oil-Gas Reservoirs in China

    Institute of Scientific and Technical Information of China (English)

    2007-01-01

    So far, more than 150 marine oil-gas fields have been found onshore and offshore about 350.The marine source rocks are mainly Paleozoic and Mesozoic onshore whereas Tertiary offshore. Three genetic categories of oil-gas reservoirs have been defined for the marine reservoirs in China: primary reservoirs, secondary reservoirs and hydrocarbon-regeneration reservoirs. And three exploration prospects have also been suggested: (1) Primary reservoirs prospects, which are chiefly distributed in many Tertiary basins of the South China Sea (SCS), the Tertiary shelf basins of the East China Sea (ECS) and the Paleozoic of Tarim basin, Sichuan basin and Ordos basin. To explore large-middle-scale even giant oil-gas fields should chiefly be considered in this category reservoirs. These basins are the most hopeful areas to explore marine oil-gas fields in China, among which especially many Tertiary basins of the SCS should be strengthened to explore. (2) Secondary reservoirs prospects, which are mainly distributed in the Paleozoic and Mesozoic of the Tarim basin, Sichuan basin, Qiangtang basin and Chuxiong basin in western China, of which exploration potential is less than that of the primary reservoirs. (3) Hydrocarbon-regeneration reservoirs prospects, which are chiefly distributed in the Bohai Bay basin, North Jiangsu-South Yellow Sea basin, southern North China basin, Jianghan basin,South Poyang basin in eastern China and the Tarim basin in western China, of which source rocks are generally the Paleozoic. And the reservoirs formed by late-stage (always Cenozoic) secondary hydrocarbon generation of the Paleozoic source rocks should mainly be considered to explore, among which middle-small and small oil-gas fields are the chief exploration targets. As a result of higher thermal evolution of Paleozoic and Mesozoic source rocks, the marine reservoirs onshore are mainly gas fields, and so far marine oil fields have only been found in the Tarim basin. No other than establishing

  1. Oil recovery from naturally fractured reservoirs by steam injection methods. Final report

    Energy Technology Data Exchange (ETDEWEB)

    Reis, J.C.; Miller, M.A.

    1995-05-01

    Oil recovery by steam injection is a proven, successful technology for nonfractured reservoirs, but has received only limited study for fractured reservoirs. Preliminary studies suggest recovery efficiencies in fractured reservoirs may be increased by as much as 50% with the application of steam relative to that of low temperature processes. The key mechanisms enhancing oil production at high temperature are the differential thermal expansion between oil and the pore volume, and the generation of gases within matrix blocks. Other mechanisms may also contribute to increased production. These mechanisms are relatively independent of oil gravity, making steam injection into naturally fractured reservoirs equally attractive to light and heavy oil deposits. The objectives of this research program are to quantify the amount of oil expelled by these recovery mechanisms and to develop a numerical model for predicting oil recovery in naturally fractured reservoirs during steam injection. The experimental study consists of constructing and operating several apparatuses to isolate each of these mechanisms. The first measures thermal expansion and capillary imbibition rates at relatively low temperature, but for various lithologies and matrix block shapes. The second apparatus measures the same parameters, but at high temperatures and for only one shape. A third experimental apparatus measures the maximum gas saturations that could build up within a matrix block. A fourth apparatus measures thermal conductivity and diffusivity of porous media. The numerical study consists of developing transfer functions for oil expulsion from matrix blocks to fractures at high temperatures and incorporating them, along with the energy equation, into a dual porosity thermal reservoir simulator. This simulator can be utilized to make predictions for steam injection processes in naturally-fractured reservoirs. Analytical models for capillary imbibition have also been developed.

  2. Increased oil production and reserves utilizing secondary/teritiary recovery techniques on small reservoirs in the Paradox Basin, Utah. Quarterly report, July 1 - September 30, 1996

    Energy Technology Data Exchange (ETDEWEB)

    Allison, M.L.

    1996-10-01

    The primary objective of this project is to enhance domestic petroleum production by demonstration and technology transfer of an advanced oil recovery technology in the Paradox basin, southeastern Utah. If this project can demonstrate technical and economic feasibility, the technique can be applied to approximately 100 additional small fields in the Paradox basin alone, and result in increased recovery of 150 to 200 million barrels of oil. This project is designed to characterize five shallow-shelf carbonate reservoirs in the Pennsylvanian (Desmoinesian) Paradox Formation and choose the best candidate for a pilot demonstration project for either a waterflood or carbon dioxide flood project. The field demonstration, monitoring of field performance, and associated validation activities will take place in the Paradox basin within the Navajo Nation. The results of this project will be transferred to industry and other researchers through a petroleum extension service, creation of digital databases for distribution, technical workshops and seminars, field trips, technical presentations at national and regional professional meeting, and publication in newsletters and various technical or trade journals. Four activities continued this quarter as part of the geological and reservoir characterization: (1) interpretation of outcrop analogues; (2) reservoir mapping, (3) reservoir engineering analysis of the five project fields; and (4) technology transfer.

  3. Investigation of spore forming bacterial flooding for enhanced oil recovery in a North Sea chalk Reservoir

    DEFF Research Database (Denmark)

    Halim, Amalia Yunita; Nielsen, Sidsel Marie; Eliasson Lantz, Anna

    2015-01-01

    Little has been done to study microbial enhanced oil recovery (MEOR) in chalk reservoirs. The present study focuses on core flooding experiments designed to see microbial plugging and its effect on oil recovery. A pressure tapped core holder was used for this purpose. A spore forming bacteria...

  4. Cold production followed by cyclic steam simulation in thin oil sands reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Wang, J.; Gates, I.D. [Dept. of Chemical and Petroleum Engineering, University of Calgary (Canada)

    2011-07-01

    In Western Canada, thermal recovery methods are required to extract bitumen and heavy oil from reservoirs, due to their high viscosity. One method is cyclic steam simulation (CSS). Steam is injected into the reservoir through a single well and fluids are produced from the reservoir at different times; a depletion chamber has to be initialized successfully so the process can perform optimally. This paper aimed at understanding how cold production can help with starting CSS. Simulations were undertaken with a heterogeneous reservoir model to explore the impact of cold production on subsequent CSS in the Bluesky oil sands formation. Results showed that a depletion zone grows in the surroundings of the well during cold production and that steam conformance is then better during CCS than without cold production. This paper showed that using cold production before CSS is a good solution when the reservoir is cold producible.

  5. Design and implementation of a caustic flooding EOR pilot at Court Bakken heavy oil reservoir

    Energy Technology Data Exchange (ETDEWEB)

    Xie, J.; Chung, B.; Leung, L. [Society of Petroleum Engineers, Canadian Section, Calgary, AB (Canada)]|[Nexen Inc., Calgary, AB (Canada)

    2008-10-15

    Successful waterflooding has been ongoing since 1988 at the Court Bakken heavy oil field in west central Saskatchewan. There are currently 20 injectors and 28 active oil producers in the Court main unit which is owned by Nexen and Pengrowth. The Court pool has an estimated 103.8 mmbbl of original oil in place (OOIP), of which 24 per cent has been successfully recovered after 20 years of waterflooding. A high-level enhanced oil recovery (EOR) screening study was conducted to evaluate other EOR technologies for a heavy oil reservoir of this viscosity range (17 degrees API). Laboratory studies showed that caustic flooding may enhance oil recovery after waterflooding at the Court Bakken heavy oil pool. A single well test demonstrated that caustic injection effectively reduced residual oil saturation. A sector model reservoir simulation revealed that caustic flood could achieve 9 per cent incremental oil recovery in the pilot area. Following the promising laboratory results, a successful caustic flood pilot was implemented at Court heavy oil pool where the major challenges encountered were low reservoir pressure and water channeling. 6 refs., 2 tabs., 6 figs.

  6. Simulation Study of CO2-EOR in Tight Oil Reservoirs with Complex Fracture Geometries.

    Science.gov (United States)

    Zuloaga-Molero, Pavel; Yu, Wei; Xu, Yifei; Sepehrnoori, Kamy; Li, Baozhen

    2016-09-15

    The recent development of tight oil reservoirs has led to an increase in oil production in the past several years due to the progress in horizontal drilling and hydraulic fracturing. However, the expected oil recovery factor from these reservoirs is still very low. CO2-based enhanced oil recovery is a suitable solution to improve the recovery. One challenge of the estimation of the recovery is to properly model complex hydraulic fracture geometries which are often assumed to be planar due to the limitation of local grid refinement approach. More flexible methods like the use of unstructured grids can significantly increase the computational demand. In this study, we introduce an efficient methodology of the embedded discrete fracture model to explicitly model complex fracture geometries. We build a compositional reservoir model to investigate the effects of complex fracture geometries on performance of CO2 Huff-n-Puff and CO2 continuous injection. The results confirm that the appropriate modelling of the fracture geometry plays a critical role in the estimation of the incremental oil recovery. This study also provides new insights into the understanding of the impacts of CO2 molecular diffusion, reservoir permeability, and natural fractures on the performance of CO2-EOR processes in tight oil reservoirs.

  7. Simulation Study of CO2-EOR in Tight Oil Reservoirs with Complex Fracture Geometries

    Science.gov (United States)

    Zuloaga-Molero, Pavel; Yu, Wei; Xu, Yifei; Sepehrnoori, Kamy; Li, Baozhen

    2016-09-01

    The recent development of tight oil reservoirs has led to an increase in oil production in the past several years due to the progress in horizontal drilling and hydraulic fracturing. However, the expected oil recovery factor from these reservoirs is still very low. CO2-based enhanced oil recovery is a suitable solution to improve the recovery. One challenge of the estimation of the recovery is to properly model complex hydraulic fracture geometries which are often assumed to be planar due to the limitation of local grid refinement approach. More flexible methods like the use of unstructured grids can significantly increase the computational demand. In this study, we introduce an efficient methodology of the embedded discrete fracture model to explicitly model complex fracture geometries. We build a compositional reservoir model to investigate the effects of complex fracture geometries on performance of CO2 Huff-n-Puff and CO2 continuous injection. The results confirm that the appropriate modelling of the fracture geometry plays a critical role in the estimation of the incremental oil recovery. This study also provides new insights into the understanding of the impacts of CO2 molecular diffusion, reservoir permeability, and natural fractures on the performance of CO2-EOR processes in tight oil reservoirs.

  8. Reservoir heterogeneity in Carter Sandstone, North Blowhorn Creek oil unit and vicinity, Black Warrior Basin, Alabama

    Energy Technology Data Exchange (ETDEWEB)

    Kugler, R.L.; Pashin, J.C.

    1992-05-01

    This report presents accomplishments made in completing Task 3 of this project which involves development of criteria for recognizing reservoir heterogeneity in the Black Warrior basin. The report focuses on characterization of the Upper Mississippian Carter sandstone reservoir in North Blowhorn Creek and adjacent oil units in Lamar County, Alabama. This oil unit has produced more than 60 percent of total oil extracted from the Black Warrior basin of Alabama. The Carter sandstone in North Blowhorn Creek oil unit is typical of the most productive Carter oil reservoirs in the Black Warrior basin of Alabama. The first part of the report synthesizes data derived from geophysical well logs and cores from North Blowhorn Creek oil unit to develop a depositional model for the Carter sandstone reservoir. The second part of the report describes the detrital and diagenetic character of Carter sandstone utilizing data from petrographic and scanning electron microscopes and the electron microprobe. The third part synthesizes porosity and pore-throat-size-distribution data determined by high-pressure mercury porosimetry and commercial core analyses with results of the sedimentologic and petrographic studies. The final section of the report discusses reservoir heterogeneity within the context of the five-fold classification of Moore and Kugler (1990).

  9. Redistribution of filtration flows by thermogel at boundary water flooding of oil reservoirs

    Science.gov (United States)

    Korsakova, N. K.; Penkovsky, V. I.; Altunina, L. K.; Kuvshinov, V. A.

    2016-11-01

    The results of physical simulation by a two-dimensional reservoir model and numerical calculation by a finite element method for the GALKA-NT thermogel influence on the redistribution of filtration flows of injected water in the oil production by boundary water flooding are presented. The reserve development by this method, especially in the case of viscose oil pools, occurs with an unstable displacement front that causes growing water fingers, which finally transform into the network of water-conducting channels in the direction of the least filtration resistance between well rows. Here the most amount of oil remains in the nonmobile capillary-locked state, which is in dynamic equilibrium with the flow of displacing water. The injection of thermogel into the reservoir area between the wells is shown to widen the displacement front and to increase the reservoir coverage by water flooding at a later stage in order to enhance oil recovery.

  10. Petroleum, oil field waters, and authigenic mineral assemblages - Are they in metastable equilibrium in hydrocarbon reservoirs?

    Science.gov (United States)

    Helgeson, Harold C.; Knox, Annette M.; Owens, Christine E.; Shock, Everett L.

    1993-07-01

    The hypothesis that although the presence of carboxylic acids and carboxylate anions in oil field waters is commonly attributed to the thermal maturation of kerogen or bacterial degradation of hydrocarbons during water-washing of petroleum in relatively shallow reservoirs, they may have also been produced in deeper reservoirs by the hydrolysis of hydrocarbons in petroleum at the oil-water interface is tested. Calculations were carried out to determine the distribution of species with the minimum Gibbs free energy in overpressured oil field waters in the Texas Gulf Coast assuming metastable equilibrium among calcite, albite, and a representative spectrum of organic and inorganic aqueous species at reservoir temperatures and pressures. The hypothesis that homogeneous equilibrium obtains among carboxylate and carbonate species in oil field waters is confirmed.

  11. Hydrocarbon charging histories of the Ordovician reservoir in the Tahe oil field, Tarim Basin, China

    Institute of Scientific and Technical Information of China (English)

    李纯泉; 陈红汉; 李思田; 张希明; 陈汉林

    2004-01-01

    The Ordovician reservoir of the Tahe oil field went through many tectonic reconstructions, and was characterized by multiple hydrocarbon chargings. The aim of this study was to unravel the complex charging histories. Systematic analysis of fluid inclusions was employed to complete the investigation. Fluorescence observation of oil inclusions under UV light, and microthermometry of both oil and aqueous inclusions in 105 core samples taken from the Ordovician reservoir indicated that the Ordovician reservoir underwent four oil chargings and a gas charging. The hydrocarbon chargings occurred at the late Hercynian, the Indo-Sinian and Yanshan, the early Himalaya, the middle Himalaya, and the late Himalaya,respectively. The critical hydrocarbon charging time was at the late Hercynian.

  12. IMPROVED OIL RECOVERY IN MISSISSIPPIAN CARBONATE RESERVOIRS OF KANSAS - NEAR TERM - CLASS 2

    Energy Technology Data Exchange (ETDEWEB)

    Timothy R. Carr; Don W. Green; G. Paul Willhite

    2000-04-30

    This annual report describes progress during the final year of the project entitled ''Improved Oil Recovery in Mississippian Carbonate Reservoirs in Kansas''. This project funded under the Department of Energy's Class 2 program targets improving the reservoir performance of mature oil fields located in shallow shelf carbonate reservoirs. The focus of the project was development and demonstration of cost-effective reservoir description and management technologies to extend the economic life of mature reservoirs in Kansas and the mid-continent. As part of the project, tools and techniques for reservoir description and management were developed, modified and demonstrated, including PfEFFER spreadsheet log analysis software. The world-wide-web was used to provide rapid and flexible dissemination of the project results through the Internet. A summary of demonstration phase at the Schaben and Ness City North sites demonstrates the effectiveness of the proposed reservoir management strategies and technologies. At the Schaben Field, a total of 22 additional locations were evaluated based on the reservoir characterization and simulation studies and resulted in a significant incremental production increase. At Ness City North Field, a horizontal infill well (Mull Ummel No.4H) was planned and drilled based on the results of reservoir characterization and simulation studies to optimize the location and length. The well produced excellent and predicted oil rates for the first two months. Unexpected presence of vertical shale intervals in the lateral resulted in loss of the hole. While the horizontal well was not economically successful, the technology was demonstrated to have potential to recover significant additional reserves in Kansas and the Midcontinent. Several low-cost approaches were developed to evaluate candidate reservoirs for potential horizontal well applications at the field scale, lease level, and well level, and enable the small

  13. Experimental Investigation on Dilation Mechanisms of Land-Facies Karamay Oil Sand Reservoirs under Water Injection

    Science.gov (United States)

    Lin, Botao; Jin, Yan; Pang, Huiwen; Cerato, Amy B.

    2016-04-01

    The success of steam-assisted gravity drainage (SAGD) is strongly dependent on the formation of a homogeneous and highly permeable zone in the land-facies Karamay oil sand reservoirs. To accomplish this, hydraulic fracturing is applied through controlled water injection to a pair of horizontal wells to create a dilation zone between the dual wells. The mechanical response of the reservoirs during this injection process, however, has remained unclear for the land-facies oil sand that has a loosely packed structure. This research conducted triaxial, permeability and scanning electron microscopy (SEM) tests on the field-collected oil sand samples. The tests evaluated the influences of the field temperature, confining stress and injection pressure on the dilation mechanisms as shear dilation and tensile parting during injection. To account for petrophysical heterogeneity, five reservoir rocks including regular oil sand, mud-rich oil sand, bitumen-rich oil sand, mudstone and sandstone were investigated. It was found that the permeability evolution in the oil sand samples subjected to shear dilation closely followed the porosity and microcrack evolutions in the shear bands. In contrast, the mudstone and sandstone samples developed distinct shear planes, which formed preferred permeation paths. Tensile parting expanded the pore space and increased the permeability of all the samples in various degrees. Based on this analysis, it is concluded that the range of injection propagation in the pay zone determines the overall quality of hydraulic fracturing, while the injection pressure must be carefully controlled. A region in a reservoir has little dilation upon injection if it remains unsaturated. Moreover, a cooling of the injected water can strengthen the dilation potential of a reservoir. Finally, it is suggested that the numerical modeling of water injection in the Karamay oil sand reservoirs must take into account the volumetric plastic strain in hydrostatic loading.

  14. Computer Modeling of the Displacement Behavior of Carbon Dioxide in Undersaturated Oil Reservoirs

    Directory of Open Access Journals (Sweden)

    Ju Binshan

    2015-11-01

    Full Text Available The injection of CO2 into oil reservoirs is performed not only to improve oil recovery but also to store CO2 captured from fuel combustion. The objective of this work is to develop a numerical simulator to predict quantitatively supercritical CO2 flooding behaviors for Enhanced Oil Recovery (EOR. A non-isothermal compositional flow mathematical model is developed. The phase transition diagram is designed according to the Minimum Miscibility Pressure (MMP and CO2 maximum solubility in oil phase. The convection and diffusion of CO2 mixtures in multiphase fluids in reservoirs, mass transfer between CO2 and crude and phase partitioning are considered. The governing equations are discretized by applying a fully implicit finite difference technique. Newton-Raphson iterative technique was used to solve the nonlinear equation systems and a simulator was developed. The performances of CO2 immiscible and miscible flooding in oil reservoirs are predicted by the new simulator. The distribution of pressure and temperature, phase saturations, mole fraction of each component in each phase, formation damage caused by asphaltene precipitation and the improved oil recovery are predicted by the simulator. Experimental data validate the developed simulator by comparison with simulation results. The applications of the simulator in prediction of CO2 flooding in oil reservoirs indicate that the simulator is robust for predicting CO2 flooding performance.

  15. Producing Light Oil from a Frozen Reservoir: Reservoir and Fluid Characterization of Umiat Field, National Petroleum Reserve, Alaska

    Energy Technology Data Exchange (ETDEWEB)

    Hanks, Catherine

    2012-12-31

    Umiat oil field is a light oil in a shallow, frozen reservoir in the Brooks Range foothills of northern Alaska with estimated oil-in-place of over 1 billion barrels. Umiat field was discovered in the 1940’s but was never considered viable because it is shallow, in the permafrost, and far from any transportation infrastructure. The advent of modern drilling and production techniques has made Umiat and similar fields in northern Alaska attractive exploration and production targets. Since 2008 UAF has been working with Renaissance Alaska Inc. and, more recently, Linc Energy, to develop a more robust reservoir model that can be combined with rock and fluid property data to simulate potential production techniques. This work will be used to by Linc Energy as they prepare to drill up to 5 horizontal wells during the 2012-2013 drilling season. This new work identified three potential reservoir horizons within the Cretaceous Nanushuk Formation: the Upper and Lower Grandstand sands, and the overlying Ninuluk sand, with the Lower Grandstand considered the primary target. Seals are provided by thick interlayered shales. Reserve estimates for the Lower Grandstand alone range from 739 million barrels to 2437 million barrels, with an average of 1527 million bbls. Reservoir simulations predict that cold gas injection from a wagon-wheel pattern of multilateral injectors and producers located on 5 drill sites on the crest of the structure will yield 12-15% recovery, with actual recovery depending upon the injection pressure used, the actual Kv/Kh encountered, and other geologic factors. Key to understanding the flow behavior of the Umiat reservoir is determining the permeability structure of the sands. Sandstones of the Cretaceous Nanushuk Formation consist of mixed shoreface and deltaic sandstones and mudstones. A core-based study of the sedimentary facies of these sands combined with outcrop observations identified six distinct facies associations with distinctive permeability

  16. Producing Light Oil from a Frozen Reservoir: Reservoir and Fluid Characterization of Umiat Field, National Petroleum Reserve, Alaska

    Energy Technology Data Exchange (ETDEWEB)

    Hanks, Catherine

    2012-12-31

    Umiat oil field is a light oil in a shallow, frozen reservoir in the Brooks Range foothills of northern Alaska with estimated oil-in-place of over 1 billion barrels. Umiat field was discovered in the 1940’s but was never considered viable because it is shallow, in the permafrost, and far from any transportation infrastructure. The advent of modern drilling and production techniques has made Umiat and similar fields in northern Alaska attractive exploration and production targets. Since 2008 UAF has been working with Renaissance Alaska Inc. and, more recently, Linc Energy, to develop a more robust reservoir model that can be combined with rock and fluid property data to simulate potential production techniques. This work will be used to by Linc Energy as they prepare to drill up to 5 horizontal wells during the 2012-2013 drilling season. This new work identified three potential reservoir horizons within the Cretaceous Nanushuk Formation: the Upper and Lower Grandstand sands, and the overlying Ninuluk sand, with the Lower Grandstand considered the primary target. Seals are provided by thick interlayered shales. Reserve estimates for the Lower Grandstand alone range from 739 million barrels to 2437 million barrels, with an average of 1527 million bbls. Reservoir simulations predict that cold gas injection from a wagon-wheel pattern of multilateral injectors and producers located on 5 drill sites on the crest of the structure will yield 12-15% recovery, with actual recovery depending upon the injection pressure used, the actual Kv/Kh encountered, and other geologic factors. Key to understanding the flow behavior of the Umiat reservoir is determining the permeability structure of the sands. Sandstones of the Cretaceous Nanushuk Formation consist of mixed shoreface and deltaic sandstones and mudstones. A core-based study of the sedimentary facies of these sands combined with outcrop observations identified six distinct facies associations with distinctive permeability

  17. INCREASING HEAVY OIL RESERVES IN THE WILMINGTON OIL FIELD THROUGH ADVANCED RESERVOIR CHARACTERIZATION AND THERMAL PRODUCTION TECHNOLOGIES

    Energy Technology Data Exchange (ETDEWEB)

    Scott Hara

    2004-03-05

    The overall objective of this project is to increase heavy oil reserves in slope and basin clastic (SBC) reservoirs through the application of advanced reservoir characterization and thermal production technologies. The project involves improving thermal recovery techniques in the Tar Zone of Fault Blocks II-A and V (Tar II-A and Tar V) of the Wilmington Field in Los Angeles County, near Long Beach, California. A primary objective is to transfer technology which can be applied in other heavy oil formations of the Wilmington Field and other SBC reservoirs, including those under waterflood. The thermal recovery operations in the Tar II-A and Tar V have been relatively inefficient because of several producibility problems which are common in SBC reservoirs. Inadequate characterization of the heterogeneous turbidite sands, high permeability thief zones, low gravity oil, and nonuniform distribution of remaining oil have all contributed to poor sweep efficiency, high steam-oil ratios, and early steam breakthrough. Operational problems related to steam breakthrough, high reservoir pressure, and unconsolidated formation sands have caused premature well and downhole equipment failures. In aggregate, these reservoir and operational constraints have resulted in increased operating costs and decreased recoverable reserves. The advanced technologies to be applied include: (1) Develop three-dimensional (3-D) deterministic and stochastic geologic models. (2) Develop 3-D deterministic and stochastic thermal reservoir simulation models to aid in reservoir management and subsequent development work. (3) Develop computerized 3-D visualizations of the geologic and reservoir simulation models to aid in analysis. (4) Perform detailed study on the geochemical interactions between the steam and the formation rock and fluids. (5) Pilot steam injection and production via four new horizontal wells (2 producers and 2 injectors). (6) Hot water alternating steam (WAS) drive pilot in the

  18. Increased Oil Production and Reserves Utilizing Secondary/Tertiary Recovery Techniques on Small Reservoirs in the Paradox Basin, Utah.

    Energy Technology Data Exchange (ETDEWEB)

    Chidsey, T.C. Jr.; Lorenz, D.M.; Culham, W.E.

    1997-10-15

    The primary objective of this project is to enhance domestic petroleum production by demonstration and technology transfer of an advanced oil recovery technology in the Paradox basin, southeastern Utah. If this project can demonstrate technical and economic feasibility, the technique can be applied to approximately 100 additional small fields in the Paradox basin alone, and result in increased recovery of 150 to 200 million barrels of oil. This project is designed to characterize five shallow-shelf carbonate reservoirs in the Pennsylvanian (Desmoinesian) Paradox Formation and choose the best candidate for a pilot demonstration project for either a waterflood or carbon dioxide- (CO{sub 2}-) flood project. The field demonstration, monitoring of field performance, and associated validation activities will take place in the Paradox basin within the Navajo Nation. The results of this project will be transferred to industry and other researchers through a petroleum extension service, creation of digital databases for distribution, technical workshops and seminars, field trips, technical presentations at national and regional professional meetings, and publication in newsletters and various technical or trade journals.

  19. Increased Oil Production and Reserves Utilizing Secondary/Tertiary Recovery Techniques on Small Reservoirs in the Paradox Basin, Utah

    Energy Technology Data Exchange (ETDEWEB)

    Allison, M. Lee; Chidsey, Jr., Thomas

    1999-11-03

    The primary objective of this project is to enhance domestic petroleum production by demonstration and technology transfer of an advanced oil recovery technology in the Paradox basin, southeastern Utah. If this project can demonstrate technical and economic feasibility, the technique can be applied to about 100 additional small fields in the Paradox basin alone, and result in increased recovery of 150 to 200 million bbl of oil. This project is designed to characterize five shallow-shelf carbonate reservoirs in the Pennsylvanian (Desmoinesian) Paradox Formation and choose the best candidate for a pilot demonstration project for either a waterflood or carbon dioxide-(CO-) flood 2 project. The field demonstration, monitoring of field performance, and associated validation activities will take place in the Paradox basin within the Navajo Nation. The results of this project will be transferred to industry and other researchers through a petroleum extension service, creation of digital databases for distribution, technical workshops and seminars, field trips, technical presentations at national and regional professional meetings, and publication in newsletters and various technical or trade journals.

  20. Increased Oil Production and Reserves Utilizing Secondary/Tertiary Recovery Techniques on Small Reservoirs in the Paradox Basin, Utah

    Energy Technology Data Exchange (ETDEWEB)

    Jr., Chidsey, Thomas C.; Allison, M. Lee

    1999-11-02

    The primary objective of this project is to enhance domestic petroleum production by field demonstration and technology transfer of an advanced- oil-recovery technology in the Paradox basin, southeastern Utah. If this project can demonstrate technical and economic feasibility, the technique can be applied to approximately 100 additional small fields in the Paradox basin alone, and result in increased recovery of 150 to 200 million barrels (23,850,000-31,800,000 m3) of oil. This project is designed to characterize five shallow-shelf carbonate reservoirs in the Pennsylvanian (Desmoinesian) Paradox Formation and choose the best candidate for a pilot demonstration project for either a waterflood or carbon-dioxide-(CO2-) miscible flood project. The field demonstration, monitoring of field performance, and associated validation activities will take place within the Navajo Nation, San Juan County, Utah.

  1. Pembina Cardium Field. Enhanced oil recovery economics. Proposed revisions to existing EOR incentives for low productivity reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    O' Keefe, J.J.; Howes, B.J.

    1985-07-01

    Technical analysis of miscibly flooding selected parts of the Pembina Cardium reservoir in Alberta indicates that substantial amounts of additional oil can be recovered, using a hydrocarbon solvent, from areas where little or no conglomerate zone is present. This represents approximately one-half of the total pool. Previous evaluations of the proposed miscible flood projects in the Pembina Cardium Field showed that a substantial enhanced oil recovery potential exists but that such projects were only marinally economic under the conditions that existed at the time. Subsequent to these evaluations, a number of significant changes have occurred. The Western Accord phased-out the Petroleum and Gas Revenue Tax and decontrolled the price of oil, world market forces have reduced oil prices, costs have declined, and a new royalty schedule has been introduced. This report analyzes the Pembina miscible flood economics in light of these changes. The combined effect of the changes is a slight improvement in project economics, which, however, remain marginal. Modifications to the existing Section 4.2 Royalty Deduction and to the earned depletion deduction are proposed with the goal of creating an economic environment that will allow the development of the Pembina Cardium enhanced oil recovery potential. The two projects evaluated in this report represent only a very small portion of the field, 8.3 km/sup 2/ out of field total of 1900 km/sup 2/. If economic considerations permitted the expansion of miscible flooding into the 50% of the Pembina Cardium reservoir considered to be amenable to the current miscible flood design, a very important contribution to oil supplies and economic activity in Canada would result. 6 figs., 26 tabs.

  2. Designing and Understanding of Fire Flooding in the later Phase of CSS in Heavy Oil Reservoir

    Institute of Scientific and Technical Information of China (English)

    2011-01-01

    Block G is a deeper thick-massive heavy oil reservoir.It is developed in 1986 by cyclic steam stimulation.After 22 years development,it’s reservoir pressure and oil production rate become lower and lower,production cost higher and higher,it is getting into the low-yielding and inefficient produced stage,urgently needing to search for more efficient mining technology to further enhance oil recovery.Block G is special-super deep heavy oil reservoir and its reservoir depth is 1540-1890m,which don’t suit for steam flooding and SAGD technology.In-situ combustion technology has a wide range of applications.Base on the characteristics of Block G that under large dip angle/thick layer,according to the parameters of fire flooding.Fire flooding pilot test started in May 2008,obtained obvious effect of increasing oil.Meanwhile there were a lot of problems,such as combustion front overlapping,injected air monolayer and one-way breakthrough,the swept efficiency decreases with combustion front improving,The paper analysis the pilot production and exited problem,and provide reference for next adjustment of Block G and fire flooding in the same type of reservoir.

  3. Evaluation of Reservoir Wettability and its Effect on Oil Recovery

    Energy Technology Data Exchange (ETDEWEB)

    Buckley, Jill S.

    2002-01-29

    The objectives of this five-year project were: (1) to achieve improved understanding of the surface and interfacial properties of crude oils and their interactions with mineral surfaces, (2) to apply the results of surface studies to improve predictions of oil production from laboratory measurements, and (3) to use the results of this research to recommend ways to improve oil recovery by waterflooding.

  4. SEISMIC DETERMINATION OF RESERVOIR HETEROGENEITY; APPLICATION TO THE CHARACTERIZATION OF HEAVY OIL RESERVOIRS

    Energy Technology Data Exchange (ETDEWEB)

    Matthias G. Imhof; James W. Castle

    2003-11-01

    The objective of the project is to examine how seismic and geologic data can be used to improve characterization of small-scale heterogeneity and their parameterization in reservoir models. The study is performed at West Coalinga Field in California. We continued our investigation on the nature of seismic reactions from heterogeneous reservoirs. We began testing our algorithm to infer parameters of object-based reservoir models from seismic data. We began integration of seismic and geologic data to determine the deterministic limits of conventional seismic data interpretation. Lastly, we began integration of seismic and geologic heterogeneity using stochastic models conditioned both on wireline and seismic data.

  5. Oil Reservoir Production Optimization using Single Shooting and ESDIRK Methods

    DEFF Research Database (Denmark)

    Capolei, Andrea; Völcker, Carsten; Frydendall, Jan;

    2012-01-01

    Conventional recovery techniques enable recovery of 10-50% of the oil in an oil field. Advances in smart well technology and enhanced oil recovery techniques enable significant larger recovery. To realize this potential, feedback model-based optimal control technologies are needed to manipulate...... the injections and oil production such that flow is uniform in a given geological structure. Even in the case of conventional water flooding, feedback based optimal control technologies may enable higher oil recovery than with conventional operational strategies. The optimal control problems that must be solved...... for sensitivity computation. We demonstrate the procedure on a water ooding example with conventional injectors and producers....

  6. Increasing Heavy Oil in the Wilmington Oil Fiel Through Advanced Reservoir Characterization and Thermal Production Technologies. Annual Report, March 30, 1995--March 31, 1996

    Energy Technology Data Exchange (ETDEWEB)

    Allison, Edith

    1996-12-01

    The objective of this project is to increase heavy oil reserves in a portion of the Wilmington Oil Field, near Long Beach, California, by implementing advanced reservoir characterization and thermal production technologies. Based on the knowledge and experience gained with this project, these technologies are intended to be extended to other sections of the Wilmington Oil Field, and, through technology transfer, will be available to increase heavy oil reserves in other slope and basin clastic (SBC) reservoirs.

  7. A Combined Thermodynamic and Kinetic Model for Barite Prediction at Oil Reservoir Conditions

    DEFF Research Database (Denmark)

    Zhen Wu, Bi Yun

    of this research was to develop a model, based on thermodynamics and kinetics, for predicting barite precipitation rates in saline waters at the pressures and temperatures of oil bearing reservoirs, using the geochemical modelling code PHREEQC. This task is complicated by the conditions where traditional methods....... Calculations for a well with seawater breakthrough results in an overestimation compared to scale samples, suggesting that significant amounts of barite precipitate in the reservoirs prior to entering to the wells. The combined model allows estimates of barite scaling rates that can be compared with field......In marine environments, barite (BaSO4) is a key proxy that has been used for understanding the biological and chemical evolution of oceans and for tracking the origin of fluids. In the oil industry, barite scale can clog pipelines and pores in the reservoirs, reducing oil yield. The goal...

  8. Analysis and applications of microorganisms from a chalk oil reservoir in the North Sea

    Energy Technology Data Exchange (ETDEWEB)

    Kaster, Krista Michelle

    2009-03-15

    Ekofisk a chalk oil reservoir in the Norwegian sector of the North Sea was found to harbour an active and diverse microbial community. Microbial actives may be deleterious in nature as in reservoir souring or maybe advantageous as in microbial enhanced oil recovery. The aim of this study was to characterise the microbial communities in the Ekofisk oil reservoir and to gain insight into the microbial mechanisms important for the a) control of reservoir souring, and b) which can be utilized in enhanced oil recovery. Produced water samples from the Ekofisk oil reservoir were analysed using both culture-dependent and -independent techniques. The Ekofisk microbial community was found to be dominated by thermophilic microorganisms many of which were capable of either sulphidogenic or methanogenic physiologies. They were similar to organisms that have been previously identified from oil reservoir fluids. The dominant organisms identified directly from the produced water samples had sequences similar to members of the genera Thermotoga, Caminicella, Thermoanaerobacter, Archaeoglobus, Thermococcus, and Methanobulbus. Enrichment cultures obtained from the produced water samples were dominated by sheathed rods. Sequence analyses of the cultures indicated predominance of the genera Petrotoga, Arcobacter, Archaeoglobus and Thermococcus. Reservoir souring caused by sulphide production due the activity of sulphate reducing prokaryotes (SRP) may be reduced by the injection of nitrate or nitrite. Nitrate or nitrite mitigates sulphide production either by the stimulation of nitrate reducing bacteria (NRB) through nitrate addition or via metabolic inhibition of the reduction of sulphite to sulphide by nitrite. Here we found that nitrate addition was ineffective at controlling souring whereas nitrite proved very effective at inhibiting sulphate reduction even at very low concentrations (0.25 mM - 1 mM) in both batch culture and bioreactor studies. To investigate microbial utilization

  9. Post Waterflood CO2 Miscible Flood in Light Oil, Fluvial-Dominated Deltaic Reservoir, Class I

    Energy Technology Data Exchange (ETDEWEB)

    Bou-Mikael, Sami

    2002-02-05

    This report demonstrates the effectiveness of the CO2 miscible process in Fluvial Dominated Deltaic reservoirs. It also evaluated the use of horizontal CO2 injection wells to improve the overall sweep efficiency. A database of FDD reservoirs for the gulf coast region was developed by LSU, using a screening model developed by Texaco Research Center in Houston. The results of the information gained in this project is disseminated throughout the oil industry via a series of SPE papers and industry open forums.

  10. Proceedings of the technical review on advances in geothermal reservoir technology---Research in progress

    Energy Technology Data Exchange (ETDEWEB)

    Lippmann, M.J. (ed.)

    1988-09-01

    This proceedings contains 20 technical papers and abstracts describing most of the research activities funded by the Department of Energy (DOE's) Geothermal Reservoir Technology Program, which is under the management of Marshall Reed. The meeting was organized in response to several requests made by geothermal industry representatives who wanted to learn more about technical details of the projects supported by the DOE program. Also, this gives them an opportunity to personally discuss research topics with colleagues in the national laboratories and universities.

  11. Super viscous oil reservoir formations of Ufa unit of Republic of Tatarstan and their properties

    Science.gov (United States)

    Osipova, D.; Vafin, R.; Surmashev, R.; Bondareva, O.

    2012-04-01

    Over 450 concentrations of super viscous oils (SVO) were discovered in Tatarstan for the time being. All of them are related to productive deposits of Permian period occurred at depths up to 300-400 metres consisting of terrigenous and carbonate deposits. Described are reservoir formations of the fields where recoverable reserves of SVO are confined by argillo-arenaceous thickness of Ufa terrigenous unit. Studying reservoir properties was based on laboratory analysis of core samples in terms of: Macro- and microscopic description, grain-size analysis, determination of effective porosity, permeability, volumetric and weight oil saturation, carbonate content, mineralogical density. According to macro-analysis data, thickness cross-section presents sandstones with rare interlayer and lenticle of siltstones and clays. The colour of calcareous sandstones varies from grey to black. Incoherent rocks prevail while closely consolidated types are rarely observed. The grain-size analysis revealed that 0.25-0.1 mm size grains are dominated in the sandstone composition, their concentration in rocks amounts to 69% that enables belonging oil rocks to fine-grained sandstones. Reservoir properties of rocks widely vary as follows: Effective porosity varies from 2.4 to 44.5% (average 31.5%), carbonate content from 0.6 to 30.1% (average 6.7%), mineralogical density from 2.3 to 3.3% (average 2.7%), and oil saturation from 0.1 to 14.9 rock weight % (average 7.8%). Reservoir porosities of reservoirs correlate to each other. Correlations between porosities are set in logarithmic values. Good direct correlation dependence (coefficient of correlation 0.5352) was identified between porosity and permeability as well as clear inverse relation between carbonate content and porosity (coefficient of correlation = - 0.7659). More tight positive correlation is observed for Porosity - Mass oil saturation (coefficient of correlation 0. 75087). This correlation indicates that super viscous oils are

  12. Terrestrial tight oil reservoir characteristics and Graded Resource Assessment in China

    Science.gov (United States)

    Wang, Shejiao; Wu, Xiaozhi; Guo, Giulin

    2016-04-01

    The success of shale/tight plays and the advanced exploitation technology applied in North America have triggered interest in exploring and exploiting tight oil in China. Due to the increased support of exploration and exploitation,great progress has been made in Erdos basin, Songliao basin, Junggar basin, Santanghu basin, Bohai Bay basin, Qaidam Basin, and Sichuan basin currently. China's first tight oil field has been found in Erdos basin in 2015, called xinanbian oil field, with over one hundred million tons oil reserves and one million tons of production scale. Several hundred million tons of tight oil reserve has been found in other basins, showing a great potential in China. Tight oil in China mainly developed in terrestrial sedimentary environment. According to the relations of source rock and reservoir, the source-reservoir combination of tight oil can be divided into three types, which are bottom generating and top storing tight oil,self- generating and self-storing tight oil,top generating and bottom storing tight oil. The self- generating and self-storing tight oil is the main type discovered at present. This type of tight oil has following characteristics:(1) The formation and distribution of tight oil are controlled by high quality source rocks. Terrestrial tight oil source rocks in China are mainly formed in the deep to half deep lacustrine facies. The lithology includes dark mudstone, shale, argillaceous limestone and dolomite. These source rocks with thickness between 20m-150m, kerogen type mostly I-II, and peak oil generation thermal maturity(Ro 0.6-1.4%), have great hydrocarbon generating potential. Most discovered tight oil is distributed in the area of TOC greater than 2 %.( 2) the reservoir with strong heterogeneity is very tight. In these low porosity and permeability reservoir,the resources distribution is controlled by the physical property. Tight sandstone, carbonate and hybrid sedimentary rocks are three main tight reservoir types in

  13. Evaluation of Reservoir Wettability and its Effect on Oil Recovery

    Energy Technology Data Exchange (ETDEWEB)

    Buckley, Jill S.

    1999-07-01

    The objective of this five-year project are: (1) to achieve improved understanding of the surface and interfacial properties of crude oils and their interactions with mineral surfaces, (2) to apply the results of surface studies to improve predictions of oil production from laboratory measurements, and (3) to use the results of this research to recommend ways to improve oil recovery by waterflooding. During the second year of this project we have tested the generality of the proposed mechanisms by which crude oil components can alter wetting. Using these mechanisms, we have begun a program of characterizing crude oils with respect to their wettability altering potential. Wettability assessment has been improved by replacing glass with mica as a standard surface material and crude oils have been used to alter wetting in simple square glass capillary tubes in which the subsequent imbibition of water can be followed visually.

  14. Study on distribution of reservoir endogenous microbe and oil displacement mechanism.

    Science.gov (United States)

    Yue, Ming; Zhu, Weiyao; Song, Zhiyong; Long, Yunqian; Song, Hongqing

    2017-02-01

    In order to research oil displacement mechanism by indigenous microbial communities under reservoir conditions, indigenous microbial flooding experiments using the endogenous mixed bacterium from Shengli Oilfield were carried out. Through microscopic simulation visual model, observation and analysis of distribution and flow of the remaining oil in the process of water flooding and microbial oil displacement were conducted under high temperature and high pressure conditions. Research has shown that compared with atmospheric conditions, the growth of the microorganism metabolism and attenuation is slowly under high pressure conditions, and the existence of the porous medium for microbial provides good adhesion, also makes its growth cycle extension. The microbial activities can effectively launch all kinds of residual oil, and can together with metabolites, enter the blind holes off which water flooding, polymer flooding and gas flooding can't sweep, then swap out remaining oil, increase liquidity of the crude oil and remarkably improve oil displacement effect.

  15. Rhamnolipids produced by indigenous Acinetobacter junii from petroleum reservoir and its potential in enhanced oil recovery

    Directory of Open Access Journals (Sweden)

    Hao Dong

    2016-11-01

    Full Text Available Biosurfactant producers are crucial for incremental oil production in microbial enhanced oil recovery (MEOR processes. The isolation of biosurfactant-producing bacteria from oil reservoirs is important because they are considered suitable for the extreme conditions of the reservoir. In this work, a novel biosurfactant-producing strain Acinetobacter junii BD was isolated from a reservoir to reduce surface tension and emulsify crude oil. The biosurfactants produced by the strain were purified and then identified via electrospray ionization-Fourier transform ion cyclotron resonance mass spectrometry (ESI FT-ICR-MS. The biosurfactants generated by the strain were concluded to be rhamnolipids, the dominant rhamnolipids were C26H48O9, C28H52O9 and C32H58O13. The optimal carbon source and nitrogen source for biomass and biosurfactant production were NaNO3 and soybean oil. The results showed that the content of acid components increased with the progress of crude oil biodegradation. A glass micromodel test demonstrated that the strain significantly increased oil recovery through interfacial tension reduction, wettability alteration and the mobility of microorganisms. In summary, the findings of this study indicate that the newly developed BD strain and its metabolites have great potential in MEOR.

  16. Rhamnolipids Produced by Indigenous Acinetobacter junii from Petroleum Reservoir and its Potential in Enhanced Oil Recovery.

    Science.gov (United States)

    Dong, Hao; Xia, Wenjie; Dong, Honghong; She, Yuehui; Zhu, Panfeng; Liang, Kang; Zhang, Zhongzhi; Liang, Chuanfu; Song, Zhaozheng; Sun, Shanshan; Zhang, Guangqing

    2016-01-01

    Biosurfactant producers are crucial for incremental oil production in microbial enhanced oil recovery (MEOR) processes. The isolation of biosurfactant-producing bacteria from oil reservoirs is important because they are considered suitable for the extreme conditions of the reservoir. In this work, a novel biosurfactant-producing strain Acinetobacter junii BD was isolated from a reservoir to reduce surface tension and emulsify crude oil. The biosurfactants produced by the strain were purified and then identified via electrospray ionization-Fourier transform ion cyclotron resonance mass spectrometry (ESI FT-ICR-MS). The biosurfactants generated by the strain were concluded to be rhamnolipids, the dominant rhamnolipids were C26H48O9, C28H52O9, and C32H58O13. The optimal carbon source and nitrogen source for biomass and biosurfactant production were NaNO3 and soybean oil. The results showed that the content of acid components increased with the progress of crude oil biodegradation. A glass micromodel test demonstrated that the strain significantly increased oil recovery through interfacial tension reduction, wettability alteration and the mobility of microorganisms. In summary, the findings of this study indicate that the newly developed BD strain and its metabolites have great potential in MEOR.

  17. Rhamnolipids Produced by Indigenous Acinetobacter junii from Petroleum Reservoir and its Potential in Enhanced Oil Recovery

    Science.gov (United States)

    Dong, Hao; Xia, Wenjie; Dong, Honghong; She, Yuehui; Zhu, Panfeng; Liang, Kang; Zhang, Zhongzhi; Liang, Chuanfu; Song, Zhaozheng; Sun, Shanshan; Zhang, Guangqing

    2016-01-01

    Biosurfactant producers are crucial for incremental oil production in microbial enhanced oil recovery (MEOR) processes. The isolation of biosurfactant-producing bacteria from oil reservoirs is important because they are considered suitable for the extreme conditions of the reservoir. In this work, a novel biosurfactant-producing strain Acinetobacter junii BD was isolated from a reservoir to reduce surface tension and emulsify crude oil. The biosurfactants produced by the strain were purified and then identified via electrospray ionization-Fourier transform ion cyclotron resonance mass spectrometry (ESI FT-ICR-MS). The biosurfactants generated by the strain were concluded to be rhamnolipids, the dominant rhamnolipids were C26H48O9, C28H52O9, and C32H58O13. The optimal carbon source and nitrogen source for biomass and biosurfactant production were NaNO3 and soybean oil. The results showed that the content of acid components increased with the progress of crude oil biodegradation. A glass micromodel test demonstrated that the strain significantly increased oil recovery through interfacial tension reduction, wettability alteration and the mobility of microorganisms. In summary, the findings of this study indicate that the newly developed BD strain and its metabolites have great potential in MEOR. PMID:27872613

  18. Analysis of methane production by microorganisms indigenous to a depleted oil reservoir for application in Microbial Enhanced Oil Recovery.

    Science.gov (United States)

    Kobayashi, Hajime; Kawaguchi, Hideo; Endo, Keita; Mayumi, Daisuke; Sakata, Susumu; Ikarashi, Masayuki; Miyagawa, Yoshihiro; Maeda, Haruo; Sato, Kozo

    2012-01-01

    We examined methane production by microorganisms collected from a depleted oilfield. Our results indicated that microorganisms indigenous to the petroleum reservoir could effectively utilize yeast extract, suggesting that the indigenous microorganisms and proteinaceous nutrients could be recruitable for Microbially Enhanced Oil Recovery. Copyright © 2011 The Society for Biotechnology, Japan. Published by Elsevier B.V. All rights reserved.

  19. Reservoir Protection Technology in China: Research & Application

    Institute of Scientific and Technical Information of China (English)

    Li Qiangui; Wu Juan; Kang Yili

    2006-01-01

    @@ Great development of reservoir protection technology (RPT) has been achieved since 1996, including oil and gas reservoir protection for exploration wells, reservoir protection during underbalanced drilling, protection of fractured tight sandstone gas reservoir, and reservoir protection while increase production and reconstructing, development and enhanced oil recovery (EOR) etc. It has stepped into a new situation with special features and advantage. These technical advancements marked that China's RTP have realized leaps from porous reservoirs to fractured reservoirs,from conventional medium-to-low permeability reservoirs to unconventional reservoirs, from oil and gas producers to exploration wells, and from application mainly in drilling and completion processes to application in stimulation,development, production and EOR processes.

  20. Stabilized oil production conditions in the development equilibrium of a water-flooding reservoir

    Directory of Open Access Journals (Sweden)

    Renshi Nie

    2016-12-01

    Full Text Available Water injection can compensate for pressure depletion of production. This paper firstly investigated into the equilibrium issue among water influx, water injection and production. Equilibrium principle was elaborated through deduction of equilibrium equation and presentation of equilibrium curves with an “equilibrium point”. Influences of artificial controllable factors (e.g. well ratio of injection to production and total well number on equilibrium were particularly analyzed using field data. It was found that the influences were mainly reflected as the location move of equilibrium point with factor change. Then reservoir pressure maintenance level was especially introduced to reveal the variation law of liquid rate and oil rate with the rising of water cut. It was also found that, even if reservoir pressure kept constant, oil rate still inevitably declined. However, in the field, a stabilized oil rate was always pursued for development efficiency. Therefore, the equilibrium issue of stabilized oil production was studied deeply through probing into some effective measures to realize oil rate stability after the increase of water cut for the example reservoir. Successful example application indicated that the integrated approach was very practical and feasible, and hence could be used to the other similar reservoir.

  1. Microorganisms in processes of the destruction of oil in reservoirs

    Directory of Open Access Journals (Sweden)

    A. A. Kurapov

    2010-01-01

    Full Text Available Pollution by oil has negative influence on all ecosystem of the sea. The main role in decomposing of hydrocarbons belongs to microorganisms. Influence emulsion and water repellencies of cellular walls of microorganisms on an oil destruction is noted.

  2. A Combined Thermodynamic and Kinetic Model for Barite Prediction at Oil Reservoir Conditions

    DEFF Research Database (Denmark)

    Zhen Wu, Bi Yun

    of the literature (PhD Study 1). The reviewed dataset was used as starting point for geochemical speciation modelling and applied to predict the stability of sulphate minerals in North Sea oil field brines. Second, for modelling of high salinity solutions using the Pitzer ion interaction approach, the temperature......In marine environments, barite (BaSO4) is a key proxy that has been used for understanding the biological and chemical evolution of oceans and for tracking the origin of fluids. In the oil industry, barite scale can clog pipelines and pores in the reservoirs, reducing oil yield. The goal...... of this research was to develop a model, based on thermodynamics and kinetics, for predicting barite precipitation rates in saline waters at the pressures and temperatures of oil bearing reservoirs, using the geochemical modelling code PHREEQC. This task is complicated by the conditions where traditional methods...

  3. Hydrocarbon charging histories of the Ordovician reservoir in the Tahe oil field, Tarim Basin, China

    Institute of Scientific and Technical Information of China (English)

    李纯泉; 陈红汉; 李思田; 张希明; 陈汉林

    2004-01-01

    The Ordovician reservoir of the Tahe oil field went through many tectonic reconstructions, and was charac-terized by multiple hydrocarbon chargings. The aim of this study was to unravel the complex charging histories. Systematicanalysis of fluid inclusions was employed to complete the investigation. Fluorescence observation of oil inclusions underUV light, and microthermometry of both oil and aqueous inclusions in 105 core samples taken from the Ordovician reservoirindicated that the Ordovician reservoir underwent four oil chargings and a gas charging. The hydrocarbon chargings oc-curred at the late Hercynian, the Indo-Sinian and Yanshan, the early Himalaya, the middle Himalaya, and the late Himalaya,respectively. The critical hydrocarbon charging time was at the late Hercynian.

  4. SEISMIC DETERMINATION OF RESERVOIR HETEROGENEITY: APPLICATION TO THE CHARACTERIZATION OF HEAVY OIL RESERVOIRS

    Energy Technology Data Exchange (ETDEWEB)

    Matthias G. Imhof; James W. Castle

    2005-02-01

    The objective of the project was to examine how seismic and geologic data can be used to improve characterization of small-scale heterogeneity and their parameterization in reservoir models. The study focused on West Coalinga Field in California. The project initially attempted to build reservoir models based on different geologic and geophysical data independently using different tools, then to compare the results, and ultimately to integrate them all. We learned, however, that this strategy was impractical. The different data and tools need to be integrated from the beginning because they are all interrelated. This report describes a new approach to geostatistical modeling and presents an integration of geology and geophysics to explain the formation of the complex Coalinga reservoir.

  5. SEISMIC DETERMINATION OF RESERVOIR HETEROGENEITY: APPLICATION TO THE CHARACTERIZATION OF HEAVY OIL RESERVOIRS

    Energy Technology Data Exchange (ETDEWEB)

    Matthias G. Imhof; James W. Castle

    2005-02-01

    The objective of the project was to examine how seismic and geologic data can be used to improve characterization of small-scale heterogeneity and their parameterization in reservoir models. The study focused on West Coalinga Field in California. The project initially attempted to build reservoir models based on different geologic and geophysical data independently using different tools, then to compare the results, and ultimately to integrate them all. Throughout the project, however, we learned that this strategy was impractical because the different data and model are complementary instead of competitive. For the complex Coalinga field, we found that a thorough understanding of the reservoir evolution through geologic times provides the necessary framework which ultimately allows integration of the different data and techniques.

  6. Reservoir engineering optimized techniques and applications research in initial development stage of a super shallow sea marginal oil field : Development case of Chengdao Oil Field in Bohai Bay, China

    Energy Technology Data Exchange (ETDEWEB)

    Yu, D.; Ren, Y.; Zhou, Y.; Wang, D. [Shengli Oil field Inc. (China). SINOPEC Corp.

    2002-06-01

    One of the greatest Chinese neritic marginal oil fields is the Chengdao oil field, located north of Dongying City, Shandong Province, China in the southern part of Bohai Bay. The depth of the seawater is less than 15 metres, even though the field lies 5 kilometres from shore. It falls in the category of super shallow sea marginal oil field, due to a number of reasons: peculiar geographical location, abominable environment and climate, complex reservoir characteristics and high economic risk of exploration and development. The major oil-bearing series of the Chengdao oil field is upper Guantao sandstones. The establishment of a three-dimensional conceptual model and static model in initial development stage were completed using Log-Constrained Seismic Inversion technique combined with three-dimensional visual geological model establishment technique. The optimization and determination of reservoir engineering technical limits, namely development scheme, well pattern and spacing, timing of water injection, water injection scheme and injection-to-production ratio was accomplished with the application of geostatistics, numerical simulation and economic evaluation techniques. For the period 1996-2001, the cumulative oil productivity of upper Guantao reservoir in pure natural energy development increased substantially. The results were presented in this paper. 3 refs., 6 tabs., 13 figs.

  7. Analysis of Proppant Hydraulic Fracturing in a Sand Oil Reservoir in Southwest of Iran

    OpenAIRE

    Reza Masoomi; Iniko Bassey; Dolgow Sergie Viktorovich; Hosein Dehghani

    2015-01-01

    Hydraulic fracturing is one way to increase the productivity of oil and gas wells. One of the most fundamental successes of hydraulic fracturing operation is selecting the proper size and type of proppants which are used during the process. The aim of this study is optimizing the type and size of used propant in hydraulic fracturing operation in a sand oil reservoir in southwest of Iran. In this study sand and ceramic (sintered bauxite) have been considered as proppant type. Also the various ...

  8. Use of modified nanoparticles in oil and gas reservoir management

    NARCIS (Netherlands)

    Turkenburg, D.H.; Chin, P.T.K.; Fischer, H.R.

    2012-01-01

    We describe a water dispersed nano sensor cocktail based on InP/ZnS quantum dots (QDs) and atomic silver clusters with a bright and visible luminescence combined with optimized sensor functionalities for the water flooding process. The QDs and Ag nano sensors were tested in simulated reservoir

  9. Characteristics of Chang 21 Low Permeability Sandstone Reservoir in Shunning Oil Field

    Institute of Scientific and Technical Information of China (English)

    WANG Jian-min; YU Liu-ying

    2006-01-01

    Characteristics of Chang 21 low permeability sandstone reservoir of Shunning oil field are analyzed and evaluated based on the data of well logging and experiment. The result shows that 1) the Chang 21 low permeability reservoir belongs to the classification of middle-to-fine sized feldspar sandstone, with its components being low in maturity, deposited in distributary rivers in the front of the delta; 2) the reservoir is obviously dominated by a low or a very low permeability with a linear variation tendency different from that of the ultra-low permeability reservoir; 3) the spatial variation in lithology and physical properties of the reservoir are controlled by the sedimentary facies zones, and 4)the physical property of the reservoir is significantly influenced by clastic constituents and their structure, and the constituent of cement materials and their content. The result also shows that the diagenesis action of the reservoir is quite strong in which dissolution greatly modified the reservoir In addition, the inter-granular dissolved pores are the mainly developed ones and the micro-structure is dominated by the combination of middle-to-large sized pores with fine-to-coarse throats. Finally, the radius of the throats is in good exponential correlation with permeability and the seepage capacity comes from those large sized throats.

  10. A combination of streamtube and geostatical simulation methodologies for the study of large oil reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Chakravarty, A.; Emanuel, A.S.; Bernath, J.A. [Chevron Petroleum Technology Company, LaHabra, CA (United States)

    1997-08-01

    The application of streamtube models for reservoir simulation has an extensive history in the oil industry. Although these models are strictly applicable only to fields under voidage balance, they have proved to be useful in a large number of fields provided that there is no solution gas evolution and production. These models combine the benefit of very fast computational time with the practical ability to model a large reservoir over the course of its history. These models do not, however, directly incorporate the detailed geological information that recent experience has taught is important. This paper presents a technique for mapping the saturation information contained in a history matched streamtube model onto a detailed geostatistically derived finite difference grid. With this technique, the saturation information in a streamtube model, data that is actually statistical in nature, can be identified with actual physical locations in a field and a picture of the remaining oil saturation can be determined. Alternatively, the streamtube model can be used to simulate the early development history of a field and the saturation data then used to initialize detailed late time finite difference models. The proposed method is presented through an example application to the Ninian reservoir. This reservoir, located in the North Sea (UK), is a heterogeneous sandstone characterized by a line drive waterflood, with about 160 wells, and a 16 year history. The reservoir was satisfactorily history matched and mapped for remaining oil saturation. A comparison to 3-D seismic survey and recently drilled wells have provided preliminary verification.

  11. Improving CO2 Efficiency for Recovering Oil in Heterogeneous Reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Grigg, Reid B.; Svec, Robert K.

    2003-03-10

    The work strived to improve industry understanding of CO2 flooding mechanisms with the ultimate goal of economically recovering more of the U.S. oil reserves. The principle interests are in the related fields of mobility control and injectivity.

  12. Application of Neuro-Net Technology to Reservoir Prediction in Chendao Oil Field

    Institute of Scientific and Technical Information of China (English)

    Jiang Suhua

    1996-01-01

    @@ Recently, the Research Institute of Geological Sciences of the Shengli oil region and the University of Petroleum have been cooperated in developing a set of intelligent expert system to predicte reservoir and to estimate sand body thickness using multiple seismic information.

  13. A mathematical model for preflush treatment in an oil reservoir using a fully miscible fluid

    NARCIS (Netherlands)

    F.J. Vermolen; G.-J. Pieters; P.L.J. Zitha; J. Bruining

    1999-01-01

    textabstractIn this paper we propose and analyse a mathematical model for preflush treatment in an oil reservoir. The model is based on two phase flow in which both phases are fully miscible. For the case of constant injection rate condition, fully implicit solutions can be constructed. Saturation p

  14. Integrated Reservoir Prediction and Oil-Gas Evaluation in the Maoshan Area

    Institute of Scientific and Technical Information of China (English)

    2000-01-01

    The Maoshan area is an area with well-developed igneous rocks and complex structures. The thickness of the reservoirs is generally small. The study of the reservoirs is based on seismic data, logging data and geological data. Using techniques and software such as Voxelgeo, BCI, RM, DFM and AP, the authors have made a comprehensive analysis of the lateral variation of reservoir parameters in the Upper Shazu bed of the third member of the Palaeogene Funing Formation, and compiled the thickness map of the Shazu bed. Also, with the data from ANN, BCI and the abstracting method for seismic characteristic parameters in combination with the structural factors, the authors have tried the multi-parameter and multi-method prediction of petroleum, delineated the potential oil and gas areas and proposed two well sites. The prediction of oil and gas for Well JB2 turns out to be quite successful.

  15. Reservoir characterization and enhanced oil recovery research. Annual report, September 1988--August 1989

    Energy Technology Data Exchange (ETDEWEB)

    Lake, L.W.; Pope, G.A.; Schechter, R.S.

    1992-03-01

    The research in this annual report falls into three tasks each dealing with a different aspect of enhanced oil recovery. The first task strives to develop procedures for accurately modeling reservoirs for use as input to numerical simulation flow models. This action describes how we have used a detail characterization of an outcrop to provide insights into what features are important to fluid flow modeling. The second task deals with scaling-up and modeling chemical and solvent EOR processes. In a sense this task is the natural extension of task 1 and, in fact, one of the subtasks uses many of the same statistical procedures for insight into the effects of viscous fingering and heterogeneity. The final task involves surfactants and their interactions with carbon dioxide and reservoir minerals. This research deals primarily with phenomena observed when aqueous surfactant solutions are injected into oil reservoirs.

  16. Permeability estimation for heavy oil reservoir: an alternative approach to avoid misleading tendencies

    Energy Technology Data Exchange (ETDEWEB)

    Rodriguez, L. [PDVSA (Venezuela)

    2011-07-01

    In oil production, characterization of the reservoir has to be undertaken in order to optimize the hydrocarbon production rate. Permeability is one of the most important parameters of a reservoir but estimation is difficult in heavy oil reservoirs and requires the use of multiple techniques. The objective of this paper was to evaluate the results of implementing a multi-scale permeability estimation method. Scale support effect and the physics of the measurements were looked into through a study which was conducted in Venezuela on two of PDVSA's fields, the Cerro Negro Field and the Morichal Field. Results showed that the proposed methodology captured efficiently the influence of parameters on permeability production and was successful in removing the local bias from the permeability data. The multi scale permeability estimation methodology was shown to address the issues encountered with a unique approach and to provide excellent results.

  17. WETTABILITY AND PREDICTION OF OIL RECOVERY FROM RESERVOIRS DEVELOPED WITH MODERN DRILLING AND COMPLETION FLUIDS

    Energy Technology Data Exchange (ETDEWEB)

    Jill S. Buckley; Norman R. Morrow

    2005-04-01

    Exposure to crude oil in the presence of an initial brine saturation can render rocks mixed-wet. Subsequent exposure to components of synthetic oil-based drilling fluids can alter the wetting toward less water-wet or more oil-wet conditions. Mixing of the non-aromatic base oils used in synthetic oil-based muds (SBM) with an asphaltic crude oil can destabilize asphaltenes and make cores less water-wet. Wetting changes can also occur due to contact with the surfactants used in SBM formulations to emulsify water and make the rock cuttings oil-wet. Reservoir cores drilled with SBMs, therefore, show wetting properties much different from the reservoir wetting conditions, invalidating laboratory core analysis using SBM contaminated cores. Core cleaning is required in order to remove all the drilling mud contaminants. In theory, core wettability can then be restored to reservoir wetting conditions by exposure to brine and crude oil. The efficiency of core cleaning of SBM contaminated cores has been explored in this study. A new core cleaning procedure was developed aimed to remove the adsorbed asphaltenes and emulsifiers from the contaminated Berea sandstone cores. Sodium hydroxide was introduced into the cleaning process in order to create a strongly alkaline condition. The high pH environment in the pore spaces changed the electrical charges of both basic and acidic functional groups, reducing the attractive interactions between adsorbing materials and the rock surface. In cores, flow-through and extraction methods were investigated. The effectiveness of the cleaning procedure was assessed by spontaneous imbibition tests and Amott wettability measurements. Test results indicating that introduction of sodium hydroxide played a key role in removing adsorbed materials were confirmed by contact angle measurements on similarly treated mica surfaces. Cleaning of the contaminated cores reversed their wettability from oil-wet to strongly water-wet as demonstrated by spontaneous

  18. Bacterial community diversity in a low-permeability oil reservoir and its potential for enhancing oil recovery.

    Science.gov (United States)

    Xiao, Meng; Zhang, Zhong-Zhi; Wang, Jing-Xiu; Zhang, Guang-Qing; Luo, Yi-Jing; Song, Zhao-Zheng; Zhang, Ji-Yuan

    2013-11-01

    The diversity of indigenous bacterial community and the functional species in the water samples from three production wells of a low permeability oil reservoir was investigated by high-throughput sequencing technology. The potential of application of indigenous bacteria for enhancing oil recovery was evaluated by examination of the effect of bacterial stimulation on the formation water-oil-rock surface interactions and micromodel test. The results showed that production well 88-122 had the most diverse bacterial community and functional species. The broth of indigenous bacteria stimulated by an organic nutrient activator at aerobic condition changed the wettability of the rock surface from oil-wet to water-wet. Micromodel test results showed that flooding using stimulated indigenous bacteria following water flooding improved oil recovery by 6.9% and 7.7% in fractured and unfractured micromodels, respectively. Therefore, the zone of low permeability reservoir has a great potential for indigenous microbial enhanced oil recovery. Copyright © 2013 Elsevier Ltd. All rights reserved.

  19. Oil-source correlation for the paleo-reservoir in the Majiang area and remnant reservoir in the Kaili area, South China

    Science.gov (United States)

    Fang, Yunxin; Liao, Yuhong; Wu, Liangliang; Geng, Ansong

    2011-05-01

    There are different viewpoints on the oil-source correlation of the Majiang paleo-reservoir and the neighbouring Kaili remnant reservoir in the Southern Guizhou Depression of China. Three potential source rocks in this depression could be inferred: the Lower-Cambrian marine mudstone, Lower-Silurian shale and Lower-Permian mudstone. Most of the potential source rocks are of high maturity. The solid bitumens and oil seepages in the Southern Guizhou Depression suffered severe secondary alterations, such as thermal degradation and biodegradation. The solid bitumens of the Majiang paleo-reservoir are also of high maturity. The oil seepages and soft bitumen of the Kaili remnant reservoir were severely biodegraded. All these secondary alterations may obscure oil-source correlations by routine biomarkers. Thus, it is very important to select appropriate biomarker parameters for the oil-source correlation. In this work, biomarkers resistant to thermal degradation and biodegradation and the data of organic carbon isotopic compositions were used for the correlation. The δ 13C values of n-alkanes in asphaltene pyrolysates were also used to make oil-oil and oil-source correlations between severely biodegraded oils. The results indicate that the Lower-Cambrian marine mudstones are the main source for the Ordovician-Silurian (O-S) solid bitumens of the Majiang area and the Ordovician-Silurian oil seepages and soft bitumens of the Kaili area. Remnant reservoir in the eastern Kaili area might have been charged at least twice by the oil generated from the Lower-Cambrian marine source rocks.

  20. Environmental Drivers of Differences in Microbial Community Structure in Crude Oil Reservoirs across a Methanogenic Gradient

    Science.gov (United States)

    Shelton, Jenna L.; Akob, Denise M.; McIntosh, Jennifer C.; Fierer, Noah; Spear, John R.; Warwick, Peter D.; McCray, John E.

    2016-01-01

    Stimulating in situ microbial communities in oil reservoirs to produce natural gas is a potentially viable strategy for recovering additional fossil fuel resources following traditional recovery operations. Little is known about what geochemical parameters drive microbial population dynamics in biodegraded, methanogenic oil reservoirs. We investigated if microbial community structure was significantly impacted by the extent of crude oil biodegradation, extent of biogenic methane production, and formation water chemistry. Twenty-two oil production wells from north central Louisiana, USA, were sampled for analysis of microbial community structure and fluid geochemistry. Archaea were the dominant microbial community in the majority of the wells sampled. Methanogens, including hydrogenotrophic and methylotrophic organisms, were numerically dominant in every well, accounting for, on average, over 98% of the total Archaea present. The dominant Bacteria groups were Pseudomonas, Acinetobacter, Enterobacteriaceae, and Clostridiales, which have also been identified in other microbially-altered oil reservoirs. Comparing microbial community structure to fluid (gas, water, and oil) geochemistry revealed that the relative extent of biodegradation, salinity, and spatial location were the major drivers of microbial diversity. Archaeal relative abundance was independent of the extent of methanogenesis, but closely correlated to the extent of crude oil biodegradation; therefore, microbial community structure is likely not a good sole predictor of methanogenic activity, but may predict the extent of crude oil biodegradation. However, when the shallow, highly biodegraded, low salinity wells were excluded from the statistical analysis, no environmental parameters could explain the differences in microbial community structure. This suggests that the microbial community structure of the 5 shallow, up-dip wells was different than the 17 deeper, down-dip wells. Also, the 17 down-dip wells

  1. Environmental Drivers of Differences in Microbial Community Structure in Crude Oil Reservoirs across a Methanogenic Gradient.

    Science.gov (United States)

    Shelton, Jenna L; Akob, Denise M; McIntosh, Jennifer C; Fierer, Noah; Spear, John R; Warwick, Peter D; McCray, John E

    2016-01-01

    Stimulating in situ microbial communities in oil reservoirs to produce natural gas is a potentially viable strategy for recovering additional fossil fuel resources following traditional recovery operations. Little is known about what geochemical parameters drive microbial population dynamics in biodegraded, methanogenic oil reservoirs. We investigated if microbial community structure was significantly impacted by the extent of crude oil biodegradation, extent of biogenic methane production, and formation water chemistry. Twenty-two oil production wells from north central Louisiana, USA, were sampled for analysis of microbial community structure and fluid geochemistry. Archaea were the dominant microbial community in the majority of the wells sampled. Methanogens, including hydrogenotrophic and methylotrophic organisms, were numerically dominant in every well, accounting for, on average, over 98% of the total Archaea present. The dominant Bacteria groups were Pseudomonas, Acinetobacter, Enterobacteriaceae, and Clostridiales, which have also been identified in other microbially-altered oil reservoirs. Comparing microbial community structure to fluid (gas, water, and oil) geochemistry revealed that the relative extent of biodegradation, salinity, and spatial location were the major drivers of microbial diversity. Archaeal relative abundance was independent of the extent of methanogenesis, but closely correlated to the extent of crude oil biodegradation; therefore, microbial community structure is likely not a good sole predictor of methanogenic activity, but may predict the extent of crude oil biodegradation. However, when the shallow, highly biodegraded, low salinity wells were excluded from the statistical analysis, no environmental parameters could explain the differences in microbial community structure. This suggests that the microbial community structure of the 5 shallow, up-dip wells was different than the 17 deeper, down-dip wells. Also, the 17 down-dip wells

  2. Environmental drivers of differences in microbial community structure in crude oil reservoirs across a methanogenic gradient

    Science.gov (United States)

    Shelton, Jenna L.; Akob, Denise M.; McIntosh, Jennifer C.; Fierer, Noah; Spear, John R.; Warwick, Peter D.; McCray, John E.

    2016-01-01

    Stimulating in situ microbial communities in oil reservoirs to produce natural gas is a potentially viable strategy for recovering additional fossil fuel resources following traditional recovery operations. Little is known about what geochemical parameters drive microbial population dynamics in biodegraded, methanogenic oil reservoirs. We investigated if microbial community structure was significantly impacted by the extent of crude oil biodegradation, extent of biogenic methane production, and formation water chemistry. Twenty-two oil production wells from north central Louisiana, USA, were sampled for analysis of microbial community structure and fluid geochemistry. Archaea were the dominant microbial community in the majority of the wells sampled. Methanogens, including hydrogenotrophic and methylotrophic organisms, were numerically dominant in every well, accounting for, on average, over 98% of the total Archaea present. The dominant Bacteria groups were Pseudomonas, Acinetobacter, Enterobacteriaceae, and Clostridiales, which have also been identified in other microbially-altered oil reservoirs. Comparing microbial community structure to fluid (gas, water, and oil) geochemistry revealed that the relative extent of biodegradation, salinity, and spatial location were the major drivers of microbial diversity. Archaeal relative abundance was independent of the extent of methanogenesis, but closely correlated to the extent of crude oil biodegradation; therefore, microbial community structure is likely not a good sole predictor of methanogenic activity, but may predict the extent of crude oil biodegradation. However, when the shallow, highly biodegraded, low salinity wells were excluded from the statistical analysis, no environmental parameters could explain the differences in microbial community structure. This suggests that the microbial community structure of the 5 shallow, up-dip wells was different than the 17 deeper, down-dip wells. Also, the 17 down-dip wells

  3. Feasibility Study on Steam and Gas Push with Dual Horizontal Wells in a Moderate-Depth Heavy Oil Reservoir

    OpenAIRE

    Jie Fan; Xiangfang Li; Tianjie Qin

    2016-01-01

    Non-condensable gas (NCG) with steam co-injection makes steam assisted gravity drainage less energy-intensive as well as reduces greenhouse gas emission and water consumption. Numerous studies have shown that the technology called steam and gas push (SAGP) is feasible for heavy oil and bitumen. However, most of these studies have focused on shallow heavy oil reservoirs and only a few works have investigated moderate-depth heavy oil reservoirs. In this study, laboratory experiments...

  4. Maximization of wave motion within a hydrocarbon reservoir for wave-based enhanced oil recovery

    KAUST Repository

    Jeong, C.

    2015-05-01

    © 2015 Elsevier B.V. We discuss a systematic methodology for investigating the feasibility of mobilizing oil droplets trapped within the pore space of a target reservoir region by optimally directing wave energy to the region of interest. The motivation stems from field and laboratory observations, which have provided sufficient evidence suggesting that wave-based reservoir stimulation could lead to economically viable oil recovery.Using controlled active surface wave sources, we first describe the mathematical framework necessary for identifying optimal wave source signals that can maximize a desired motion metric (kinetic energy, particle acceleration, etc.) at the target region of interest. We use the apparatus of partial-differential-equation (PDE)-constrained optimization to formulate the associated inverse-source problem, and deploy state-of-the-art numerical wave simulation tools to resolve numerically the associated discrete inverse problem.Numerical experiments with a synthetic subsurface model featuring a shallow reservoir show that the optimizer converges to wave source signals capable of maximizing the motion within the reservoir. The spectra of the wave sources are dominated by the amplification frequencies of the formation. We also show that wave energy could be focused within the target reservoir area, while simultaneously minimizing the disturbance to neighboring formations - a concept that can also be exploited in fracking operations.Lastly, we compare the results of our numerical experiments conducted at the reservoir scale, with results obtained from semi-analytical studies at the granular level, to conclude that, in the case of shallow targets, the optimized wave sources are likely to mobilize trapped oil droplets, and thus enhance oil recovery.

  5. IMPROVED OIL RECOVERY IN MISSISSIPPIAN CARBONATE RESERVOIRS OF KANSAS--NEAR TERM--CLASS 2

    Energy Technology Data Exchange (ETDEWEB)

    Timothy R. Carr; Don W. Green; G. Paul Willhite

    1999-06-01

    This annual report describes progress during the third year of the project entitled ''Improved Oil Recovery in Mississippian Carbonate Reservoirs in Kansas''. This project funded under the Department of Energy's Class 2 program targets improving the reservoir performance of mature oil fields located in shallow shelf carbonate reservoirs. The focus of this project is development and demonstration of cost-effective reservoir description and management technologies to extend the economic life of mature reservoirs in Kansas and the mid-continent. The project introduced a number of potentially useful technologies, and demonstrated these technologies in actual oil field operations. Advanced technology was tailored specifically to the scale appropriate to the operations of Kansas producers. An extensive technology transfer effort is ongoing. Traditional technology transfer methods (e.g., publications and workshops) are supplemented with a public domain relational database and an online package of project results that is available through the Internet. The goal is to provide the independent complete access to project data, project results and project technology on their desktop. Included in this report is a summary of significant project results at the demonstration site (Schaben Field, Ness County, Kansas). The value of cost-effective techniques for reservoir characterization and simulation at Schaben Field were demonstrated to independent operators. All major operators at Schaben have used results of the reservoir management strategy to locate and drill additional infill locations. At the Schaben Demonstration Site, the additional locations resulted in incremental production increases of 200 BOPD from a smaller number of wells.

  6. Improved Oil Recovery in Mississippian Carbonate Reservoirs of Kansas -- Near-Term -- Class 2

    Energy Technology Data Exchange (ETDEWEB)

    Carr, Timothy R.; Green, Don W.; Willhite, G. Paul

    1999-07-08

    This report describes progress during the third year of the project entitled ''Improved Oil Recovery in Mississippian Carbonate Reservoirs in Kansas''. This project funded under the Department of Energy's Class 2 program targets improving the reservoir performance of mature oil fields located in shallow shelf carbonate reservoirs. The focus of this project is development and demonstration of cost-effective reservoir description and management technologies to extend the economic life of mature reservoirs in Kansas and mid-continent. The project introduced a number of potentially useful technologies, and demonstrated these technologies in actual oil field operations. Advanced technology was tailored specifically to the scale appropriate to the operations of Kansas producers. An extensive technology transfer effort is ongoing. Traditional technology transfer methods (e.g., publications and workshops) are supplemented with a public domain relational database and an online package of project results that is available through the Internet. The goal is to provide the independent complete access to project data, project results and project technology on their desktop. Included in this report is a summary of significant project results at the demonstration site (Schaben Field, Ness County, Kansas). The value of cost-effective techniques for reservoir characterization and simulation at Schaben Field were demonstrated to independent operators. All major operators at Schaben have used results of the reservoir management strategy to locate and drill additional infill locations. At the Schaben Demonstration Site, the additional locations resulted in incremental production increases of 200 BOPD from a smaller number of wells.

  7. Optimization of Hydraulic Fracturing Fluid System in a Sand Oil Reservoir in Southwest of Iran

    Directory of Open Access Journals (Sweden)

    Reza Masoomi

    2015-10-01

    Full Text Available Fracturing fluid is one of the most important components of a hydraulic fracturing operation. Currently a lot of fluids are available for hydraulic fracturing. In order to selecting the most appropriate fracturing fluid for oil and gas wells with special characteristics, should be well understood fluid properties and should be informed about how changes in fluid properties to achieve the desired results. The aim of this study is optimization of viscosity and gel concentration in water base and foam base fluids which are used in hydraulic fracturing process in a sand oil reservoir in southwest of Iran. For this purpose various scenarios have been designed for various kinds of water base fluids and foam base fluids. Then the cumulative oil production has been estimated versus time and fracture half length. In addition the final required fracturing fluid and proppant have been determined for hydraulic fracturing in studied reservoir. Also in this study increasing the cumulative oil recovery in fractured and Non-fractured wells in a sand oil reservoir in southwest of Iran have been investigated.

  8. Performance of Surfactant Methyl Ester Sulphonate solution for Oil Well Stimulation in reservoir sandstone TJ Field

    Science.gov (United States)

    Eris, F. R.; Hambali, E.; Suryani, A.; Permadi, P.

    2017-05-01

    Asphaltene, paraffin, wax and sludge deposition, emulsion and water blocking are kinds ofprocess that results in a reduction of the fluid flow from the reservoir into formation which causes a decrease of oil wells productivity. Oil well Stimulation can be used as an alternative to solve oil well problems. Oil well stimulation technique requires applying of surfactant. Sodium Methyl Ester Sulphonate (SMES) of palm oil is an anionic surfactant derived from renewable natural resource that environmental friendly is one of potential surfactant types that can be used in oil well stimulation. This study was aimed at formulation SMES as well stimulation agent that can identify phase transitions to phase behavior in a brine-surfactant-oil system and altered the wettability of rock sandstone and limestone. Performance of SMES solution tested by thermal stability test, phase behavioral examination and rocks wettability test. The results showed that SMES solution (SMES 5% + xylene 5% in the diesel with addition of 1% NaCl at TJformation water and SMES 5% + xylene 5% in methyl ester with the addition of NaCl 1% in the TJ formation water) are surfactant that can maintain thermal stability, can mostly altered the wettability toward water-wet in sandstone reservoir, TJ Field.

  9. Sand Failure Mechanism and Sanding Parameters in Niger Delta Oil Reservoirs

    Directory of Open Access Journals (Sweden)

    Sunday Isehunwa,

    2010-05-01

    Full Text Available Sand production is a major issue during oil and gas production from unconsolidated reservoirs. In predicting the onset of sand production, it is important to accurately determine the failure mechanism and the contributing parameters. The aim of this study was to determine sand failure mechanism in the Niger-Delta, identify themajor contributing parameters and evaluate their effects on sanding.Completion and production data from 78 strings completed on 22 reservoirs in a Niger Delta oil Field were evaluated. Sand failure mechanisms and contributing parameters were identified and compared with published profiles. The results showed that cohesive stress is the predominant sand failure mechanism. Water cut, bean size and gas oil ratio (GOR impact sand production in the Niger Delta.

  10. Revitalizing a mature oil play: Strategies for finding and producing unrecovered oil in Frio Fluvial-Deltaic Sandstone Reservoirs of South Texas

    Energy Technology Data Exchange (ETDEWEB)

    McRae, L.E.; Holtz, M.H.; Knox, P.R.

    1995-07-01

    The Frio Fluvial-Deltaic Sandstone Play of South Texas is one example of a mature play where reservoirs are being abandoned at high rates, potentially leaving behind significant unrecovered resources in untapped and incompletely drained reservoirs. Nearly 1 billion barrels of oil have been produced from Frio reservoirs since the 1940`s, yet more than 1.6 BSTB of unrecovered mobile oil is estimated to remain in the play. Frio reservoirs of the South Texas Gulf Coast are being studied to better characterize interwell stratigraphic heterogeneity in fluvial-deltaic depositional systems and determine controls on locations and volumes of unrecovered oil. Engineering data from fields throughout the play trend were evaluated to characterize variability exhibited by these heterogeneous reservoirs and were used as the basis for resource calculations to demonstrate a large additional oil potential remaining within the play. Study areas within two separate fields have been selected in which to apply advanced reservoir characterization techniques. Stratigraphic log correlations, reservoir mapping, core analyses, and evaluation of production data from each field study area have been used to characterize reservoir variability present within a single field. Differences in sandstone depositional styles and production behavior were assessed to identify zones with significant stratigraphic heterogeneity and a high potential for containing unproduced oil. Detailed studies of selected reservoir zones within these two fields are currently in progress.

  11. Microbial diversity in degraded and non-degraded petroleum samples and comparison across oil reservoirs at local and global scales.

    Science.gov (United States)

    Sierra-Garcia, Isabel Natalia; Dellagnezze, Bruna M; Santos, Viviane P; Chaves B, Michel R; Capilla, Ramsés; Santos Neto, Eugenio V; Gray, Neil; Oliveira, Valeria M

    2017-01-01

    Microorganisms have shown their ability to colonize extreme environments including deep subsurface petroleum reservoirs. Physicochemical parameters may vary greatly among petroleum reservoirs worldwide and so do the microbial communities inhabiting these different environments. The present work aimed at the characterization of the microbiota in biodegraded and non-degraded petroleum samples from three Brazilian reservoirs and the comparison of microbial community diversity across oil reservoirs at local and global scales using 16S rRNA clone libraries. The analysis of 620 16S rRNA bacterial and archaeal sequences obtained from Brazilian oil samples revealed 42 bacterial OTUs and 21 archaeal OTUs. The bacterial community from the degraded oil was more diverse than the non-degraded samples. Non-degraded oil samples were overwhelmingly dominated by gammaproteobacterial sequences with a predominance of the genera Marinobacter and Marinobacterium. Comparisons of microbial diversity among oil reservoirs worldwide suggested an apparent correlation of prokaryotic communities with reservoir temperature and depth and no influence of geographic distance among reservoirs. The detailed analysis of the phylogenetic diversity across reservoirs allowed us to define a core microbiome encompassing three bacterial classes (Gammaproteobacteria, Clostridia, and Bacteroidia) and one archaeal class (Methanomicrobia) ubiquitous in petroleum reservoirs and presumably owning the abilities to sustain life in these environments.

  12. WETTABILITY AND PREDICTION OF OIL RECOVERY FROM RESERVOIRS DEVELOPED WITH MODERN DRILLING AND COMPLETION FLUIDS

    Energy Technology Data Exchange (ETDEWEB)

    Jill S. Buckley; Norman R. Morrow

    2003-05-01

    This report summarizes the experimental results of some baseline imbibition tests on recovery of mineral oil at very strongly water wet conditions (VSWW) from sandstones with air permeability ranging from 80 to 360 md. Mixed wettability cores were prepared by adsorption from either Minnelusa or Gullfaks crude oil using either synthetic Minnelusa reservoir brine or sea water. Recovery of two synthetic-based mud (SBM) base oils, Petrofree(reg sign)SF and LVT 200 from mixed wettability cores gave results that correlated closely with results for refined oils with viscosities ranging from 3.8 to 84 cp. Two synthetic-based mud emulsifiers (LE SUPERMUL and EZ MUL(reg sign)NT) were added to mineral oil and tested for their effect on the wettability of MXW-F core samples as indicated by spontaneous imbibition. In both cases a significant decrease in water wetness was obtained.

  13. Investigation of biosurfactant-producing indigenous microorganisms that enhance residue oil recovery in an oil reservoir after polymer flooding.

    Science.gov (United States)

    She, Yue-Hui; Zhang, Fan; Xia, Jing-Jing; Kong, Shu-Qiong; Wang, Zheng-Liang; Shu, Fu-Chang; Hu, Ji-Ming

    2011-01-01

    Three biosurfactant-producing indigenous microorganisms (XDS1, XDS2, XDS3) were isolated from a petroleum reservoir in the Daqing Oilfield (China) after polymer flooding. Their metabolic, biochemical, and oil-degradation characteristics, as well as their oil displacement in the core were studied. These indigenous microorganisms were identified as short rod bacillus bacteria with white color, round shape, a protruding structure, and a rough surface. Strains have peritrichous flagella, are able to produce endospores, are sporangia, and are clearly swollen and terminal. Bacterial cultures show that the oil-spreading values of the fermentation fluid containing all three strains are more than 4.5 cm (diameter) with an approximate 25 mN/m surface tension. The hydrocarbon degradation rates of each of the three strains exceeded 50%, with the highest achieving 84%. Several oil recovery agents were produced following degradation. At the same time, the heavy components of crude oil were degraded into light components, and their flow characteristics were also improved. The surface tension and viscosity of the crude oil decreased after being treated by the three strains of microorganisms. The core-flooding tests showed that the incremental oil recoveries were 4.89-6.96%. Thus, XDS123 treatment may represent a viable method for microbial-enhanced oil recovery.

  14. Utilizing natural gas huff and puff to enhance production in heavy oil reservoir

    Energy Technology Data Exchange (ETDEWEB)

    Wenlong, G.; Shuhong, W.; Jian, Z.; Xialin, Z. [Society of Petroleum Engineers, Kuala Lumpur (Malaysia)]|[PetroChina Co. Ltd., Beijing (China); Jinzhong, L.; Xiao, M. [China Univ. of Petroleum, Beijing (China)

    2008-10-15

    The L Block in the north structural belt of China's Tuha Basin is a super deep heavy oil reservoir. The gas to oil ratio (GOR) is 12 m{sup 3}/m{sup 3} and the initial bubble point pressure is only 4 MPa. The low production can be attributed to high oil viscosity and low flowability. Although steam injection is the most widely method for heavy oil production in China, it is not suitable for the L Block because of its depth. This paper reviewed pilot tests in which the natural gas huff and puff process was used to enhance production in the L Block. Laboratory experiments that included both conventional and unconventional PVT were conducted to determine the physical property of heavy oil saturated by natural gas. The experiments revealed that the heavy oil can entrap the gas for more than several hours because of its high viscosity. A pseudo bubble point pressure exists much lower than the bubble point pressure in manmade foamy oils, which is relative to the depressurization rate. Elastic energy could be maintained in a wider pressure scope than natural depletion without gas injection. A special experimental apparatus that can stimulate the process of gas huff and puff in the reservoir was also introduced. The foamy oil could be seen during the huff and puff experiment. Most of the oil flowed to the producer in a pseudo single phase, which is among the most important mechanisms for enhancing production. A pilot test of a single well demonstrated that the oil production increased from 1 to 2 cubic metres per day to 5 to 6 cubic metres per day via the natural gas huff and puff process. The stable production period which was 5 to 10 days prior to huff and puff, was prolonged to 91 days in the first cycle and 245 days in the second cycle. 10 refs., 1 tab., 12 figs.

  15. The influence of lumping on the behavior of reservoir with light oil and CO2

    Energy Technology Data Exchange (ETDEWEB)

    Scanavini, Helena Finardi Alvares [Universidade Estadual de Campinas (UNISIM/UNICAMP), SP (Brazil). Dept. de Engenharia de Petroleo. Pesquisa em Simulacao e Gerenciamento de Reservatorios; Schiozer, Denis Jose [Universidade Estadual de Campinas (DEP/FEM/UNICAMP), SP (Brazil). Fac. de Engenharia Mecanica. Dept. de Engenharia de Petroleo

    2012-07-01

    Compositional simulation demands a large number of equations and functions to be solved, once fluid properties depend on reservoir pressure and temperature and also on fluid composition. As a consequence, the number of components used influences considerably in the simulation run time and accuracy: more components yield more equations to be solved with expected higher run time. Giant petroleum fields discovered recently in Brazil (pre-salt reservoirs) demand compositional simulation due to the fluid characteristics (light oil with the presence of CO2). However, the computational time can be a limitation because of the number of grid blocks that are necessary to represent the reservoir. So, reducing the number of components is an important step for the simulation models. Under this context, this paper presents a study on the influence of different lumping clusters, used to reduce the number of components in a volatile oil, on reservoir simulation. Phase diagram, saturation pressure and simulation results were used for comparison purposes. The best results were obtained for the cases with 14, 9 and 7 pseudo components, which represented correctly the original fluid, reducing till three times the simulation run time, for the same production volumes of oil and gas. (author)

  16. Productivity Analysis of Volume Fractured Vertical Well Model in Tight Oil Reservoirs

    Directory of Open Access Journals (Sweden)

    Jiahang Wang

    2017-01-01

    Full Text Available This paper presents a semianalytical model to simulate the productivity of a volume fractured vertical well in tight oil reservoirs. In the proposed model, the reservoir is a composite system which contains two regions. The inner region is described as formation with finite conductivity hydraulic fracture network and the flow in fracture is assumed to be linear, while the outer region is simulated by the classical Warren-Root model where radial flow is applied. The transient rate is calculated, and flow patterns and characteristic flowing periods caused by volume fractured vertical well are analyzed. Combining the calculated results with actual production data at the decline stage shows a good fitting performance. Finally, the effects of some sensitive parameters on the type curves are also analyzed extensively. The results demonstrate that the effect of fracture length is more obvious than that of fracture conductivity on improving production in tight oil reservoirs. When the length and conductivity of main fracture are constant, the contribution of stimulated reservoir volume (SRV to the cumulative oil production is not obvious. When the SRV is constant, the length of fracture should also be increased so as to improve the fracture penetration and well production.

  17. Oil reservoirs in grainstone aprons around Bryozoan Mounds, Upper Harrodsburg Limestone, Mississippian, Illinois Basin

    Energy Technology Data Exchange (ETDEWEB)

    Jobe, H. [UNOCAL Energy Resources, Sugar Land, TX (United States); Saller, A. [UNOCAL Energy Resources, Brea, CA (United States)

    1995-06-01

    Several oil pools have been discovered recently in the upper Harrodsburg Limestone (middle Mississippian) of the Illinois basin. A depositional model for bryozoan mound complexes has allowed more successful exploration and development in this play. In the Johnsonville area of Wayne County, Illinois, three lithofacies are dominant in the upper Harrodsburg: (1) bryozoan boundstones, (2) bryozoan grainstones, and (3) fossiliferous wackestones. Bryozoan boundstones occur as discontinuous mounds and have low porosity. Although bryozoan boundstones are not the main reservoir lithofacies, they are important because they influenced the distribution of bryozoan grainstones and existing structure. Bryozoan grainstones have intergranular porosity and are the main reservoir rock. Bryozoan fragments derived from bryozoan boundstone mounds were concentrated in grainstones around the mounds. Fossiliferous wackestones are not porous and form vertical and lateral seals for upper Harrodsburg grainstones. Fossiliferous wackestones were deposited in deeper water adjacent to bryozoan grainstone aprons, and above grainstones and boundstones after the mounds were drowned. Upper Harrodsburg oil reservoirs occur where grainstone aprons are structurally high. The Harrodsburg is a good example of a carbonate mound system where boundstone cores are not porous, but adjacent grainstones are porous. Primary recovery in these upper Harrodsburg reservoirs is improved by strong pressure support from an aquifer in the lower Harrodsburg. Unfortunately, oil production is commonly decreased by water encroaching from that underlying aquifer.

  18. Terahertz-dependent identification of simulated hole shapes in oil-gas reservoirs

    Science.gov (United States)

    Bao, Ri-Ma; Zhan, Hong-Lei; Miao, Xin-Yang; Zhao, Kun; Feng, Cheng-Jing; Dong, Chen; Li, Yi-Zhang; Xiao, Li-Zhi

    2016-10-01

    Detecting holes in oil-gas reservoirs is vital to the evaluation of reservoir potential. The main objective of this study is to demonstrate the feasibility of identifying general micro-hole shapes, including triangular, circular, and square shapes, in oil-gas reservoirs by adopting terahertz time-domain spectroscopy (THz-TDS). We evaluate the THz absorption responses of punched silicon (Si) wafers having micro-holes with sizes of 20 μm-500 μm. Principal component analysis (PCA) is used to establish a model between THz absorbance and hole shapes. The positions of samples in three-dimensional spaces for three principal components are used to determine the differences among diverse hole shapes and the homogeneity of similar shapes. In addition, a new Si wafer with the unknown hole shapes, including triangular, circular, and square, can be qualitatively identified by combining THz-TDS and PCA. Therefore, the combination of THz-TDS with mathematical statistical methods can serve as an effective approach to the rapid identification of micro-hole shapes in oil-gas reservoirs. Project supported by the National Natural Science Foundation of China (Grant No. 61405259), the National Basic Research Program of China (Grant No. 2014CB744302), and the Specially Founded Program on National Key Scientific Instruments and Equipment Development, China (Grant No. 2012YQ140005).

  19. Characterization of oil and gas reservoir heterogeneity; Final report, November 1, 1989--June 30, 1993

    Energy Technology Data Exchange (ETDEWEB)

    Sharma, G.D.

    1993-09-01

    The Alaskan North Slope comprises one of the Nation`s and the world`s most prolific oil province. Original oil in place (OOIP) is estimated at nearly 70 BBL (Kamath and Sharma, 1986). Generalized reservoir descriptions have been completed by the University of Alaska`s Petroleum Development Laboratory over North Slope`s major fields. These fields include West Sak (20 BBL OOIP), Ugnu (15 BBL OOIP), Prudhoe Bay (23 BBL OOIP), Kuparuk (5.5 BBL OOIP), Milne Point (3 BBL OOIP), and Endicott (1 BBL OOIP). Reservoir description has included the acquisition of open hole log data from the Alaska Oil and Gas Conservation Commission (AOGCC), computerized well log analysis using state-of-the-art computers, and integration of geologic and logging data. The studies pertaining to fluid characterization described in this report include: experimental study of asphaltene precipitation for enriched gases, CO{sup 2} and West Sak crude system, modeling of asphaltene equilibria including homogeneous as well as polydispersed thermodynamic models, effect of asphaltene deposition on rock-fluid properties, fluid properties of some Alaskan north slope reservoirs. Finally, the last chapter summarizes the reservoir heterogeneity classification system for TORIS and TORIS database.

  20. Environmental drivers of differences in microbial community structure in crude oil reservoirs across a methanogenic gradient

    Directory of Open Access Journals (Sweden)

    Jenna L Shelton

    2016-09-01

    Full Text Available Stimulating in situ microbial communities in oil reservoirs to produce natural gas is a potentially viable strategy for recovering additional fossil fuel resources following traditional recovery operations. Little is known about what geochemical parameters drive microbial population dynamics in biodegraded, methanogenic oil reservoirs. We investigated if microbial community structure was significantly impacted by the extent of crude oil biodegradation, extent of biogenic methane production, and formation water chemistry. Twenty-two oil production wells from north central Louisiana, USA, were sampled for analysis of microbial community structure and fluid geochemistry. Archaea were the dominant microbial community in the majority of the wells sampled. Methanogens, including hydrogenotrophic and methylotrophic organisms, were numerically dominant in every well, accounting for, on average, over 98% of the total archaea present. The dominant Bacteria groups were Pseudomonas, Acinetobacter, Enterobacteriaceae, and Clostridiales, which have also been identified in other microbially-altered oil reservoirs. Comparing microbial community structure to fluid (gas, water, and oil geochemistry revealed that the relative extent of biodegradation, salinity, and spatial location were the major drivers of microbial diversity. Archaeal relative abundance was independent of the extent of methanogenesis, but closely correlated to the extent of crude oil biodegradation; therefore, microbial community structure is likely not a good sole predictor of methanogenic activity, but may predict the extent of crude oil biodegradation. However, when the shallow, highly biodegraded, low salinity wells were excluded from the statistical analysis, no environmental parameters could explain the differences in microbial community structure. This suggests that the microbial community structure of the 5 shallow up-dip wells was different than the 17 deeper, down-dip wells, and that

  1. Increasing heavy oil reserves in the Wilmington Oil Field through advanced reservoir characterization and thermal production technologies. Annual report, March 30, 1995--March 31, 1996

    Energy Technology Data Exchange (ETDEWEB)

    NONE

    1997-09-01

    The objective of this project is to increase heavy oil reserves in a portion of the Wilmington Oil Field, near Long Beach, California, by implementing advanced reservoir characterization and thermal production technologies. Based on the knowledge and experience gained with this project, these technologies are intended to be extended to other sections of the Wilmington Oil Field, and, through technology transfer, will be available to increase heavy oil reserves in other slope and basin clastic (SBC) reservoirs. The project involves implementing thermal recovery in the southern half of the Fault Block II-A Tar zone. The existing steamflood in Fault Block II-A has been relatively inefficient due to several producibility problems which are common in SBC reservoirs. Inadequate characterization of the heterogeneous turbidite sands, high permeability thief zones, low gravity oil, and nonuniform distribution of remaining oil have all contributed to poor sweep efficiency, high steam-oil ratios, and early steam breakthrough. Operational problems related to steam breakthrough, high reservoir pressure, and unconsolidated formation sands have caused premature well and downhole equipment failures. In aggregate, these reservoir and operational constraints have resulted in increased operating costs and decreased recoverable reserves. A suite of advanced reservoir characterization and thermal production technologies are being applied during the project to improve oil recovery efficiency and reduce operating costs.

  2. Origin of the Silurian Crude Oils and Reservoir Formation Characteristics in the Tazhong Uplift

    Institute of Scientific and Technical Information of China (English)

    YANG Haijun; LI Sumei; PANG Xiongqi; XIAO Zhongyao; GU Qiaoyuan; ZHANG Baoshou

    2010-01-01

    The Silurian stratum in the Tazhong uplift is an important horizon for exploration because it preserves some features of the hydrocarbons produced from multi-stage tectonic evolution.For this reason,the study of the origin of the Silurian oils and their formation characteristics constitutes a major part in revealing the mechanisms for the composite hydrocarbon accumulation zone in the Tazhong area.Geochemical investigations indicate that the physical properties of the Silurian oils in Tazhong vary with belts and blocks,i.e.,heavy oils are distributed in the TZ47-15 well-block in the North Slope while normal and light oils in the No.I fault belt and the TZ16 well-block,which means that the oil properties are controlled by structural patterns.Most biomarkers in the Silurian oils are similar to that of the Mid-Upper Ordovician source rocks,suggesting a good genetic relationship.However,the compound specific isotope of n-alkanes in the oils and the chemical components of the hydrocarbons in fluid inclusions indicate that these oils are mixed oils derived from both the MidUpper Ordovician and the Cambrian-Lower Ordovician source rocks.Most Silurian oils have a record of secondary alterations like earlier biodegradation,including the occurrence of "UCM" humps in the total ion current (TIC) chromatogram of saturated and aromatic hydrocarbons and 25-norhopane in saturated hydrocarbons of the crude oils,and regular changes in the abundances of light and heavy components from the structural low to the structural high.The fact that the Silurian oils are enriched in chain alkanes,e.g.,n.alkanes and 25-norhopane,suggests that they were mixed oils of the earlier degraded oils with the later normal oils.It is suggested that the Silurian oils experienced at least three episodes of petroleum charging according to the composition and distribution as well as the maturity of reservoir crude oils and the oils in fluid inclusions.The migration and accumulation models of these oils in

  3. Simulation study to determine the feasibility of injecting hydrogen sulfide, carbon dioxide and nitrogen gas injection to improve gas and oil recovery oil-rim reservoir

    Science.gov (United States)

    Eid, Mohamed El Gohary

    This study is combining two important and complicated processes; Enhanced Oil Recovery, EOR, from the oil rim and Enhanced Gas Recovery, EGR from the gas cap using nonhydrocarbon injection gases. EOR is proven technology that is continuously evolving to meet increased demand and oil production and desire to augment oil reserves. On the other hand, the rapid growth of the industrial and urban development has generated an unprecedented power demand, particularly during summer months. The required gas supplies to meet this demand are being stretched. To free up gas supply, alternative injectants to hydrocarbon gas are being reviewed to support reservoir pressure and maximize oil and gas recovery in oil rim reservoirs. In this study, a multi layered heterogeneous gas reservoir with an oil rim was selected to identify the most optimized development plan for maximum oil and gas recovery. The integrated reservoir characterization model and the pertinent transformed reservoir simulation history matched model were quality assured and quality checked. The development scheme is identified, in which the pattern and completion of the wells are optimized to best adapt to the heterogeneity of the reservoir. Lateral and maximum block contact holes will be investigated. The non-hydrocarbon gases considered for this study are hydrogen sulphide, carbon dioxide and nitrogen, utilized to investigate miscible and immiscible EOR processes. In November 2010, re-vaporization study, was completed successfully, the first in the UAE, with an ultimate objective is to examine the gas and condensate production in gas reservoir using non hydrocarbon gases. Field development options and proces schemes as well as reservoir management and long term business plans including phases of implementation will be identified and assured. The development option that maximizes the ultimate recovery factor will be evaluated and selected. The study achieved satisfactory results in integrating gas and oil

  4. Potential application of oxygen containing gases to enhance gravity drainage in heavy oil bearing reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Lakatos, I. [Hungarian Academy of Sciences, Miscolc (Hungary). Lab. for Mining Chemistry; Bauer, K. [Hungarian Academy of Sciences, Miscolc (Hungary). Lab. for Mining Chemistry; Lakatos-Szabo, J. [Hungarian Academy of Sciences, Miscolc (Hungary). Lab. for Mining Chemistry

    1997-06-01

    In the frame of laboratory studies the effect of air/natural CO{sub 2} mixtures on chemical composition of crude oil and gas phase, the rheological and interfacial properties, the flow mechanism and the safety measures were analyzed. The tests were performed at reservoir conditions (200 bar and 109 C) using natural rock, oil and gas samples. The oxygen content of the gas phase and the gas/oil ratio varied within wide limits. Both crude and asphaltene-free oil were used to determine the consequences of the low temperature oxidation. On the basis of the experimental results it was found that the oxygen content of the cap gas had been completely consumed by the chemical reactions (oxidation, condensation and water formation) before the asphaltene content set in equilibrium. Nearly 9% excess asphaltene formation was observed in both the crude and the asphaltene-free oils. The substantial increase in asphaltene content and the presence of colloidal water results in a measurable change in rheological and interfacial properties. Despite these factors the flow and displacement mechanism is only slightly influenced if the reservoir is of fractured character. On the other hand the in-situ oxidation of this heavy crude oil improves the efficiency of bitumen production and the quality of product used mostly for road construction. As a final statement, it was concluded that replacing the CO{sub 2} with oxygen containing inert gas, the chemical reactions can be in-situ regulated without jeopardizing the recovery efficiency. Application of the artificial gas cap concept opens new perspectives in EOR technology of karstic and fractured reservoirs containing medium and heavy crude oils in those cases where CO{sub 2} or CH gas is not available. (orig./MSK)

  5. Nonlinear Model Predictive Control for Oil Reservoirs Management

    DEFF Research Database (Denmark)

    Capolei, Andrea

    . With this objective function we link the optimization problem in production optimization to the Markowitz portfolio optimization problem in finance or to the the robust design problem in topology optimization. In this study we focus on open-loop configuration, i.e. without measurement feedback. We demonstrate......, the research community is working on improving current feedback model-based optimal control technologies. The topic of this thesis is production optimization for water flooding in the secondary phase of oil recovery. We developed numerical methods for nonlinear model predictive control (NMPC) of an oil field....... Further, we studied the use of robust control strategies in both open-loop, i.e. without measurement feedback, and closed-loop, i.e. with measurement feedback, configurations. This thesis has three main original contributions: The first contribution in this thesis is to improve the computationally...

  6. Characterization of oil and gas reservoir heterogeneity. Annual report, November 1, 1990--October 31, 1991

    Energy Technology Data Exchange (ETDEWEB)

    1991-12-31

    The objective of the cooperative research program is to characterize Alaskan reservoirs in terms of their reserves, physical and chemical properties, geologic configuration and structure, and the development potential. The tasks completed during this period include: (1) geologic reservoir description of Endicott Field; (2) petrographic characterization of core samples taken from selected stratigraphic horizons of the West Sak and Ugnu (Brookian) wells; (3) development of a polydispersed thermodynamic model for predicting asphaltene equilibria and asphaltene precipitation from crude oil-solvent mixtures, and (4) preliminary geologic description of the Milne Point Unit.

  7. Quantitative Methods for Reservoir Characterization and Improved Recovery: Application to Heavy Oil Sands

    Energy Technology Data Exchange (ETDEWEB)

    Castle, James W.; Molz, Fred W.; Bridges, Robert A.; Dinwiddie, Cynthia L.; Lorinovich, Caitlin J.; Lu, Silong

    2003-02-07

    This project involved application of advanced analytical property-distribution methods conditioned to continuous outcrop control for improved reservoir characterization and simulation. The investigation was performed in collaboration with Chevron Production Company U.S.A. as an industrial partner, and incorporates data from the Temblor Formation in Chevron's West Coalinga Field, California. Improved prediction of interwell reservoir heterogeneity was needed to increase productivity and to reduce recovery cost for California's heavy oil sands, which contained approximately 2.3 billion barrels of remaining reserves in the Temblor Formation and in other formations of the San Joaquin Valley.

  8. Improved oil recovery in fluvial dominated reservoirs of Kansas--near-term. Annual report

    Energy Technology Data Exchange (ETDEWEB)

    Green, D.W.; Willhite, G.P.; Walton, A.; Schoeling, L.; Reynolds, R.; Michnick, M.; Watney, L.

    1996-11-01

    Common oil field problems exist in fluvial dominated deltaic reservoirs in Kansas. The problems are poor waterflood sweep efficiency and lack of reservoir management. The poor waterflood sweep efficiency is due to (1) reservoir heterogeneity, (2) channeling of injected water through high permeability zones or fractures, and (3) clogging of injection wells due to solids in the injection water. In many instances the lack of reservoir management results from (1) poor data collection and organization, (2) little or no integrated analysis of existing data by geological and engineering personnel, (3) the presence of multiple operators within the field, and (4) not identifying optimum recovery techniques. Two demonstration sites operated by different independent oil operators are involved in this project. The Stewart Field is located in Finney County, Kansas and is operated by North American Resources Company. This field was in the latter stage of primary production at the beginning of this project and is currently being waterflooded as a result of this project. The Nelson Lease (an existing waterflood) is located in Allen County, Kansas, in the N.E. Savonburg Field and is operated by James E. Russell Petroleum, Inc. The objective is to increase recovery efficiency and economics in these type of reservoirs. The technologies being applied to increase waterflood sweep efficiency are (1) in situ permeability modification treatments, (2) infill drilling, (3) pattern changes, and (4) air flotation to improve water quality. The technologies being applied to improve reservoir management are (1) database development, (2) reservoir simulation, (3) transient testing, (4) database management and (5) integrated geological and engineering analysis. Results of these two field projects are discussed.

  9. Theoretical and experimental fundamentals of designing promising technological equipment to improve efficiency and environmental safety of highly viscous oil recovery from deep oil reservoirs

    Science.gov (United States)

    Moiseyev, V. A.; Nazarov, V. P.; Zhuravlev, V. Y.; Zhuykov, D. A.; Kubrikov, M. V.; Klokotov, Y. N.

    2016-12-01

    The development of new technological equipment for the implementation of highly effective methods of recovering highly viscous oil from deep reservoirs is an important scientific and technical challenge. Thermal recovery methods are promising approaches to solving the problem. It is necessary to carry out theoretical and experimental research aimed at developing oil-well tubing (OWT) with composite heatinsulating coatings on the basis of basalt and glass fibers. We used the method of finite element analysis in Nastran software, which implements complex scientific and engineering calculations, including the calculation of the stress-strain state of mechanical systems, the solution of problems of heat transfer, the study of nonlinear static, the dynamic transient analysis of frequency characteristics, etc. As a result, we obtained a mathematical model of thermal conductivity which describes the steady-state temperature and changes in the fibrous highly porous material with the heat loss by Stefan-Boltzmann's radiation. It has been performed for the first time using the method of computer modeling in Nastran software environments. The results give grounds for further implementation of the real design of the OWT when implementing thermal methods for increasing the rates of oil production and mitigating environmental impacts.

  10. Isolation of Biosurfactant Producing Bacteria from Oil Reservoirs

    Directory of Open Access Journals (Sweden)

    A Tabatabaee, M Mazaheri Assadi, AA Noohi,VA Sajadian

    2005-01-01

    Full Text Available Biosurfactants or surface-active compounds are produced by microoaganisms. These molecules reduce surface tension both aqueous solutions and hydrocarbon mixtures. In this study, isolation and identification of biosurfactant producing bacteria were assessed. The potential application of these bacteria in petroleum industry was investigated. Samples (crude oil were collected from oil wells and 45 strains were isolated. To confirm the ability of isolates in biosurfactant production, haemolysis test, emulsification test and measurement of surface tension were conducted. We also evaluated the effect of different pH, salinity concentrations, and temperatures on biosurfactant production. Among importance features of the isolated strains, one of the strains (NO.4: Bacillus.sp showed high salt tolerance and their successful production of biosurfactant in a vast pH and temperature domain and reduced surface tension to value below 40 mN/m. This strain is potential candidate for microbial enhanced oil recovery. The strain4 biosurfactant component was mainly glycolipid in nature.

  11. Sequential extraction and compositional analysis of oil-bearing fluid inclusions in reservoir rocks from Kuche Depression, Tarim Basin

    Institute of Scientific and Technical Information of China (English)

    2000-01-01

    The free oils, adsorbed oils and oil-bearing fluid inclusions have been extracted separately and analyzed by GC and GC-MS in reservoir rock samples collected from the Kuche Depression. The results demonstrate that the molecular compositions of oil-bearing fluid inclusions are significantly different from those of the free oils (the current oils). Compared with the current oil, the oil-bearing fluid inclusions are characterized by relatively high values of parameters Pr/nC17and Ph/nC18, low values of Pr/Ph, hopanes/steranes, C30-diahopane/C30-hopane and Ts/Tm, low content of C29Ts terpane and high maturities as indicated by C29 steranes 20S/(20R+20S). In addition, the oil-bearing fluid inclusions correlate very well with the oils in northern and central Tarim Basin, which were derived from Cambrian-Ordovician marine source rocks. The adsorbedoils appear to be an intermediate type between free oils and oil-bearing fluid inclusions. The above analytical data indicate that there are at least two oil-charging episodes for these reservoir rock samples. The early charging oils were derived from Cambrian-Ordovician marine source rocks, and the later charging oils, from Triassic-Jurassic terrestrial source rocks. The primary marine oils were overwhelmingly diluted by the following terrestrial oils.

  12. Time lapse seismic observations and effects of reservoir compressibility at Teal South oil field

    Science.gov (United States)

    Islam, Nayyer

    One of the original ocean-bottom time-lapse seismic studies was performed at the Teal South oil field in the Gulf of Mexico during the late 1990's. This work reexamines some aspects of previous work using modern analysis techniques to provide improved quantitative interpretations. Using three-dimensional volume visualization of legacy data and the two phases of post-production time-lapse data, I provide additional insight into the fluid migration pathways and the pressure communication between different reservoirs, separated by faults. This work supports a conclusion from previous studies that production from one reservoir caused regional pressure decline that in turn resulted in liberation of gas from multiple surrounding unproduced reservoirs. I also provide an explanation for unusual time-lapse changes in amplitude-versus-offset (AVO) data related to the compaction of the producing reservoir which, in turn, changed an isotropic medium to an anisotropic medium. In the first part of this work, I examine regional changes in seismic response due to the production of oil and gas from one reservoir. The previous studies primarily used two post-production ocean-bottom surveys (Phase I and Phase II), and not the legacy streamer data, due to the unavailability of legacy prestack data and very different acquisition parameters. In order to incorporate the legacy data in the present study, all three post-stack data sets were cross-equalized and examined using instantaneous amplitude and energy volumes. This approach appears quite effective and helps to suppress changes unrelated to production while emphasizing those large-amplitude changes that are related to production in this noisy (by current standards) suite of data. I examine the multiple data sets first by using the instantaneous amplitude and energy attributes, and then also examine specific apparent time-lapse changes through direct comparisons of seismic traces. In so doing, I identify time-delays that, when

  13. Fine study on single sand body and measures for tapping the potential of residual oil during polymer flooding in Pubei reservoir of Daqing

    Science.gov (United States)

    Meng, Y. J.

    2016-08-01

    In order to effectively guide the narrow channel sand body oil fields to exploit, according to the sand body distribution characteristics and geological genesis of narrow channel sand body oil fields, the type of single sand body is clarified. By means of identification of logging curves and correlation of well-tie profile, the internal structure of single sand body is recognized. and then the remaining oil genesis, distribution characteristics and the potential areas for polymer flooding are clarified by combining numerical simulation technology and dynamic analysis technology, and the remaining oil potential tapping method is designed by taking into consideration various factors including the characteristics of the remaining oil, reservoir property and product dynamic character. The result shows that the single sand body is divided into five types including multiphase channel superposition, distributary channel, single channel, sheet sand and lenticular sand. Potential remaining oil mainly are distributed in thick oil layers of multiphase channel superposition type and distributary channel type in which channel sands were developed and sedimentary environment are stable inner front facies and lake regressive inner front facies. The remaining oil is developed by optimizing the parameters of polymer flooding and combining many different measures. The study provides technical support for the efficient exploration for polymer flooding.

  14. BTEX anomalies used as indicators of submarine oil and gas reservoirs

    Institute of Scientific and Technical Information of China (English)

    ZHANG Yong; MENG Xiangjun; SUN Ping; CHEN Yanli; QU Peng

    2009-01-01

    It is a conventional method for petroleum prospecting to generally use paraffin hydrocarbon as basic indexes of oil and gas. This conventional geochemical technology, however, shows some limits in the prospecting as paraffin is vulnerable to influences from human and biologic activities. Consequently, BTEX (short for benzene, toluene, ethyl benzene and xylem, which are direct biomarkers) among aromatic hydrocarbon series has been taken into account for the oil and gas prediction. Domestic and foreign study results demonstrate that BTEX is hardly disturbed and can well indicate oil and gas reservoirs. Based on measured data from a South China Sea area, the present authors have used self-developed visual assessment software for petroleum prospecting has been used to process data, strip background anomalies, and outline significant BTEX anomalies. By comparison with stratigraphic profiles of the target area, it is confirmed that BTEX is a good indication of marine oil and gas during the petroleum prospecting.

  15. Managing Injected Water Composition To Improve Oil Recovery: A Case Study of North Sea Chalk Reservoirs

    DEFF Research Database (Denmark)

    Zahid, Adeel; Shapiro, Alexander; Stenby, Erling Halfdan;

    2012-01-01

    In recent years, many core displacement experiments of oil by seawater performed on chalk rock samples have reported SO42–, Ca2+, and Mg2+ as potential determining ions for improving oil recovery. Most of these studies were carried out with outcrop chalk core plugs. The objective of this study...... is to investigate the potential of the advanced waterflooding process by carrying out experiments with reservoir chalk samples. The study results in a better understanding of the mechanisms involved in increasing the oil recovery with potential determining ions. We carried out waterflooding instead of spontaneous...... with the following injecting fluids: distilled water, brine with and without sulfate, and brine containing only magnesium ions. The total oil recovery, recovery rate, and interaction mechanisms of ions with rock were studied for different injecting fluids at different temperatures and wettability conditions. Studies...

  16. Oil recovery enhancement from fractured, low permeability reservoirs. Annual report 1990--1991, Part 1

    Energy Technology Data Exchange (ETDEWEB)

    Poston, S.W.

    1991-12-31

    Joint funding by the Department of Energy and the State of Texas has Permitted a three year, multi-disciplinary investigation to enhance oil recovery from a dual porosity, fractured, low matrix permeability oil reservoir to be initiated. The Austin Chalk producing horizon trending thru the median of Texas has been identified as the candidate for analysis. Ultimate primary recovery of oil from the Austin Chalk is very low because of two major technological problems. The commercial oil producing rate is based on the wellbore encountering a significant number of natural fractures. The prediction of the location and frequency of natural fractures at any particular region in the subsurface is problematical at this time, unless extensive and expensive seismic work is conducted. A major portion of the oil remains in the low permeability matrix blocks after depletion because there are no methods currently available to the industry to mobilize this bypassed oil. The following multi-faceted study is aimed to develop new methods to increase oil and gas recovery from the Austin Chalk producing trend. These methods may involve new geological and geophysical interpretation methods, improved ways to study production decline curves or the application of a new enhanced oil recovery technique. The efforts for the second year may be summarized as one of coalescing the initial concepts developed during the initial phase to more in depth analyses. Accomplishments are predicting natural fractures; relating recovery to well-log signatures; development of the EOR imbibition process; mathematical modeling; and field test.

  17. The effect of thermotropic oil-displacing compound thickened Ninka on reservoir microflora and the composition of oil in Usinskoe oil field

    Science.gov (United States)

    Ovsyannikova, V. S.; Shcherbakova, A. G.; Guseva, Y. Z.; Altunina, L. K.; Chuykina, D. I.

    2016-11-01

    The work presents results of the study of the impact of thermotropic sol-forming compound thickened NINKA on enhanced oil recovery, stimulation of oil production, on the composition of crude oil, and on oil reservoir microflora sampled from reservoir fluids in the testing and reference areas of Usinskoe field. In vitro, the compound in the concentrations of 0.1-0.5% has a stimulating effect on the microflora, which is more pronounced in a low-mineralized environment. In reservoir conditions, after the injection of the compound, along with the appearance of nitrogen-containing components of the compound and products of its hydrolysis in the wellstream, some wells showed a significant increase in the number of heterotrophic and denitrifying microflora, which is indicative of a stimulating effect of the compound. The change in the composition of oil from these producing wells is due to the desorption of polar and high-molecular components and, to a lesser extent, to the redistribution of filtration flows.

  18. New Technology of Optimizing Heavy Oil Reservoir Management by Geochemical Means: A Case Study in Block Leng 43, Liaohe Oilfield, China

    Institute of Scientific and Technical Information of China (English)

    ZHAO HONGJING(赵红静); ZHANG CHUNMING(张春明); MEI BOWEN(梅博文); S. R. LARTER; WU TIESHENG(吴铁生)

    2002-01-01

    Geochemical methods can be used to optimize heavy oil reservoir management. The distribution of some biomarkers in oils is different with the degree of biodegradation. Geochemical parameters can be used to predict oil viscosity and thus to preliminarily evaluate the difficulties involved in oil production. The results of viscosity prediction for oils from reservoir S2 3 in block Leng 43 and preliminary evaluation of oil production difficulty are consistent with the geological data.

  19. Thermal Hydraulic Analysis Using GIS on Application of HTR to Thermal Recovery of Heavy Oil Reservoirs

    Directory of Open Access Journals (Sweden)

    Yangping Zhou

    2012-01-01

    Full Text Available At present, large water demand and carbon dioxide (CO2 emissions have emerged as challenges of steam injection for oil thermal recovery. This paper proposed a strategy of superheated steam injection by the high-temperature gas-cooled reactor (HTR for thermal recovery of heavy oil, which has less demand of water and emission of CO2. The paper outlines the problems of conventional steam injection and addresses the advantages of superheated steam injection by HTR from the aspects of technology, economy, and environment. A Geographic Information System (GIS embedded with a thermal hydraulic analysis function is designed and developed to analyze the strategy, which can make the analysis work more practical and credible. Thermal hydraulic analysis using this GIS is carried out by applying this strategy to a reference heavy oil field. Two kinds of injection are considered and compared: wet steam injection by conventional boilers and superheated steam injection by HTR. The heat loss, pressure drop, and possible phase transformation are calculated and analyzed when the steam flows through the pipeline and well tube and is finally injected into the oil reservoir. The result shows that the superheated steam injection from HTR is applicable and promising for thermal recovery of heavy oil reservoirs.

  20. 油页岩地层测井解释评价技术探讨%On Oil Shale Reservoir Log Evaluation Technique

    Institute of Scientific and Technical Information of China (English)

    王新龙; 罗安银; 祗淑华; 李振苓

    2013-01-01

    The lithologic character,mineral composition,physical property and quality characteristics of oil shale reservoir are introduced.There are obvious differences in well logging response characteristics and interpretation evaluation methods between oil shale reservoir and conventional oil and gas reservoir.Logging data are used to study the following aspects of the reservoir:lithologic identification,mineral composition,physical parameters calculation,organic carbon content,oil content,fracture evaluation,rock mechanics parameters,and so on.And through cuttings,core data analysis and comparison,the results of quantitative evaluation of the reservoir log data,testing interval selection,and fracturing plans can meet the technical needs of reservoir exploration and development.The reservoir log evaluation technique is an important reference to further study other non-conventional oil and gas zone interpretation methods.%介绍了油页岩储层的岩性特征、矿物组成、物性和品质特征,它的测井响应特征及解释评价方法与常规油气层存在明显区别.利用测井资料,针对油页岩地层特点,在岩性判别、矿物组分处理、物性参数求取、有机碳含量、含油率、裂缝评价、岩石力学参数等方面进行了研究.通过和岩屑、岩心等资料分析对比,油页岩地层测井解释定量评价结果、试油层段选择、压裂方案制定等均能满足勘探开发等方面的技术需求.油页岩储层测井评价技术对其他非常规油气层解释技术的深入研究有着重要的参考意义.

  1. Heat transfer fundamentals for electro-thermal heating of oil reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    McGee, B.C.W. [E-T Energy, Calgary, AB (Canada); Donaldson, R.D. [Midvale Mathematics Ltd, Calgary, AB (Canada)

    2009-07-01

    Most of the oil in Alberta is heavy oil or bitumen and cannot be produced easily from the reservoir. Electro-thermal methods are currently being considered for mobilizing bitumen from oil sands. Shell has proposed the use of electro-thermal methods in carbonate rocks and has tested a process at the Shell Peace River operation. E-T Energy is using an electro-thermal process in the Athabasca Oil Sands. Other institutions and companies, including the Alberta Research Council, have also developed electro-thermal approaches for bitumen recovery. Raising the temperature of the host formation reduces the bitumen viscosity allowing the near solid material at original temperature to flow as a liquid. These effects help in sweeping the bitumen to be recovered from the formation when driving agents are externally injected or when autogenous processes, such as gravity drainage come into play. The purpose of this paper was to present a model for radiant heat transfer mechanisms that can be used to compare different electro-thermal heating methods. The model compared the resulting temperature distribution, time to achieve a heated volume at some distance away from the wellbore, and the power density in the reservoir between the different electro-thermal methods. The paper also presented insight into design issues, such as well spacing and input power requirements, as well as matters related to sweep efficiency, near wellbore heating, and water vaporization. The study showed that heat transfer using conduction and electro-thermal methods from a cylindrical electrode achieved limited heating of the reservoir. An array of closely spaced electrodes would be needed to achieve an effective temperature distribution for the recovery of bitumen. Introducing convection as a heat transfer mechanism significantly increased the volume of reservoir that can be heated over a specific duration. 14 refs., 3 tabs., 9 figs.

  2. Improved oil recovery in fluvial dominated deltaic reservoirs of Kansas - Near-term, Class I

    Energy Technology Data Exchange (ETDEWEB)

    Green, D.W.; Willhite, G.P.; Reynolds, Rodney R.; McCune, A. Dwayne; Michnick, Michael J.; Walton, Anthony W.; Watney, W. Lynn

    2000-06-08

    This project involved two demonstration projects, one in a Marrow reservoir located in the southwestern part of the state and the second in the Cherokee Group in eastern Kansas. Morrow reservoirs of western Kansas are still actively being explored and constitute an important resource in Kansas. Cumulative oil production from the Morrow in Kansas is over 400,000,000 bbls. Much of the production from the Morrow is still in the primary stage and has not reached the mature declining state of that in the Cherokee. The Cherokee Group has produced about 1 billion bbls of oil since the first commercial production began over a century ago. It is a billion-barrel plus resource that is distributed over a large number of fields and small production units. Many of the reservoirs are operated close to the economic limit, although the small units and low production per well are offset by low costs associated with the shallow nature of the reservoirs (less than 1000 ft. deep).

  3. Pyritization effect on well logging parameters in Jurassic reservoirs within S-E Western Siberian oil fields

    Science.gov (United States)

    Janishevskii, A.; Ten, T.; Ezhova, A.

    2016-09-01

    Authigenic sulfide mineralization in hydrocarbon-saturated reservoirs distorts the electrical and density properties of rocks. The correlation between volumetric density, electro-conductive minerals and open porosity in 300 samples were determined. This fact made it possible to develop a nomograph in evaluating oil saturated reservoirs and could be applied in well geophysical survey data interpretation.

  4. Steam Flooding after Steam Soak in Heavy Oil Reservoirs through Extended-reach Horizontal Wells

    Institute of Scientific and Technical Information of China (English)

    Ning Zhengfu; Liu Huiqing; Zhang Hongling

    2007-01-01

    This paper presents a new development scheme of simultaneous injection and production in a single horizontal well drilled for developing small block reservoirs or offshore reservoirs.It is possible to set special packers within the long completion horizontal interval to establish an injection zone and a production zone.This method can also be used in steam flooding after steam soak through a horizontal well.Simulation results showed that it was desirable to start steam flooding after six steam soaking cycles and at this time the oil/steam ratio was 0.25 and oil recovery efficiency was 23.48%.Steam flooding performance was affected by separation interval and steam injection rate.Reservoir numerical simulation indicated that maximum oil recovery would be achieved at a separation section of 40-50 m at steam injection rate of 100-180 t/d; and the larger the steam injection rate,the greater the water cut and pressure difference between injection zone and production zone.A steam injection rate of 120 t/d was suitable for steam flooding under practical injection-production conditions.All the results could be useful for the guidance of steam flooding projects.

  5. Synergistic evaluation of a complex conglomerate reservoir for enhanced oil recovery, Barrancas Formation, Argentina

    Energy Technology Data Exchange (ETDEWEB)

    Simlote, V.N.; Ebanks, W.J.; Eslinger, E.V.

    1982-09-01

    An Engineering-geological study of the Top Red Conglomerate (TRC) portions of the Barrancas formation, Mendoza area, Argentina, was conducted to evaluate waterflood performance and develop a predictive model for use in evaluating reservoir response to caustic flooding. Initial oil in place of the TRC reservoir was approximately 400 million STB. The field has produced 154 million STB through 1980, and it is being considered for enhanced recovery processes. The TRC has large variations in permeability, owing to its origin as the uppermost part of a thick alluvial fan-braided channel sequence of sediments. Porosity and permeability development in these rocks are governed mainly by the abundance of detrital clay, and are reduced somewhat by calcite and zeolite cements and authigenic clays. Chemically reactive components are potential causes of formation damage by reactions with injected chemicals. A geological model of layering and areal variability in the reservoir was used to guide the application of a black oil simulator to two cross-sections. This simulation of waterflooded performance indicated good vertical sweep efficiency near injection wells but less efficient sweep farther away because of gravity segregation. The relative merits of several enhanced recovery processes were evaluated for recovering the oil left after waterflooding. Caustic flooding appears to be the most feasible; therefore, the chemical reactivity of representative core samples were evaluated. The mineralogy and cation exchange capacity (CEC) results are presented. CEC values were compared with short term caustic consumption measurements.

  6. Extended application of radon as a natural tracer in oil reservoirs

    Directory of Open Access Journals (Sweden)

    Moreira R.M.

    2013-05-01

    Full Text Available In the 80's it was a common practice in the study of contamination by NAPL to incorporate a tracer to the medium to be studied. At that time the first applications focused on the use of 222Rn, a naturally occurring radioactive isotope as a natural tracer, appropriate for thermodynamics studies, geology and transport properties in thermal reservoirs. In 1993 the deficit of radon was used to spot and quantify the contamination by DNAPL under the surface. For the first time these studies showed that radon could be used as a partitioning tracer. A methodology that provides alternatives to quantify the oil volume stored in the porous space of oil reservoirs is under development at CDTN. The methodology here applied, widens up and adapts the knowledge acquired from the use of radon as a tracer to the studies aimed at assessing SOR. It is a postulation of this work that once the radon partition coefficient between oil and water is known, SOR will be determined considering the increased amount of radon in the water phase as compared to the amount initially existent as the reservoir is flooded with water. This paper will present a description of the apparatus used and some preliminary results of the experiments.

  7. Mineral content prediction for unconventional oil and gas reservoirs based on logging data

    Science.gov (United States)

    Maojin, Tan; Youlong, Zou; Guoyue

    2012-09-01

    Coal bed methane and shale oil &gas are both important unconventional oil and gas resources, whose reservoirs are typical non-linear with complex and various mineral components, and the logging data interpretation model are difficult to establish for calculate the mineral contents, and the empirical formula cannot be constructed due to various mineral. The radial basis function (RBF) network analysis is a new method developed in recent years; the technique can generate smooth continuous function of several variables to approximate the unknown forward model. Firstly, the basic principles of the RBF is discussed including net construct and base function, and the network training is given in detail the adjacent clustering algorithm specific process. Multi-mineral content for coal bed methane and shale oil &gas, using the RBF interpolation method to achieve a number of well logging data to predict the mineral component contents; then, for coal-bed methane reservoir parameters prediction, the RBF method is used to realized some mineral contents calculation such as ash, volatile matter, carbon content, which achieves a mapping from various logging data to multimineral. To shale gas reservoirs, the RBF method can be used to predict the clay content, quartz content, feldspar content, carbonate content and pyrite content. Various tests in coalbed and gas shale show the method is effective and applicable for mineral component contents prediction

  8. A new flooding scheme by horizontal well in thin heavy oil reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Liu, H.; Zhang, H.; Wang, M. [China Univ. of Petroleum, Beijing (China). MOE Key Laboratory of Petroleum Engineering ; Wang, Z. [Shengli Oil Field Co. (China). Dept. of Science and Technology]|[SINOPEC, Shengli (China)

    2008-10-15

    This paper presented a new flooding scheme for single horizontal wells that could improve recovery from thin marginal heavy oil reservoirs or from offshore reservoirs. The scheme involved the use of a multiple tubing string completion in a single wellbore. Special packers were installed within the long completion horizontal interval to establish an injection zone and a production zone. The new flooding scheme also involved simultaneous injection and production. Numerical simulation of the reservoir was used to determine the thickness of the formation and the lower limitation for different viscosities and the optimum time to start steam flooding after steam soaking by economic oil/steam ratio. The peak recovery efficiency of steam flooding was shown to occur when the length of separation section ratio is 0.15 to 0.2. It was concluded that high thermal efficiency in horizontal wells with long completion intervals can be maintained by alternating between steam soaking and steam flooding. Suitable alternation time to steam flooding is a seventh cycle for horizontal wells. Water cut and pressure difference will increase the steam injection rate, and thereby improve the oil production rate. The suitable injection rate for steam flooding is 2.4 t/d.ha.h because of its slow pressure change. 11 refs., 7 figs.

  9. Application of integrated reservoir management and reservoir characterization to optimize infill drilling. Quarterly technical progress report, June 13--September 12, 1997

    Energy Technology Data Exchange (ETDEWEB)

    NONE

    1997-12-31

    The eighteen 10-acre infill wells which were drilled as part of the field demonstration portion of the project are all currently in service with no operational problems. These wells consist of fourteen producing wells and four injection wells. The producing wells are currently producing a total of approximately 500 bopd, down from a peak rate of 900 bopd. Unit production is currently averaging approximately 2,800 bopd, 12,000 bwpd and 17,000 bwipd. The paper describes progress on core analysis, gas-oil/oil-gas permeability tests, water-oil/oil-water permeability tests, water-gas permeability tests, electrical resistivity measurements, capillary pressure tests, reservoir surveillance, and paleontologic analysis.

  10. RESERVOIR CHARACTERIZATION OF UPPER DEVONIAN GORDON SANDSTONE, JACKSONBURG STRINGTOWN OIL FIELD, NORTHWESTERN WEST VIRGINIA

    Energy Technology Data Exchange (ETDEWEB)

    S. Ameri; K. Aminian; K.L. Avary; H.I. Bilgesu; M.E. Hohn; R.R. McDowell; D.L. Matchen

    2001-07-01

    The Jacksonburg-Stringtown oil field contained an estimated 88,500,000 barrels of oil in place, of which approximately 20,000,000 barrels were produced during primary recovery operations. A gas injection project, initiated in 1934, and a pilot waterflood, begun in 1981, yielded additional production from limited portions of the field. The pilot was successful enough to warrant development of a full-scale waterflood in 1990, involving approximately 8,900 acres in three units, with a target of 1,500 barrels of oil per acre recovery. Historical patterns of drilling and development within the field suggests that the Gordon reservoir is heterogeneous, and that detailed reservoir characterization is necessary for understanding well performance and addressing problems observed by the operators. The purpose of this work is to establish relationships among permeability, geophysical and other data by integrating geologic, geophysical and engineering data into an interdisciplinary quantification of reservoir heterogeneity as it relates to production. Conventional stratigraphic correlation and core description shows that the Gordon sandstone is composed of three parasequences, formed along the Late Devonian shoreline of the Appalachian Basin. The parasequences comprise five lithofacies, of which one includes reservoir sandstones. Pay sandstones were found to have permeabilities in core ranging from 10 to 200 mD, whereas non-pay sandstones have permeabilities ranging from below the level of instrumental detection to 5 mD; Conglomeratic zones could take on the permeability characteristics of enclosing materials, or could exhibit extremely low values in pay sandstone and high values in non-pay or low permeability pay sandstone. Four electrofacies based on a linear combination of density and scaled gamma ray best matched correlations made independently based on visual comparison of geophysical logs. Electrofacies 4 with relatively high permeability (mean value > 45 mD) was

  11. EXPERIMENTAL AND THEORETICAL DETERMINATION OF HEAVY OIL VISCOSITY UNDER RESERVOIR CONDITIONS

    Energy Technology Data Exchange (ETDEWEB)

    Dr. Jorge Gabitto; Maria Barrufet

    2003-05-01

    The USA deposits of heavy oils and tar sands contain significant energy reserves. Thermal methods, particularly steam drive and steam soak, are used to recover heavy oils and bitumen. Thermal methods rely on several displacement mechanisms to recover oil, but the most important is the reduction of crude viscosity with increasing temperature. The main objective of this research is to propose a simple procedure to predict heavy oil viscosity at reservoir conditions as a function of easily determined physical properties. This procedure will avoid costly experimental testing and reduce uncertainty in designing thermal recovery processes. First, we reviewed critically the existing literature choosing the most promising models for viscosity determination. Then, we modified an existing viscosity correlation, based on the corresponding states principle in order to fit more than two thousand commercial viscosity data. We collected data for compositional and black oil samples (absence of compositional data). The data were screened for inconsistencies resulting from experimental error. A procedure based on the monotonic increase or decrease of key variables was implemented to carry out the screening process. The modified equation was used to calculate the viscosity of several oil samples where compositional data were available. Finally, a simple procedure was proposed to calculate black oil viscosity from common experimental information such as, boiling point, API gravity and molecular weight.

  12. Diffusion and spatially resolved NMR in Berea and Venezuelan oil reservoir rocks.

    Science.gov (United States)

    Murgich, J; Corti, M; Pavesi, L; Voltini, F

    1992-01-01

    Conventional and spatially resolved proton NMR and relaxation measurements are used in order to study the molecular motions and the equilibrium and nonequilibrium diffusion of oils in Berea sandstone and Venezuelan reservoir rocks. In the water-saturated Berea a single line with T*2 congruent to 150 microseconds is observed, while the relaxation recovery is multiexponential. In an oil reservoir rock (Ful 13) a single narrow line is present while a distribution of relaxation rates is evidenced from the recovery plots. On the contrary, in the Ful 7 sample (extracted at a deeper depth in a different zone) two NMR components are present, with 3.5 and 30 KHz linewidths, and the recovery plot exhibits biexponential law. No echo signal could be reconstructed in the oil reservoir rocks. These findings can be related to the effects in the micropores, where motions at very low frequency can occur in a thin layer. From a comparison of the diffusion constant in water-saturated Berea, D congruent to 5*10(-6) cm2/sec, with the ones in model systems, the average size of the pores is estimated around 40 A. The density profiles at the equilibrium show uniform distribution of oils or of water, and the relaxation rates appear independent from the selected slice. The nonequilibrium diffusion was studied as a function of time in a Berea cylinder with z axis along H0, starting from a thin layer of oil at the base, and detecting the spin density profiles d(z,t) with slice-selection techniques. Simultaneously, the values of T1's were measured locally, and the distribution of the relaxation rates was observed to be present in any slice.(ABSTRACT TRUNCATED AT 250 WORDS)

  13. AN INTEGRATED APPROACH TO CHARACTERIZING BYPASSED OIL IN HETEROGENEOUS AND FRACTURED RESERVOIRS USING PARTITIONING TRACERS

    Energy Technology Data Exchange (ETDEWEB)

    Akhil Datta-Gupta

    2003-08-01

    We explore the use of efficient streamline-based simulation approaches for modeling partitioning interwell tracer tests in hydrocarbon reservoirs. Specifically, we utilize the unique features of streamline models to develop an efficient approach for interpretation and history matching of field tracer response. A critical aspect here is the underdetermined and highly ill-posed nature of the associated inverse problems. We have adopted an integrated approach whereby we combine data from multiple sources to minimize the uncertainty and non-uniqueness in the interpreted results. For partitioning interwell tracer tests, these are primarily the distribution of reservoir permeability and oil saturation distribution. A novel approach to multiscale data integration using Markov Random Fields (MRF) has been developed to integrate static data sources from the reservoir such as core, well log and 3-D seismic data. We have also explored the use of a finite difference reservoir simulator, UTCHEM, for field-scale design and optimization of partitioning interwell tracer tests. The finite-difference model allows us to include detailed physics associated with reactive tracer transport, particularly those related with transverse and cross-streamline mechanisms. We have investigated the potential use of downhole tracer samplers and also the use of natural tracers for the design of partitioning tracer tests. Finally, the behavior of partitioning tracer tests in fractured reservoirs is investigated using a dual-porosity finite-difference model.

  14. Improved oil recovery using bacteria isolated from North Sea petroleum reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Davey, R.A.; Lappin-Scott, H. [Univ. of Exeter (United Kingdom)

    1995-12-31

    During secondary oil recovery, water is injected into the formation to sweep out the residual oil. The injected water, however, follows the path of least resistance through the high-permeability zones, leaving oil in the low-permeability zones. Selective plugging of these their zones would divert the waterflood to the residual oil and thus increase the life of the well. Bacteria have been suggested as an alternative plugging agent to the current method of polymer injection. Starved bacteria can penetrate deeply into rock formations where they attach to the rock surfaces, and given the right nutrients can grow and produce exo-polymer, reducing the permeability of these zones. The application of microbial enhanced oil recovery has only been applied to shallow, cool, onshore fields to date. This study has focused on the ability of bacteria to enhance oil recovery offshore in the North Sea, where the environment can be considered extreme. A screen of produced water from oil reservoirs (and other extreme subterranean environments) was undertaken, and two bacteria were chosen for further work. These two isolates were able to grow and survive in the presence of saline formation waters at a range of temperatures above 50{degrees}C as facultative anaerobes. When a solution of isolates was passed through sandpacks and nutrients were added, significant reductions in permeabilities were achieved. This was confirmed in Clashach sandstone at 255 bar, when a reduction of 88% in permeability was obtained. Both isolates can survive nutrient starvation, which may improve penetration through the reservoir. Thus, the isolates show potential for field trials in the North Sea as plugging agents.

  15. Oil Recovery Enhancement from Fractured, Low Permeability Reservoirs. [Carbonated Water

    Science.gov (United States)

    Poston, S. W.

    1991-01-01

    The results of the investigative efforts for this jointly funded DOE-State of Texas research project achieved during the 1990-1991 year may be summarized as follows: Geological Characterization - Detailed maps of the development and hierarchical nature the fracture system exhibited by Austin Chalk outcrops were prepared. The results of these efforts were directly applied to the development of production decline type curves applicable to a dual-fracture-matrix flow system. Analysis of production records obtained from Austin Chalk operators illustrated the utility of these type curves to determine relative fracture/matrix contributions and extent. Well-log response in Austin Chalk wells has been shown to be a reliable indicator of organic maturity. Shear-wave splitting concepts were used to estimate fracture orientations from Vertical Seismic Profile, VSP data. Several programs were written to facilitate analysis of the data. The results of these efforts indicated fractures could be detected with VSP seismic methods. Development of the EOR Imbibition Process - Laboratory displacement as well as Magnetic Resonance Imaging, MRI and Computed Tomography, CT imaging studies have shown the carbonated water-imbibition displacement process significantly accelerates and increases recovery from oil saturated, low permeability rocks. Field Tests - Two operators amenable to conducting a carbonated water flood test on an Austin Chalk well have been identified. Feasibility studies are presently underway.

  16. Feasibility study of the in-situ combustion in shallow, thin, and multi-layered heavy oil reservoir

    Energy Technology Data Exchange (ETDEWEB)

    Zhong, L. [Society of Petroleum Engineers, Kuala Lumpur (Malaysia)]|[Daqing Petroleum Inst., Beijing (China); Yu, D. [Daqing Petroleum Inst., Beijing (China); Gong, Y. [China National Petroleum Corp., Beijing (China). Liaohe Oilfield; Wang, P.; Zhang, L. [China National Petroleum Corp., Beijing (China). Huabei Oilfield; Liu, C. [China National Petroleum Corp., Beijing (China). JiLin Oilfield

    2008-10-15

    In situ combustion is a process where oxygen is injected into oil reservoirs in order to oxidize the heavier components of crude oil. The oil is driven towards the production wells by the combustion gases and steam generated by the combustion processes. This paper investigated dry and wet forward in situ combustion processes designed for an oil reservoir with thin sand layers. Laboratory and numerical simulations were conducted to demonstrate the feasibility of the processes in a shallow, thin, heterogenous heavy oil reservoir in China. Combustion tube experiments were conducted in order to determine fuel consumption rates. A numerical geological model was constructed to represent the reservoir conditions. Gas, water, oil and solid phases were modelled. Four processes were considered: cracking; pyrolysis of heavy fractions; the combustion of light and heavy fractions; and the combustion of coke. Oil recovery rates were calculated for a period of 10 years. Reactor experiments were conducted to investigate igniting temperatures and air injection rates using an apparatus comprised of an electric heater, oil sand pack tube and a computerized control system. Experiments were performed at different temperature and injection rates. The experiments demonstrated that ignition times and air volumes decreased when air temperature was increased. Results of the study showed that a 20 per cent increase in oil recovery using the in situ combustion processes. It was concluded that adequate air injection rates are needed to ensure effective combustion front movement. 4 refs., 6 tabs., 4 figs.

  17. Geochemical features and genesis of the natural gas and bitumen in paleo-oil reservoirs of Nanpanjiang Basin, China

    Institute of Scientific and Technical Information of China (English)

    ZHAO MengJun; ZHANG ShuiChang; ZHAO Lin; DA Jiang

    2007-01-01

    Bitumen from the Nanpanjiang Basin occurs mainly in the Middle Devonian and Upper Permian reef limestone paleo-oil reservoirs and reserves primarily in holes and fractures and secondarily in minor matrix pores and bio-cavities. N2 is the main component of the natural gas and is often associated with pyrobitumen in paleo-oil reservoirs. The present study shows that the bitumen in paleo-oil reservoirs was sourced from the Middle Devonian argillaceous source rock and belongs to pyrobitumen by crude oil cracking under high temperature and pressure. But the natural gas with high content of N2 is neither an oil-cracked gas nor a coal-formed gas generated from the Upper Permian Longtan Formation source rock, instead it is a kerogen-cracked gas generated at the late stage from the Middle Devonian argillaceous source rock. The crude oil in paleo-oil reservoirs completely cracked into pyrobitumen and methane gas by the agency of hugely thick Triassic deposits. After that, the abnormal high pressure of methane gas reservoirs was completely destroyed due to the erosion of 2000-4500-m-thick Triassic strata. But the kerogen-cracked gas with normal pressure was preserved under the relatively sealed condition and became the main body of the gas shows.

  18. Geochemical features and genesis of the natural gas and bitumen in paleo-oil reservoirs of Nanpanjiang Basin, China

    Institute of Scientific and Technical Information of China (English)

    2007-01-01

    Bitumen from the Nanpanjiang Basin occurs mainly in the Middle Devonian and Upper Permian reef limestone paleo-oil reservoirs and reserves primarily in holes and fractures and secondarily in minor matrix pores and bio-cavities. N2 is the main component of the natural gas and is often associated with pyrobitumen in paleo-oil reservoirs. The present study shows that the bitumen in paleo-oil reservoirs was sourced from the Middle Devonian argillaceous source rock and belongs to pyrobitumen by crude oil cracking under high temperature and pressure. But the natural gas with high content of N2 is neither an oil-cracked gas nor a coal-formed gas generated from the Upper Permian Longtan Formation source rock, instead it is a kerogen-cracked gas generated at the late stage from the Middle Devonian argilla- ceous source rock. The crude oil in paleo-oil reservoirs completely cracked into pyrobitumen and methane gas by the agency of hugely thick Triassic deposits. After that, the abnormal high pressure of methane gas reservoirs was completely destroyed due to the erosion of 2000--4500-m-thick Triassic strata. But the kerogen-cracked gas with normal pressure was preserved under the relatively sealed condition and became the main body of the gas shows.

  19. Revitalizing a mature oil play: Strategies for finding and producing oil in Frio Fluvial-Deltaic Sandstone reservoirs of South Texas

    Energy Technology Data Exchange (ETDEWEB)

    Knox, P.R.; Holtz, M.H.; McRae, L.E. [and others

    1996-09-01

    Domestic fluvial-dominated deltaic (FDD) reservoirs contain more than 30 Billion barrels (Bbbl) of remaining oil, more than any other type of reservoir, approximately one-third of which is in danger of permanent loss through premature field abandonments. The U.S. Department of Energy has placed its highest priority on increasing near-term recovery from FDD reservoirs in order to prevent abandonment of this important strategic resource. To aid in this effort, the Bureau of Economic Geology, The University of Texas at Austin, began a 46-month project in October, 1992, to develop and demonstrate advanced methods of reservoir characterization that would more accurately locate remaining volumes of mobile oil that could then be recovered by recompleting existing wells or drilling geologically targeted infill. wells. Reservoirs in two fields within the Frio Fluvial-Deltaic Sandstone (Vicksburg Fault Zone) oil play of South Texas, a mature play which still contains 1.6 Bbbl of mobile oil after producing 1 Bbbl over four decades, were selected as laboratories for developing and testing reservoir characterization techniques. Advanced methods in geology, geophysics, petrophysics, and engineering were integrated to (1) identify probable reservoir architecture and heterogeneity, (2) determine past fluid-flow history, (3) integrate fluid-flow history with reservoir architecture to identify untapped, incompletely drained, and new pool compartments, and (4) identify specific opportunities for near-term reserve growth. To facilitate the success of operators in applying these methods in the Frio play, geologic and reservoir engineering characteristics of all major reservoirs in the play were documented and statistically analyzed. A quantitative quick-look methodology was developed to prioritize reservoirs in terms of reserve-growth potential.

  20. Seismic Wave Attenuation in Fractured Reservoir: Application on Abu Dhabi Oil Fields.

    Science.gov (United States)

    Bouchaala, F.; Ali, M.; Matsushima, J.

    2016-12-01

    There is a close link between fractures network and fluids circulation so information about nature and geometry of fractures in the reservoir zone is benificial for the petroleum industry. However the immaturity of the methodology and the complication of fractures network in some reservoirs like those of Abu Dhabi oil fields, make getting such information challenging. Since several studies showed the close link between physical properties of the subsurface and seismic wave attenuation (eg. Müller et al. 2010), we use this parameter in this study to assess its potentiality on fractures detection and characterization, even though its use is not common for reservoir characterization and even less for fractures characterization. To get an accurate attenuation profiles, we use a robust methods recently developed to estimate accurately attenuation from Vertical Seismic Profiling (VSP) (Matsushima et al. 2016) and sonic waveforms (Suziki and Matsushima 2013) in the reservoir zones. The data were acquired from many wells located in offshore and onshore oil fields of Abu Dhabi region. The subsurface of this region is mainly composed of carbonate rocks, such media are known to be highly heterogeneous. Scattering and intrinsic attenuation profiles were compared to interpreted fractures by using Formation Micro-imager (FMI). The comparison shows a correlation between these two parameters and fractures characteristic, such as their density and dipping. We also performed Alford rotation on dipole data to estimate the attenuation from fast and slow shear waveforms. The anisotropy is proportional to the dispersion of the points plotted from the ratio between the intrinsic attenuation of fast and slow shear over the depth, from the line (Qslow /Qfast=1), which corresponds to the isotropic case. We noticed that the zones with low fractures density display less dispersion than those of high density. Even though our results show potentiality of the attenuation for fractured

  1. Stress, seismicity and structure of shallow oil reservoirs of Clinton County, Kentucky. Final report

    Energy Technology Data Exchange (ETDEWEB)

    Hamilton-Smith, T. [Kentucky Geological Survey, Lexington, KY (United States)

    1995-12-12

    Between 1993 and 1995 geophysicists of the Los Alamos National Laboratory, in a project funded by the US Department of Energy, conducted extensive microseismic monitoring of oil production in the recently discovered High Bridge pools of Clinton County and were able to acquire abundant, high-quality data in the northern of the two pools. This investigation provided both three-dimensional spatial and kinetic data relating to the High Bridge fracture system that previously had not been available. Funded in part by the Los Alamos National Laboratory, the Kentucky Geological Survey committed to develop a geological interpretation of these geophysical results, that would be of practical benefit to future oils exploration. This publication is a summary of the results of that project. Contents include the following: introduction; discovery and development; regional geology; fractured reservoir geology; oil migration and entrapment; subsurface stress; induced seismicity; structural geology; references; and appendices.

  2. Evaluation of biocompatible stabilised gelled soya bean oil nanoparticles as new hydrophobic reservoirs.

    Science.gov (United States)

    Boudier, Ariane; Kirilov, Plamen; Franceschi-Messant, Sophie; Belkhelfa, Haouaria; Hadioui, Laila; Roques, Christine; Perez, Emile; Rico-Lattes, Isabelle

    2010-01-01

    Based on the organogel concept, in which an oil is trapped in a network of low-molecular-mass organic gelator fibres creating a gel, a formulation of gelled soya bean oil nanoparticles was evaluated for its capacity to form biocompatible hydrophobic reservoirs. The aqueous dispersions of nanoparticles were prepared by hot emulsification (T° > Tgel) and cooling at room temperature in the presence of polyethyleneimine (PEI). The dispersions were stabilised by the electrostatic interactions between the positively charged amino groups of the PEI and the negatively charged carboxylates of the gelator fibres present at the surface of the particles. The aqueous dispersions were highly stable (several months) and the gelled particles were able to entrap a hydrophobic fluorescent model molecule (Nile red), allowing testing in cells. The gelled oil nanoparticles were found to be biocompatible with the tested cells (keratinocytes) and had the ability to become rapidly internalised. Thus, organogel-based nanoparticles are a promising hydrophobic drug delivery system.

  3. Reservoir

    Directory of Open Access Journals (Sweden)

    M. Mokhtar

    2016-12-01

    Full Text Available Scarab field is an analog for the deep marine slope channels in Nile Delta of Egypt. It is one of the Pliocene reservoirs in West delta deep marine concession. Channel-1 and channel-2 are considered as main channels of Scarab field. FMI log is used for facies classification and description of the channel subsequences. Core data analysis is integrated with FMI to confirm the lithologic response and used as well for describing the reservoir with high resolution. A detailed description of four wells penetrated through both channels lead to define channel sequences. Some of these sequences are widely extended within the field under study exhibiting a good correlation between the wells. Other sequences were of local distribution. Lithologic sequences are characterized mainly by fining upward in Vshale logs. The repetition of these sequences reflects the stacking pattern and high heterogeneity of the sandstone reservoir. It also refers to the sea level fluctuation which has a direct influence to the facies change. In terms of integration of the previously described sequences with a high resolution seismic data a depositional model has been established. The model defines different stages of the channel using Scarab-2 well as an ideal analog.

  4. Enhanced heavy oil recovery for carbonate reservoirs integrating cross-well seismic–a synthetic Wafra case study

    KAUST Repository

    Katterbauer, Klemens

    2015-07-14

    Heavy oil recovery has been a major focus in the oil and gas industry to counter the rapid depletion of conventional reservoirs. Various techniques for enhancing the recovery of heavy oil were developed and pilot-tested, with steam drive techniques proven in most circumstances to be successful and economically viable. The Wafra field in Saudi Arabia is at the forefront of utilizing steam recovery for carbonate heavy oil reservoirs in the Middle East. With growing injection volumes, tracking the steam evolution within the reservoir and characterizing the formation, especially in terms of its porosity and permeability heterogeneity, are key objectives for sound economic decisions and enhanced production forecasts. We have developed an integrated reservoir history matching framework using ensemble based techniques incorporating seismic data for enhancing reservoir characterization and improving history matches. Examining the performance on a synthetic field study of the Wafra field, we could demonstrate the improved characterization of the reservoir formation, determining more accurately the position of the steam chambers and obtaining more reliable forecasts of the reservoir’s recovery potential. History matching results are fairly robust even for noise levels up to 30%. The results demonstrate the potential of the integration of full-waveform seismic data for steam drive reservoir characterization and increased recovery efficiency.

  5. Computer simulation of reservoir depletion and oil flow from the Macondo well following the Deepwater Horizon blowout

    Science.gov (United States)

    Hsieh, Paul

    2010-01-01

    This report describes the application of a computer model to simulate reservoir depletion and oil flow from the Macondo well following the Deepwater Horizon blowout. Reservoir and fluid data used for model development are based on (1) information released in BP's investigation report of the incident, (2) information provided by BP personnel during meetings in Houston, Texas, and (3) calibration by history matching to shut-in pressures measured in the capping stack during the Well Integrity Test. The model is able to closely match the measured shut-in pressures. In the simulation of the 86-day period from the blowout to shut in, the simulated reservoir pressure at the well face declines from the initial reservoir pressure of 11,850 pounds per square inch (psi) to 9,400 psi. After shut in, the simulated reservoir pressure recovers to a final value of 10,300 psi. The pressure does not recover back to the initial pressure owing to reservoir depletion caused by 86 days of oil discharge. The simulated oil flow rate declines from 63,600 stock tank barrels per day just after the Deepwater Horizon blowout to 52,600 stock tank barrels per day just prior to shut in. The simulated total volume of oil discharged is 4.92 million stock tank barrels. The overall uncertainty in the simulated flow rates and total volume of oil discharged is estimated to be + or - 10 percent.

  6. Increasing waterflood reserves in the Wilmington Oil Field through improved reservoir characterization and reservoir management. Annual report, March 21, 1995--March 20, 1996

    Energy Technology Data Exchange (ETDEWEB)

    Sullivan, D.; Clarke, D.; Walker, S.; Phillips, C.; Nguyen, J.; Moos, D.; Tagbor, K.

    1997-08-01

    This project uses advanced reservoir characterization tools, including the pulsed acoustic cased-hole logging tool, geologic three- dimensional (3-D) modeling software, and commercially available reservoir management software to identify sands with remaining high oil saturation following waterflood. Production from the identified high oil saturation sands will be stimulated by recompleting existing production and injection wells in these sands using conventional means as well as short radius and ultra-short radius laterals. Although these reservoirs have been waterflooded over 40 years, researchers have found areas of remaining oil saturation. Areas such as the top sand in the Upper Terminal Zone Fault Block V, the western fault slivers of Upper Terminal Zone Fault Block V, the bottom sands of the Tar Zone Fault Block V, and the eastern edge of Fault Block IV in both the Upper Terminal and Lower Terminal Zones all show significant remaining oil saturation. Each area of interest was uncovered emphasizing a different type of reservoir characterization technique or practice. This was not the original strategy but was necessitated by the different levels of progress in each of the project activities.

  7. 3-D Reservoir and Stochastic Fracture Network Modeling for Enhanced Oil Recovery, Circle Ridge Phosphoria/Tensleep Reservoir, and River Reservation, Arapaho and Shoshone Tribes, Wyoming

    Energy Technology Data Exchange (ETDEWEB)

    La Pointe, Paul R.; Hermanson, Jan

    2002-09-09

    The goal of this project is to improve the recovery of oil from the Circle Ridge Oilfield, located on the Wind River Reservation in Wyoming, through an innovative integration of matrix characterization, structural reconstruction, and the characterization of the fracturing in the reservoir through the use of discrete fracture network models.

  8. QUANTITATIVE METHODS FOR RESERVOIR CHARACTERIZATION AND IMPROVED RECOVERY: APPLICATION TO HEAVY OIL SANDS

    Energy Technology Data Exchange (ETDEWEB)

    James W. Castle; Fred J. Molz; Ronald W. Falta; Cynthia L. Dinwiddie; Scott E. Brame; Robert A. Bridges

    2002-10-30

    Improved prediction of interwell reservoir heterogeneity has the potential to increase productivity and to reduce recovery cost for California's heavy oil sands, which contain approximately 2.3 billion barrels of remaining reserves in the Temblor Formation and in other formations of the San Joaquin Valley. This investigation involves application of advanced analytical property-distribution methods conditioned to continuous outcrop control for improved reservoir characterization and simulation, particularly in heavy oil sands. The investigation was performed in collaboration with Chevron Production Company U.S.A. as an industrial partner, and incorporates data from the Temblor Formation in Chevron's West Coalinga Field. Observations of lateral variability and vertical sequences observed in Temblor Formation outcrops has led to a better understanding of reservoir geology in West Coalinga Field. Based on the characteristics of stratigraphic bounding surfaces in the outcrops, these surfaces were identified in the subsurface using cores and logs. The bounding surfaces were mapped and then used as reference horizons in the reservoir modeling. Facies groups and facies tracts were recognized from outcrops and cores of the Temblor Formation and were applied to defining the stratigraphic framework and facies architecture for building 3D geological models. The following facies tracts were recognized: incised valley, estuarine, tide- to wave-dominated shoreline, diatomite, and subtidal. A new minipermeameter probe, which has important advantages over previous methods of measuring outcrop permeability, was developed during this project. The device, which measures permeability at the distal end of a small drillhole, avoids surface weathering effects and provides a superior seal compared with previous methods for measuring outcrop permeability. The new probe was used successfully for obtaining a high-quality permeability data set from an outcrop in southern Utah

  9. Characteristics of the nuclear magnetic resonance logging response in fracture oil and gas reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Xiao Lizhi; Li Kui, E-mail: xiaolizhi@cup.edu.cn [State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing 102249 (China)

    2011-04-15

    Fracture oil and gas reservoirs exist in large numbers. The accurate logging evaluation of fracture reservoirs has puzzled petroleum geologists for a long time. Nuclear magnetic resonance (NMR) logging is an effective new technology for borehole measurement and formation evaluation. It has been widely applied in non-fracture reservoirs, and good results have been obtained. But its application in fracture reservoirs has rarely been reported in the literature. This paper studies systematically the impact of fracture parameters (width, number, angle, etc), the instrument parameter (antenna length) and the borehole condition (type of drilling fluid) on NMR logging by establishing the equation of the NMR logging response in fracture reservoirs. First, the relationship between the transverse relaxation time of fluid-saturated fracture and fracture aperture in the condition of different transverse surface relaxation rates was analyzed; then, the impact of the fracture aperture, dip angle, length of two kinds of antennas and mud type was calculated through forward modeling and inversion. The results show that the existence of fractures affects the NMR logging; the characteristics of the NMR logging response become more obvious with increasing fracture aperture and number of fractures. It is also found that T{sub 2} distribution from the fracture reservoir will be affected by echo spacing, type of drilling fluids and length of antennas. A long echo spacing is more sensitive to the type of drilling fluid. A short antenna is more effective for identifying fractures. In addition, the impact of fracture dip angle on NMR logging is affected by the antenna length.

  10. Study on detailed geological modelling for fluvial sandstone reservoir in Daqing oil field

    Energy Technology Data Exchange (ETDEWEB)

    Zhao Hanqing; Fu Zhiguo; Lu Xiaoguang [Institute of Petroleum Exploration and Development, Daqing (China)

    1997-08-01

    Guided by the sedimentation theory and knowledge of modern and ancient fluvial deposition and utilizing the abundant information of sedimentary series, microfacies type and petrophysical parameters from well logging curves of close spaced thousands of wells located in a large area. A new method for establishing detailed sedimentation and permeability distribution models for fluvial reservoirs have been developed successfully. This study aimed at the geometry and internal architecture of sandbodies, in accordance to their hierarchical levels of heterogeneity and building up sedimentation and permeability distribution models of fluvial reservoirs, describing the reservoir heterogeneity on the light of the river sedimentary rules. The results and methods obtained in outcrop and modem sedimentation studies have successfully supported the study. Taking advantage of this method, the major producing layers (PI{sub 1-2}), which have been considered as heterogeneous and thick fluvial reservoirs extending widely in lateral are researched in detail. These layers are subdivided into single sedimentary units vertically and the microfacies are identified horizontally. Furthermore, a complex system is recognized according to their hierarchical levels from large to small, meander belt, single channel sandbody, meander scroll, point bar, and lateral accretion bodies of point bar. The achieved results improved the description of areal distribution of point bar sandbodies, provide an accurate and detailed framework model for establishing high resolution predicting model. By using geostatistic technique, it also plays an important role in searching for enriched zone of residual oil distribution.

  11. Revitalizing a mature oil play: Strategies for finding and producing unrecovered oil in frio fluvial-deltaic sandstone reservoirs at South Texas. Annual report, October 1994--October 1995

    Energy Technology Data Exchange (ETDEWEB)

    Holtz, M.; Knox, P.; McRae, L. [and others

    1996-02-01

    The Frio Fluvial-Deltaic Sandstone oil play of South Texas has produced nearly 1 billion barrels of oil, yet it still contains about 1.6 billion barrels of unrecovered mobile oil and nearly the same amount of residual oil resources. Interwell-scale geologic facise models of Frio Fluvial-deltaic reservoirs are being combined with engineering assessments and geophysical evaluations in order to determine the controls that these characteristics exert on the location and volume or unrecovered mobile and residual oil. Progress in the third year centered on technology transfer. An overview of project tasks is presented.

  12. Research on surfactant flooding in high temperature and high-salinity reservoir for enhanced oil recovery

    Energy Technology Data Exchange (ETDEWEB)

    Zhou, Ming [Southwest Petroleum Univ., Chengdu, Sichuan (China). State Key Lab. of Oil and Gas Reservoir Geology and Exploitation; Southwest Petroleum Univ., Chengdu, Sichuan (China). School of Material Science and Engineering; Zhao, Jinzhou; Yang, Yan [Southwest Petroleum Univ., Chengdu, Sichuan (China). State Key Lab. of Oil and Gas Reservoir Geology and Exploitation; Wang, Xu [Southwest Petroleum Univ., Chengdu, Sichuan (China). School of Material Science and Engineering

    2013-05-15

    The aim of this work was to research the solution properties of a new surfactant flooding system for high temperature and high salinity reservoir, which include trimeric sulfonate surfactants 1,2,3-tri(2-oxypropyl sulfonation-3-alkylether-propoxyl) propanes (TTSS-n) and anion-nonionic surfactant NPSO [sodium nonyl phenol polyethyleneoxy ether sulfonate, (EO = 10)]. The critical micelle concentrations (CMCs) of five trimeric sulfonate surfactants were smaller than 400 mg L{sup -1}. Furthermore, their interfacial tensions (IFTs) could reach an ultralow value with Tazhong 4 oil at lower concentrations. Through optimized formulation, we found that TTSS-12 had better properties and was selected as the major component of the surfactant flooding system. We designed an optimal formulation of the surfactant flooding system with 1000 mg . L{sup -1} TTSS-12 and 1000 mg . L{sup -1} NPSO surfactant. The system with a very small surfactant concentration could reach ultralow IFT with Tazhong 4 crude oils at high temperature (110 C) and high concentration formation brine (112,228.8 mg/L TDS), which proved that the simpler component surfactant had better reservoir compatibility. NPSO could weaken the disadvantage of the surfactant TTSS-12 in oil/water interface. The stability of this surfactant flooding system was evaluated by aging time, static adsorption and chromatographic separation. All experiments showed that it still keeps ultralow IFT in high temperature and high salinity conditions. Coreflooding experimentation showed that average oil recovery reached 9.8 wt% by surfactant flooding, therefore, it is feasible to use as a surfactant flooding system for enhanced oil recovery (EOR). (orig.)

  13. CO2 Huff-n-Puff Process in a Light Oil Shallow Shelf Carbonate Reservoir

    Energy Technology Data Exchange (ETDEWEB)

    Boomer, R.J.; Cole, R.; Kovar, M.; Prieditis, J.; Vogt, J.; Wehner, S.

    1999-02-24

    The application cyclic CO2, often referred to as the CO2 Huff-n-Puff process, may find its niche in the maturing waterfloods of the Permian Basin. Coupling the CO2 Huff-n-Puff process to miscible flooding applications could provide the needed revenue to sufficiently mitigate near-term negative cash flow concerns in capital-intensive miscible projects. Texaco Exploration and Production Inc. and the US Department of Energy have teamed up in a attempt to develop the CO2 Huff-n-Puff process in the Grayburg and San Andres formations which are light oil, shallow shelf carbonate reservoirs that exist throughout the Permian Basin. This cost-shared effort is intended to demonstrate the viability of this underutilized technology in a specific class of domestic reservoir.

  14. Improved oil recovery in Mississippian carbonate reservoirs of Kansas -- near term -- Class 2. Quarterly report, April 1--June 30, 1995

    Energy Technology Data Exchange (ETDEWEB)

    Carr, T.; Green, D.W.; Willhite, G.P.; Schoeling, L.; Reynolds, R.

    1995-07-01

    The objective of this project is to demonstrate incremental reserves from Osagian and Meramecian (Mississippian) dolomite reservoirs in western Kansas through application of reservoir characterization to identify areas of unrecovered mobile oil. The project addresses producibility problems in two fields: specific reservoirs target the Schaben Field in Ness County, Kansas, and the Bindley Field in Hodgeman County, Kansas. The producibility problems to be addressed include inadequate reservoir characterization, drilling and completion design problems, non-optimum recovery efficiency. The results of this project will be disseminated through various technology transfer activities. General overview--progress is reported for the period from 1 April 1995 to 30 June 1995. Work in this quarter has concentrated on reservoir characterization with the initiation of technology transfer. Difficulties still remain in the drilling of the final two wells. Some preliminary work on reservoir characterization has been completed, and related technology transfer has been initiated.

  15. Modification of reservoir chemical and physical factors in steamfloods to increase heavy oil recovery. [Quarterly report], January 1--March 31, 1997

    Energy Technology Data Exchange (ETDEWEB)

    Yortsos, Y.C. [University of Southern California, Los Angeles, CA (United States)

    1997-08-01

    Thermal methods, and particularly steam injection, are currently recognized as the most promising for the efficient recovery of heavy oil. Despite significant progress, however, important technical issues remain open. Specifically, still inadequate is our knowledge of the complex interaction between porous media and the various fluids of thermal recovery (steam, water, heavy oil, gases, and chemicals). While, the interplay of heat transfer and fluid flow with pore- and macro-scale heterogeneity is largely unexplored. The objectives of this contract are to continue previous work and to carry out new fundamental studies in the following areas of interest to thermal recovery: displacement and flow properties of fluids involving phase change (condensation-evaporation) in porous media; flow properties of mobility control fluids (such as foam); and the effect of reservoir heterogeneity on thermal recovery. The specific projects are motivated by and address the need to improve heavy oil recovery from typical reservoirs as well as less conventional fractured reservoirs producing from vertical or horizontal wells. During this quarter, work continued on the development of relative permeabilities during steam displacement. Most of the work concentrated on the representation of the three-phase flow in terms of a double-drainage process. Work continued on the optimization of recovery processes in heterogeneous reservoirs by using optimal control methods. The effort at present is concentrating in fine-tuning the optimization algorithm as well as in developing control methodologies with different constraints. In parallel, we continued experiments in a Hele-Shaw cell with two controlled injection wells and one production well. In the area of chemical additives work continued on the behavior of non-Newtonian fluid flow and on foam displacements in porous media.

  16. Reserve and Pressure Change of Paleo-oil Reservoir in Puguang Area,Sichuan Basin

    Institute of Scientific and Technical Information of China (English)

    Zhang Yuanchun; Zou Huayao; Wang Cunwu; Li Pingping

    2008-01-01

    The Puguang (普光) gas field is the largest gas field found in marine carbonates in China.The Feixiangnan (飞仙关) and Changxing (长兴) reservoirs are two such reservoirs that had been buried to a depth of about 7 000 m and experienced maximum temperature of up to 220 ℃ before uplift to the present-day depth of 5 000-5 500 m,with present-day thermal maturity between 2.0% and 3.0% equivalent vitrinite reflectance (Ro).Bitumen staining is ubiquitous throughout the Feixianguan and Changxing formations,with the greatest concentrations in zones with the highest porosity and permeability,suggesting that the solid bitumen is the result of in-situ cracking of oil.According to the distribution of bitumen in the core,the paleo-oil boundary can be approximately determined.The paleo-oil resource is calculated to be about (0.61-0.92)×109 t (average 0.76×109 t),and the cracked gas volume is about (380.80-595.80)×109 m3 (average 488.30×109 m3); at least 58.74% of cracked gas is preserved in Puguang gas field.The study area experienced not only the cracking of oil but also thermochemical sulfate reduction,resulting in large quantities of nonhydrocarbon gas,with about 15.2% H2S and 8.3% CO2,together with the structural reconfiguration.During the whole process,the great change of volume and pressure compels the PVTsim modeling software to simulate various factors,such as the cracking of oil,the thermochemical sulfate reduction (TSR) and the tectonic uplift in both isolated and open geological conditions,respectively.The results show that although any one of these factors may induce greater pressure changes in an isolated system than in a closed system,the oil cracking and C3+involving TSR lead to overpressure during the early stage of gas reservoir.Therefore,the tectonic uplift and the methane-dominated TSR,as well as the semi-open system contribute to the reducing pressure resulting in the current normal formation pressure.

  17. Control of Microbial Sulfide Production with Biocides and Nitrate in Oil Reservoir Simulating Bioreactors.

    Directory of Open Access Journals (Sweden)

    Yuan eXue

    2015-12-01

    Full Text Available Oil reservoir souring by the microbial reduction of sulfate to sulfide is unwanted, because it enhances corrosion of metal infrastructure used for oil production and processing. Reservoir souring can be prevented or remediated by the injection of nitrate or biocides, although injection of biocides into reservoirs is not commonly done. Whether combined application of these agents may give synergistic reservoir souring control is unknown. In order to address this we have used up-flow sand-packed bioreactors injected with 2 mM sulfate and volatile fatty acids (VFA, 3 mM each of acetate, propionate and butyrate at a flow rate of 3 or 6 pore volumes per day. Pulsed injection of the biocides glutaraldehyde (Glut, benzalkonium chloride (BAC and cocodiamine was used to control souring. Souring control was determined as the recovery time (RT needed to re-establish an aqueous sulfide concentration of 0.8-1 mM (of the 1.7-2 mM before the pulse. Pulses were either for a long time (120 h at low concentration (long-low or for a short time (1 h at high concentration (short-high. The short-high strategy gave better souring control with Glut, whereas the long-low strategy was better with cocodiamine. Continuous injection of 2 mM nitrate alone was not effective, because 3 mM VFA can fully reduce both 2 mM nitrate to nitrite and N2 and, subsequently, 2 mM sulfate to sulfide. No synergy was observed for short-high pulsed biocides and continuously injected nitrate. However, use of continuous nitrate and long-low pulsed biocide gave synergistic souring control with BAC and Glut, as indicated by increased RTs in the presence, as compared to the absence of nitrate. Increased production of nitrite, which increases the effectiveness of souring control by biocides, is the most likely cause for this synergy.

  18. Cost Effective Surfactant Formulations for Improved Oil Recovery in Carbonate Reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    William A. Goddard; Yongchun Tang; Patrick Shuler; Mario Blanco; Yongfu Wu

    2007-09-30

    This report summarizes work during the 30 month time period of this project. This was planned originally for 3-years duration, but due to its financial limitations, DOE halted funding after 2 years. The California Institute of Technology continued working on this project for an additional 6 months based on a no-cost extension granted by DOE. The objective of this project is to improve the performance of aqueous phase formulations that are designed to increase oil recovery from fractured, oil-wet carbonate reservoir rock. This process works by increasing the rate and extent of aqueous phase imbibition into the matrix blocks in the reservoir and thereby displacing crude oil normally not recovered in a conventional waterflood operation. The project had three major components: (1) developing methods for the rapid screening of surfactant formulations towards identifying candidates suitable for more detailed evaluation, (2) more fundamental studies to relate the chemical structure of acid components of an oil and surfactants in aqueous solution as relates to their tendency to wet a carbonate surface by oil or water, and (3) a more applied study where aqueous solutions of different commercial surfactants are examined for their ability to recover a West Texas crude oil from a limestone core via an imbibition process. The first item, regarding rapid screening methods for suitable surfactants has been summarized as a Topical Report. One promising surfactant screening protocol is based on the ability of a surfactant solution to remove aged crude oil that coats a clear calcite crystal (Iceland Spar). Good surfactant candidate solutions remove the most oil the quickest from the surface of these chips, plus change the apparent contact angle of the remaining oil droplets on the surface that thereby indicate increased water-wetting. The other fast surfactant screening method is based on the flotation behavior of powdered calcite in water. In this test protocol, first the calcite

  19. The Werkendam natural CO2 accumulation: An analogue for CO2 storage in depleted oil reservoirs

    Science.gov (United States)

    Bertier, Pieter; Busch, Andreas; Hangx, Suzanne; Kampman, Niko; Nover, Georg; Stanjek, Helge; Weniger, Philipp

    2015-04-01

    The Werkendam natural CO2 accumulation is hosted in the Röt (Early Triassic) sandstone of the West Netherlands Basin, at a depth of 2.8 km, about 20 km south-east of Rotterdam (NL). This reservoir, in a fault-bound structure, was oil-filled prior to charging with magmatic CO2 in the early Cretaceous. It therefore offers a unique opportunity to study long-term CO2-water-rock interactions in the presence of oil. This contribution will present the results of a detailed mineralogical and geochemical characterisation of core sections from the Werkendam CO2 reservoir and an adjacent, stratigraphically equivalent aquifer. X-ray diffraction combined with X-ray fluorescence spectrometry revealed that the reservoir samples contain substantially more feldspar and more barite and siderite than those from the aquifer, while the latter have higher hematite contents. These differences are attributed to the effects hydrocarbons and related fluids on diagenesis in the closed system of the CO2 reservoir versus the open-system of the aquifer. Petrophysical analyses yielded overall higher and more anisotropic permeability for the reservoir samples, while the porosity is overall not significantly different from that of their aquifer equivalents. The differences are most pronounced in coarse-grained sandstones. These have low anhydrite contents and contain traces of calcite, while all other analyzed samples contain abundant anhydrite, dolomite/ankerite and siderite, but no calcite. Detailed petrography revealed mm-sized zones of excessive primary porosity. These are attributed to CO2-induced dissolution of precompactional, grain-replacive anhydrite cement. Diagenetic dolomite/ankerite crystals are covered by anhedral, epitaxial ankerite, separated from the crystals by bitumen coats. Since these carbonates were oil-wet before CO2-charging, the overgrowths are interpreted to have grown after CO2-charging. Their anhedral habit suggests growth in a 2-phase water-CO2 system. Isotopic

  20. Development of a compositional model fully coupled with geomechanics and its application to tight oil reservoir simulation

    Science.gov (United States)

    Xiong, Yi

    Tight oil reservoirs have received great attention in recent years as unconventional and promising petroleum resources; they are reshaping the U.S. crude oil market due to their substantial production. However, fluid flow behaviors in tight oil reservoirs are not well studied or understood due to the complexities in the physics involved. Specific characteristics of tight oil reservoirs, such as nano-pore scale and strong stress-dependency result in complex porous medium fluid flow behaviors. Recent field observations and laboratory experiments indicate that large effects of pore confinement and rock compaction have non-negligible impacts on the production performance of tight oil reservoirs. On the other hand, there are approximations or limitations for modeling tight oil reservoirs under the effects of pore confinement and rock compaction with current reservoir simulation techniques. Thus this dissertation aims to develop a compositional model coupled with geomechanics with capabilities to model and understand the complex fluid flow behaviors of multiphase, multi-component fluids in tight oil reservoirs. MSFLOW_COM (Multiphase Subsurface FLOW COMpositional model) has been developed with the capability to model the effects of pore confinement and rock compaction for multiphase fluid flow in tight oil reservoirs. The pore confinement effect is represented by the effect of capillary pressure on vapor-liquid equilibrium (VLE), and modeled with the VLE calculation method in MSFLOW_COM. The fully coupled geomechanical model is developed from the linear elastic theory for a poro-elastic system and formulated in terms of the mean stress. Rock compaction is then described using stress-dependent rock properties, especially stress-dependent permeability. Thus MSFLOW_COM has the capabilities to model the complex fluid flow behaviors of tight oil reservoirs, fully coupled with geomechanics. In addition, MSFLOW_COM is validated against laboratory experimental data, analytical

  1. Integrated, multidisciplinary reservoir characterization, modeling and engineering leading to enhanced oil recovery from the Midway-Sunset field, California

    Energy Technology Data Exchange (ETDEWEB)

    Schamel, S.; Forster, C.; Deo, M. (Univ. of Utah, Salt Lake City, UT (United States)) (and others)

    1996-01-01

    The Pru Fee property is developed in a heavy oil, Class III (slope and basin clastic sand), reservoir of the Midway-Sunset field, San Joaquin Basin, California. Wells on the property were shut-in with an estimated 85% of the original oil remaining in place because the reservoir failed to respond to conventional cyclic steaming. Producibility problems are attributed to the close proximity of the property to the margin of the field. Specific problems include complex reservoir geometry, thinning pay, bottom water, and dipping beds. These problems are likely common at the margins of the Midway-Sunset and other Class III reservoirs. This project forms the first step in returning the property to production and explores strategies that might be applied elsewhere. Reservoir characterization, modeling, and engineering methods are integrated to design, simulate, and implement a pilot steam flood. A new drillhole provides good quality, core through the pay zone and a full suite of geophysical logs. Correlations between geological and petrophysical data are used to extrapolate reservoir conditions from older logs and yield a 3-dimensional petrophysical model. Numerical results illustrate how each producibility problem might influence production and provide a framework for designing the pilot steam flood. This first phase illustrates how a multidisciplinary team can use established technologies in developing the detailed petrophysical, geological, and numerical models needed to enhance oil recovery from marginal areas of Class III reservoirs.

  2. Integrated, multidisciplinary reservoir characterization, modeling and engineering leading to enhanced oil recovery from the Midway-Sunset field, California

    Energy Technology Data Exchange (ETDEWEB)

    Schamel, S.; Forster, C.; Deo, M. [Univ. of Utah, Salt Lake City, UT (United States)] [and others

    1996-12-31

    The Pru Fee property is developed in a heavy oil, Class III (slope and basin clastic sand), reservoir of the Midway-Sunset field, San Joaquin Basin, California. Wells on the property were shut-in with an estimated 85% of the original oil remaining in place because the reservoir failed to respond to conventional cyclic steaming. Producibility problems are attributed to the close proximity of the property to the margin of the field. Specific problems include complex reservoir geometry, thinning pay, bottom water, and dipping beds. These problems are likely common at the margins of the Midway-Sunset and other Class III reservoirs. This project forms the first step in returning the property to production and explores strategies that might be applied elsewhere. Reservoir characterization, modeling, and engineering methods are integrated to design, simulate, and implement a pilot steam flood. A new drillhole provides good quality, core through the pay zone and a full suite of geophysical logs. Correlations between geological and petrophysical data are used to extrapolate reservoir conditions from older logs and yield a 3-dimensional petrophysical model. Numerical results illustrate how each producibility problem might influence production and provide a framework for designing the pilot steam flood. This first phase illustrates how a multidisciplinary team can use established technologies in developing the detailed petrophysical, geological, and numerical models needed to enhance oil recovery from marginal areas of Class III reservoirs.

  3. Preservation of ancestral Cretaceous microflora recovered from a hypersaline oil reservoir

    Science.gov (United States)

    Gales, Grégoire; Tsesmetzis, Nicolas; Neria, Isabel; Alazard, Didier; Coulon, Stéphanie; Lomans, Bart P.; Morin, Dominique; Ollivier, Bernard; Borgomano, Jean; Joulian, Catherine

    2016-03-01

    Microbiology of a hypersaline oil reservoir located in Central Africa was investigated with molecular and culture methods applied to preserved core samples. Here we show that the community structure was partially acquired during sedimentation, as many prokaryotic 16S rRNA gene sequences retrieved from the extracted DNA are phylogenetically related to actual Archaea inhabiting surface evaporitic environments, similar to the Cretaceous sediment paleoenvironment. Results are discussed in term of microorganisms and/or DNA preservation in such hypersaline and Mg-rich solutions. High salt concentrations together with anaerobic conditions could have preserved microbial/molecular diversity originating from the ancient sediment basin wherein organic matter was deposited.

  4. Numerical modeling of oil displacement by water from fractured-pore reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Kats, R.M.; Avakyan, E.A.

    1984-01-01

    The process of oil displacement by water in a fractured-pore bed in a two-dimensional statement is mathematically modelled directly. The initial is a two-dimensional filtering model of two immiscible liquids with regard for the capillary forces and gravity in the porous medium. Adaptation of this model for the case of fractured-pore collector is done by reducing the filtering and geometric parameters of this model according to the parameters of the reservoir model represented by a continuum with double porosity, and making the appropriate changes in the algorithm and the computation program.

  5. WETTABILITY AND PREDICTION OF OIL RECOVERY FROM RESERVOIRS DEVELOPED WITH MODERN DRILLING AND COMPLETION FLUIDS

    Energy Technology Data Exchange (ETDEWEB)

    Jill S. Buckley; Norman R. Morrow

    2006-01-01

    The objectives of this project are: (1) to improve understanding of the wettability alteration of mixed-wet rocks that results from contact with the components of synthetic oil-based drilling and completion fluids formulated to meet the needs of arctic drilling; (2) to investigate cleaning methods to reverse the wettability alteration of mixed-wet cores caused by contact with these SBM components; and (3) to develop new approaches to restoration of wetting that will permit the use of cores drilled with SBM formulations for valid studies of reservoir properties.

  6. Horizontal drilling pilot in a shallow heavy oil reservoir in the Suplac Field in Northwestern Romania

    Energy Technology Data Exchange (ETDEWEB)

    Lavelle, J.; Yaghoobi, A. [OMV Petrom S.A. (Romania)

    2011-07-01

    The Suplac field situated in north-western Romania is a shallow and heavy oil deposit lying at depths of between 40 and 200 meters. The deposit has been exploited since 1964 using different techniques but some areas of the reservoir located beneath villages and steep hills were never reached. The aim of this paper is to describe a project using horizontal alternating steam drive (HASD) to harvest oil from these areas by turning from vertical to horizontal. A pilot test was conducted over 4 months in 2010 with 3 parallel horizontal wells. The rig equipment, the well path designs and the directional difficulties are discussed herein. Results showed that horizontals could be drilled using a vertical mast rig and all the expectations were met. The success of this pilot project was highlighted herein and the company is now planning on continuing with a horizontal development program; however wellbore clean out is a remaining challenge.

  7. Class III Mid-Term Project, "Increasing Heavy Oil Reserves in the Wilmington Oil Field Through Advanced Reservoir Characterization and Thermal Production Technologies"

    Energy Technology Data Exchange (ETDEWEB)

    Scott Hara

    2007-03-31

    The overall objective of this project was to increase heavy oil reserves in slope and basin clastic (SBC) reservoirs through the application of advanced reservoir characterization and thermal production technologies. The project involved improving thermal recovery techniques in the Tar Zone of Fault Blocks II-A and V (Tar II-A and Tar V) of the Wilmington Field in Los Angeles County, near Long Beach, California. A primary objective has been to transfer technology that can be applied in other heavy oil formations of the Wilmington Field and other SBC reservoirs, including those under waterflood. The first budget period addressed several producibility problems in the Tar II-A and Tar V thermal recovery operations that are common in SBC reservoirs. A few of the advanced technologies developed include a three-dimensional (3-D) deterministic geologic model, a 3-D deterministic thermal reservoir simulation model to aid in reservoir management and subsequent post-steamflood development work, and a detailed study on the geochemical interactions between the steam and the formation rocks and fluids. State of the art operational work included drilling and performing a pilot steam injection and production project via four new horizontal wells (2 producers and 2 injectors), implementing a hot water alternating steam (WAS) drive pilot in the existing steamflood area to improve thermal efficiency, installing a 2400-foot insulated, subsurface harbor channel crossing to supply steam to an island location, testing a novel alkaline steam completion technique to control well sanding problems, and starting on an advanced reservoir management system through computer-aided access to production and geologic data to integrate reservoir characterization, engineering, monitoring, and evaluation. The second budget period phase (BP2) continued to implement state-of-the-art operational work to optimize thermal recovery processes, improve well drilling and completion practices, and evaluate the

  8. Reservoir characterization and monitoring of cold and thermal heavy oil production using multi-transient EM

    Energy Technology Data Exchange (ETDEWEB)

    Engelmark, F. [Petroleum Geo-Services Asia Pacific Pte Ltd., Singapore (Singapore)

    2008-10-15

    This study emphasized the importance of mapping the in situ subsurface distribution of heavy oil for evaluating the amount of oil in place. The multi-transient electromagnetic (MTEM) method was shown to be an ideal method to characterize the large scale distribution of oil, including the average saturation levels, on the scale needed to optimize oil extraction using steam assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS). A feasibility study for an MTEM monitoring project would simulate reservoir temperature, water saturation and salinity to determine the evolution over time expressed in resistivity and the expanding steam chamber. The 4 factors influencing the resistivity in the monitoring phase were discussed. The temperature due to steaming causes a significant drop in resistivity of the affected rock volume, while the changes in water saturation affect resistivity. The drop in salinity of the pore water due to mixing with distilled water originating in the condensation of the injected steam causes an increase in resistivity, while the mineral dissolution and overall volume expansion causes formation damage that permanently changes the rock fabric. The overall effect of steam injection is a reduction in resistivity within the main part of the chamber, with a sudden increase in resistivity in the proximity of the injection well due to salt depletion. The lowered resistivity within a halo outside the steam chamber can be attributed to the heat radiation front expanding faster than the maturing steam chamber. The author noted that reservoir simulators do not yet incorporate the dynamic changes in porosity and permeability that are observed as permanent reductions of the elastic moduli and reduced resistivity. It was concluded that in order to fully describe the evolution of the steam chamber, this so called formation damage must be better understood. 6 refs., 7 figs.

  9. Cost Effective Surfactant Formulations for Improved Oil Recovery in Carbonate Reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    William A. Goddard; Yongchun Tang; Patrick Shuler; Mario Blanco; Yongfu Wu

    2007-09-30

    This report summarizes work during the 30 month time period of this project. This was planned originally for 3-years duration, but due to its financial limitations, DOE halted funding after 2 years. The California Institute of Technology continued working on this project for an additional 6 months based on a no-cost extension granted by DOE. The objective of this project is to improve the performance of aqueous phase formulations that are designed to increase oil recovery from fractured, oil-wet carbonate reservoir rock. This process works by increasing the rate and extent of aqueous phase imbibition into the matrix blocks in the reservoir and thereby displacing crude oil normally not recovered in a conventional waterflood operation. The project had three major components: (1) developing methods for the rapid screening of surfactant formulations towards identifying candidates suitable for more detailed evaluation, (2) more fundamental studies to relate the chemical structure of acid components of an oil and surfactants in aqueous solution as relates to their tendency to wet a carbonate surface by oil or water, and (3) a more applied study where aqueous solutions of different commercial surfactants are examined for their ability to recover a West Texas crude oil from a limestone core via an imbibition process. The first item, regarding rapid screening methods for suitable surfactants has been summarized as a Topical Report. One promising surfactant screening protocol is based on the ability of a surfactant solution to remove aged crude oil that coats a clear calcite crystal (Iceland Spar). Good surfactant candidate solutions remove the most oil the quickest from the surface of these chips, plus change the apparent contact angle of the remaining oil droplets on the surface that thereby indicate increased water-wetting. The other fast surfactant screening method is based on the flotation behavior of powdered calcite in water. In this test protocol, first the calcite

  10. Influence of biodegradation on benzocarbazole distri-butions in reservoired oils

    Institute of Scientific and Technical Information of China (English)

    2002-01-01

    Partition coefficient difference of benzocarba-zole isomers between oil, water and mineral phase makes them auseful indicator to quantify petroleum migration distance. Because of their nitrogen-heteroatom andannelated aromatic cycles they are generally regarded asbeing more resistant and the effects of biodegradation ontheir concentrations and distributions have not previouslybeen investigated. Reservoir extracts from three wells lo-cated in the Leng43 block of the Liaohe Basin were analyzed to investigate their occurrence and the effect of biodegrada-tion. Both hydrocarbon biomarkers and benzocarbazole isomers show systematical changes with the increase extent of biodegradation in study columns. Carbazole compounds may be biodegraded in a similar way to that observed in aliphatic and aromatic hydrocarbons. The distance from oil water contact is a primary control factor for biodegradation. The concentrations of benzocarbazole isomers show a slight increase in the upper part of the columns then a sharp de-crease towards oil water contact (OWC). Among three iso-mers benzo[a]carbazole seems more susceptible to biode-gradation than other two isomers and benzo[b]carbazole has higher ability to res ist bacterial attack. Benzo[b]carba-zole/benzo- [a]carbazole ratios can sensitively indicate the degree of biodegradation and the benzocarbazole index (BCratio) cannot be directly used as a migration indicator inbiodegraded oils.

  11. Evaluation of reservoir wettability and its effect on oil recovery. Annual report, February 1, 1996--January 31, 1997

    Energy Technology Data Exchange (ETDEWEB)

    Buckley, J.S.

    1998-03-01

    We report on the first year of the project, {open_quotes}Evaluation of Reservoir Wettability and its Effect on Oil Recovery.{close_quotes} The objectives of this five-year project are: (1) to achieve improved understanding of the surface and interfacial properties of crude oils and their interactions with mineral surfaces, (2) to apply the results of surface studies to improve predictions of oil production from laboratory measurements, and (3) to use the results of this research to recommend ways to improve oil recovery by waterflooding. During the first year of this project we have focused on understanding the interactions between crude oils and mineral surfaces that establish wetting in porous media. Mixed-wetting can occur in oil reservoirs as a consequence of the initial fluid distribution. Water existing as thick films on flat surfaces and as wedges in comers can prevent contact of oil and mineral. Water-wet pathways are thus preserved. Depending on the balance of surface forces-which depend on oil, solid, and brine compositions-thick water films can be either stable or unstable. Water film stability has important implications for subsequent alteration of wetting in a reservoir. On surfaces exposed to oil, the components that are likely to adsorb and alter wetting can divided into two main groups: those containing polar heteroatoms, especially organic acids and bases; and the asphaltenes, large molecules that aggregate in solution and precipitate upon addition of n-pentane and similar agents. In order to understand how crude oils interact with mineral surfaces, we must first gather information about both these classes of compounds in a crude oil. Test procedures used to assess the extent of wetting alteration include adhesion and adsorption on smooth surfaces and spontaneous imbibition into porous media. Part 1 of this project is devoted to determining the mechanisms by which crude oils alter wetting.

  12. Optimisation of Oil Production in Two – Phase Flow Reservoir Using Simultaneous Method and Interior Point Optimiser

    DEFF Research Database (Denmark)

    2012-01-01

    in the reservoir. A promising decrease of these remained resources can be provided by smart wells applying water injections to sustain satisfactory pressure level in the reservoir throughout the whole process of oil production. Basically to enhance secondary recovery of the remaining oil after drilling, water...... fields, or closed loop optimisation, can be used for optimising the reservoir performance in terms of net present value of oil recovery or another economic objective. In order to solve an optimal control problem we use a direct collocation method where we translate a continuous problem into a discrete...... for large scale nonlinear optimisation was applied. Because of its versatile compatibility with programming technologies, a C++ programming language in Microsoft Visual Studio integrated development environment was used for modelling the optimal control problem. Thanks to object oriented features...

  13. Study on Productivity Numerical Simulation of Highly Deviated and Fractured Wells in Deep Oil and Gas Reservoirs

    Directory of Open Access Journals (Sweden)

    Li Liangchuan

    2016-01-01

    Full Text Available This paper establishes the model of sandstone, porosity and permeability on single well in allusion to 10 highly deviated and fractured wells in deep oil and gas reservoirs of Jidong Oilfield, which forms a numerical simulation method of highly deviated and fractured wells in deep oil and gas reservoirs of Jidong Oilfield. The numerical simulation results of highly deviated and fractured wells productivity in deep oil and gas reservoirs are given out under different layers (layer ES1, layer ES3, layer ED2,and layer ED3, different deviation angles(60° and 75°, different fracture parameters and producing pressure drops. Through the comparison with testing data getting from exploration wells, we know that the calculation results of numerical simulation are consistent with practical testing results.

  14. Bones and oil reservoirs : bioengineers use oilpatch technology to study fluid flow in bones

    Energy Technology Data Exchange (ETDEWEB)

    Marsters, S.

    2003-06-01

    The fact that porosity and the presence of channels are qualities that are common to oil reservoirs and bones, led to the use of reservoir modelling technology in investigating bone disorders and to the discovery of dramatic changes in the structure and blood supply of osteoarthritic bones that lie under degenerating cartilage. CMG (Computer Modelling Group) Ltd., developers of reservoir simulation software claim that their software packages can help with the modelling of cellular responses to strains and deformations that occur as fluid flows through bone after a traumatic event such as a tear in the anterior cruciate ligament, a common sports-related injury. Researchers at the University of Calgary expect that by looking at the changes in blood and fluid flow within the bone, they can attain a better understanding of the chain of events that leads to osteoarthritis. Better understanding of the progression of the disease could eventually lead to more precise administration of drugs to deal with osteoarthritic pain, and even to the prevention of painful arthritic joints.

  15. Development Optimization and Uncertainty Analysis Methods for Oil and Gas Reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Ettehadtavakkol, Amin, E-mail: amin.ettehadtavakkol@ttu.edu [Texas Tech University (United States); Jablonowski, Christopher [Shell Exploration and Production Company (United States); Lake, Larry [University of Texas at Austin (United States)

    2017-04-15

    Uncertainty complicates the development optimization of oil and gas exploration and production projects, but methods have been devised to analyze uncertainty and its impact on optimal decision-making. This paper compares two methods for development optimization and uncertainty analysis: Monte Carlo (MC) simulation and stochastic programming. Two example problems for a gas field development and an oilfield development are solved and discussed to elaborate the advantages and disadvantages of each method. Development optimization involves decisions regarding the configuration of initial capital investment and subsequent operational decisions. Uncertainty analysis involves the quantification of the impact of uncertain parameters on the optimum design concept. The gas field development problem is designed to highlight the differences in the implementation of the two methods and to show that both methods yield the exact same optimum design. The results show that both MC optimization and stochastic programming provide unique benefits, and that the choice of method depends on the goal of the analysis. While the MC method generates more useful information, along with the optimum design configuration, the stochastic programming method is more computationally efficient in determining the optimal solution. Reservoirs comprise multiple compartments and layers with multiphase flow of oil, water, and gas. We present a workflow for development optimization under uncertainty for these reservoirs, and solve an example on the design optimization of a multicompartment, multilayer oilfield development.

  16. Modelling the effect of wettability distributions on oil recovery from microporous carbonate reservoirs

    Science.gov (United States)

    Kallel, W.; van Dijke, M. I. J.; Sorbie, K. S.; Wood, R.; Jiang, Z.; Harland, S.

    2016-09-01

    Carbonate-hosted hydrocarbon reservoirs are known to be weakly- to moderately oil-wet, but the pore-scale wettability distribution is poorly understood. Moreover, micropores, which often dominate in carbonate reservoirs, are usually assumed to be water-wet and their role in multi-phase flow is neglected. Modelling the wettability of carbonates using pore network models is challenging, because of our inability to attribute appropriate chemical characteristics to the pore surfaces and over-simplification of the pore shapes. Here, we implement a qualitatively plausible wettability alteration scenario in a two-phase flow network model that captures a diversity of pore shapes. The model qualitatively reproduces patterns of wettability alteration recently observed in microporous carbonates via high-resolution imaging. To assess the combined importance of pore-space structure and wettability on petrophysical properties, we consider a homogeneous Berea sandstone network and a heterogeneous microporous carbonate network, whose disconnected coarse-scale pores are connected through a sub-network of fine-scale pores. Results demonstrate that wettability effects are significantly more profound in the carbonate network, as the wettability state of the micropores controls the oil recovery.

  17. Optimisation of production from an oil-reservoir using augmented Lagrangian methods

    Energy Technology Data Exchange (ETDEWEB)

    Doublet, Daniel Christopher

    2007-07-01

    This work studies the use of augmented Lagrangian methods for water flooding production optimisation from an oil reservoir. Commonly, water flooding is used as a means to enhance oil recovery, and due to heterogeneous rock properties, water will flow with different velocities throughout the reservoir. Due to this, water breakthrough can occur when great regions of the reservoir are still unflooded so that much of the oil may become 'trapped' in the reservoir. To avoid or reduce this problem, one can control the production so that the oil recovery rate is maximised, or alternatively the net present value (NPV) of the reservoir is maximised. We have considered water flooding, using smart wells. Smart wells with down-hole valves gives us the possibility to control the injection/production at each of the valve openings along the well, so that it is possible to control the flowregime. One can control the injection/production at all valve openings, and the setting of the valves may be changed during the production period, which gives us a great deal of control over the production and we want to control the injection/ production so that the profit obtained from the reservoir is maximised. The problem is regarded as an optimal control problem, and it is formulated as an augmented Lagrangian saddle point problem. We develop a method for optimal control based on solving the Karush-Kuhn-Tucker conditions for the augmented Lagrangian functional, a method, which to my knowledge has not been presented in the literature before. The advantage of this method is that we do not need to solve the forward problem for each new estimate of the control variables, which reduces the computational effort compared to other methods that requires the solution of the forward problem every time we find a new estimate of the control variables, such as the adjoint method. We test this method on several examples, where it is compared to the adjoint method. Our numerical experiments show

  18. Increased oil production and reserves from improved completion techniques in the Bluebell Field, Uinta Basin, Utah. Seventh quarterly technical progress report, April 1, 1995--June 30, 1995

    Energy Technology Data Exchange (ETDEWEB)

    Morgan, C.D.

    1995-09-01

    The objective of this project is to increase oil production and reserves in the Uinta Basin by demonstrating improved completion techniques. Low productivity of Uinta Basin wells is caused by gross production intervals of several thousand feet that contain perforated thief zones, water-bearing zones, and unperforated oil-bearing intervals. Geologic and engineering characterization and computer simulation of the Green River and Wasatch formations in the Bluebell field will determine reservoir heterogeneities related to fractures and depositional trends. This will be followed by drilling and recompletion of several wells to demonstrate improved completion techniques based on the reservoir characterization. Transfer of the project results will be an ongoing component of the project. Technical progress for this quarter are discussed for subsurface and engineering studies.

  19. Investigation of oil recovery improvement by coupling an interfacial tension agent and a mobility control agent in light oil reservoirs. Final report

    Energy Technology Data Exchange (ETDEWEB)

    Pitts, M.

    1995-12-01

    This research studied the oil recovery potential of flooding light oil reservoirs by combining interfacial tension reducing agent(s) with a mobility control agent. The specific objectives were: To define the mechanisms and limitations of co-injecting interfacial tension reduction agent(s) and a mobility control agent to recover incremental oil. Specifically, the study focused on the fluid-fluid and fluid-rock interactions. To evaluate the economics of the combination technology and investigate methods to make the process more profitable. Specific areas of study were to evaluate different chemical concentration tapers and the volume of chemical injection required to give optimal oil recovery.

  20. Advanced Oil Recovery Technologies for Improved Recovery from Slope Basin Clastic Reservoirs, Nash Draw Brushy Canyon Pool, Eddy County, NM

    Energy Technology Data Exchange (ETDEWEB)

    Murphy, Mark B.

    1999-02-24

    The Nash Draw Brushy Canyon Pool in Eddy County New Mexico is a cost-shared field demonstration project in the US Department of Energy Class II Program. A major goal of the Class III Program is to stimulate the use of advanced technologies to increase ultimate recovery from slope-basin clastic reservoirs. Advanced characterization techniques are being used at the Nash Draw project to develop reservoir management strategies for optimizing oil recovery from this Delaware reservoir. Analysis, interpretation, and integration of recently acquired geologic, geophysical, and engineering data revealed that the initial reservoir characterization was too simplistic to capture the critical features of this complex formation. Contrary to the initial characterization, a new reservoir description evolved that provided sufficient detail regarding the complexity of the Brushy Canyon interval at Nash Draw. This new reservoir description is being used as a risk reduction tool to identify ''sweet spots'' for a development drilling program as well as to evaluate pressure maintenance strategies. The reservoir characterization, geological modeling, 3-D seismic interpretation, and simulation studies have provided a detailed model of the Brushy Canyon zones. This model was used to predict the success of different reservoir management scenarios and to aid in determining the most favorable combination of targeted drilling, pressure maintenance, well simulation, and well spacing to improve recovery from this reservoir.

  1. The Hybrid of Classification Tree and Extreme Learning Machine for Permeability Prediction in Oil Reservoir

    KAUST Repository

    Prasetyo Utomo, Chandra

    2011-06-01

    Permeability is an important parameter connected with oil reservoir. Predicting the permeability could save millions of dollars. Unfortunately, petroleum engineers have faced numerous challenges arriving at cost-efficient predictions. Much work has been carried out to solve this problem. The main challenge is to handle the high range of permeability in each reservoir. For about a hundred year, mathematicians and engineers have tried to deliver best prediction models. However, none of them have produced satisfying results. In the last two decades, artificial intelligence models have been used. The current best prediction model in permeability prediction is extreme learning machine (ELM). It produces fairly good results but a clear explanation of the model is hard to come by because it is so complex. The aim of this research is to propose a way out of this complexity through the design of a hybrid intelligent model. In this proposal, the system combines classification and regression models to predict the permeability value. These are based on the well logs data. In order to handle the high range of the permeability value, a classification tree is utilized. A benefit of this innovation is that the tree represents knowledge in a clear and succinct fashion and thereby avoids the complexity of all previous models. Finally, it is important to note that the ELM is used as a final predictor. Results demonstrate that this proposed hybrid model performs better when compared with support vector machines (SVM) and ELM in term of correlation coefficient. Moreover, the classification tree model potentially leads to better communication among petroleum engineers concerning this important process and has wider implications for oil reservoir management efficiency.

  2. AN INTEGRATED APPROACH TO CHARACTERIZING BYPASSED OIL IN HETEROGENEOUS AND FRACTURED RESERVOIRS USING PARTITIONING TRACERS

    Energy Technology Data Exchange (ETDEWEB)

    Akhil Datta-Gupta

    2004-08-01

    We explore the use of efficient streamline-based simulation approaches for modeling and analysis partitioning interwell tracer tests in heterogeneous and fractured hydrocarbon reservoirs. The streamline approach is generalized to model water injection in naturally fractured reservoirs through the use of a dual media approach. The fractures and matrix are treated as separate continua that are connected through a transfer function, as in conventional finite difference simulators for modeling fractured systems. A detailed comparison with a commercial finite difference simulator shows very good agreement. Furthermore, an examination of the scaling behavior of the computation time indicates that the streamline approach is likely to result in significant savings for large-scale field applications. We also propose a novel approach to history matching finite-difference models that combines the advantage of the streamline models with the versatility of finite-difference simulation. In our approach, we utilize the streamline-derived sensitivities to facilitate history matching during finite-difference simulation. The use of finite-difference model allows us to account for detailed process physics and compressibility effects. The approach is very fast and avoids much of the subjective judgments and time-consuming trial-and-errors associated with manual history matching. We demonstrate the power and utility of our approach using a synthetic example and two field examples. Finally, we discuss several alternative ways of using partitioning interwell tracer tests (PITTs) in oil fields for the calculation of oil saturation, swept pore volume and sweep efficiency, and assess the accuracy of such tests under a variety of reservoir conditions.

  3. Sulfide remediation by pulsed injection of nitrate into a low temperature Canadian heavy oil reservoir.

    Science.gov (United States)

    Voordouw, Gerrit; Grigoryan, Aleksandr A; Lambo, Adewale; Lin, Shiping; Park, Hyung Soo; Jack, Thomas R; Coombe, Dennis; Clay, Bill; Zhang, Frank; Ertmoed, Ryan; Miner, Kirk; Arensdorf, Joseph J

    2009-12-15

    Sulfide formation by oil field sulfate-reducing bacteria (SRB) can be diminished by the injection of nitrate, stimulating the growth of nitrate-reducing bacteria (NRB). We monitored the field-wide injection of nitrate into a low temperature (approximately 30 degrees C) oil reservoir in western Canada by determining aqueous concentrations of sulfide, sulfate, nitrate, and nitrite, as well as the activities of NRB in water samples from 3 water plants, 2 injection wells, and 15 production wells over 2 years. The injection water had a low sulfate concentration (approximately 1 mM). Nitrate (2.4 mM, 150 ppm) was added at the water plants. Its subsequent distribution to the injection wells gave losses of 5-15% in the pipeline system, indicating that most was injected. Continuous nitrate injection lowered the total aqueous sulfide output of the production wells by 70% in the first five weeks, followed by recovery. Batchwise treatment of a limited section of the reservoir with high nitrate eliminated sulfide from one production well with nitrate breakthrough. Subsequent, field-wide treatment with week-long pulses of 14 mM nitrate gave breakthrough at an additional production well. However, this trend was reversed when injection with a constant dose of 2.4 mM (150 ppm) was resumed. The results are explained by assuming growth of SRB near the injection wellbore due to sulfate limitation. Injection of a constant nitrate dose inhibits these SRB initially. However, because of the constant, low temperature of the reservoir, SRB eventually grow back in a zone further removed from the injection wellbore. The resulting zonation (NRB closest to and SRB further away from the injection wellbore) can be broken by batch-wise increases in the concentration of injected nitrate, allowing it to re-enter the SRB-dominated zone.

  4. Simulation study of the VAPEX process in fractured heavy oil system at reservoir conditions

    Energy Technology Data Exchange (ETDEWEB)

    Azin, Reza; Ghotbi, Cyrus [Department of Chemical and Petroleum Engineering, Sharif Univ. Tech., Tehran (Iran); Kharrat, Riyaz; Rostami, Behzad [Petroleum University of Technology Research Center, Tehran (Iran); Vossoughi, Shapour [4132C Learned Hall, Department of Chemical and Petroleum Engineering, Kansas University, Lawrence, KS (United States)

    2008-01-15

    The Vapor Extraction (VAPEX) process, a newly developed Enhanced Oil Recovery (EOR) process to recover heavy oil and bitumen, has been studied theoretically and experimentally and is found a promising EOR method for certain heavy oil reservoirs. In this work, a simulation study of the VAPEX process was made on a fractured model, which consists of a matrix surrounded by horizontal and vertical fractures. The results show a very interesting difference in the pattern of solvent flow in fractured model compared with the conventional model. Also, in the fractured system, due to differences in matrix and fracture permeabilities, the solvent first spreads through the fractures and then starts diffusing into matrix from all parts of the matrix. Thus, the solvent surrounds the oil bank, and an oil rather than the solvent chamber forms and shrinks as the process proceeds. In addition, the recovery factor is higher at lower solvent injection rates for a constant pore volume of the solvent injected into the model. Also, the diffusion process becomes important and higher recoveries are obtained at low injection rates, provided sufficient time is given to the process. The effect of inter-connectivity of the surrounding fractures was studied by making the side vertical fractures shorter than the side length of the model. It was observed that inter-connectivity of the fractures affects the pattern of solvent distribution. Even for the case of side fractures being far apart from the bottom fracture, the solvent distribution in the matrix was significantly different than that in the model without fractures. Combination of diffusion phenomenon and gravity segregation was observed to be controlling factors in all VAPEX processes simulated in fractured systems. The early breakthrough of the solvent for the case of matrix surrounded by the fracture partially inhibited diffusion of the solvent into the oil and consequently the VAPEX process became the least effective. It is concluded

  5. Water-oil separation performance of technical textiles used for marine pollution disasters.

    Science.gov (United States)

    Seddighi, Mahdi; Hejazi, Sayyed Mahdi

    2015-07-15

    Oil is principally one of the most important energy sources in the world. However, as long as oil is explored and transported for being used, there will be the risk of the spillage into the marine environment. The use of technical textiles, i.e. fibrous beds, is a conventional separation technique for oil/water emulsion since it is efficient and easy to design. In this paper, the recovery of oil by technical textiles was mathematically modeled based on the structural parameters of textile and the capillary mechanism. Eleven types of commercial technical textiles with different properties were prepared for the experimental program. The experimental design included fiber type (polypropylene and polyester), fabric type (woven and/or nonwoven), fabric thickness and fabric areal density. Consequently, the absorption capacities of different technical textile samples were derived by the use of theoretical and experimental methods. The results show that there is a well fitness between theoretical outputs and experimental data.

  6. Functioning of Oil and Gas Industry Technical Committees in Republic of Kazakhstan

    Directory of Open Access Journals (Sweden)

    Zhanserik B. Ilmaliev

    2012-03-01

    Full Text Available The article brings in complex analysis of the existing legal, organizational problems of technical committees, particularly the ones in oil and gas industry and offers ways to overcome them

  7. The economics of carbon dioxide transport by pipeline and storage in saline aquifers and oil reservoirs

    Science.gov (United States)

    McCoy, Sean T.

    Large reductions in carbon dioxide (CO2) emissions are needed to mitigate the impacts of climate change. One method of achieving such reductions is CO2 capture and storage (CCS). CCS requires the capture of carbon dioxide (CO2) at a large industrial facility, such as a power plant, and its transport to a geological storage site where CO2 is sequestered, if implemented, CCS could allow fossil fuels to be used with little or no CO2 emissions until alternative energy sources are more widely deployed. Large volumes of CO2 are most efficiently transported by pipeline and stored either in deep saline aquifers or in oil reservoirs, where CO2 is used for enhanced oil recovery (EOR). This thesis describes a suite of models developed to estimate the project-specific cost of CO2 transport and storage. Engineering-economic models of pipeline CO2 transport, CO2flood EOR, and aquifer storage were developed for this purpose. The models incorporate a probabilistic analysis capability that is used to quantify the sensitivity of transport and storage cost to variability and uncertainty in the model input parameters. The cost of CO2 pipeline transport is shown to be sensitive to the region of construction, in addition to factors such as the length and design capacity of the pipeline. The cost of CO2 storage in saline aquifers is shown to be most sensitive to factors affecting site characterization cost. For EOR projects, CO2 storage has traditionally been a secondary effect of oil recovery; thus, a levelized cost of CO2 storage cannot be defined. Instead EOR projects were evaluated based on the breakeven price of CO2 (i.e., the price of CO2 at which the project net present value is zero). The breakeven CO2 price is shown to be most sensitive to oil prices, losses of CO2 outside the productive zone of the reservoir, and reservoir pressure. Future research should include collection and aggregation of more specific data characterizing possible sites for aquifer storage and applications

  8. THEORY OF FLUID-SOLID COUPLED FLOW THROUGH FRACTURED LOW-PERMEABILITY OIL RESERVOIR AND ITS APPLICATIONS

    Institute of Scientific and Technical Information of China (English)

    Liu Jian-jun

    2003-01-01

    During the development of low permeability reservoirs. the interaction between fluid flow and rock-mass deformation is obvious. On the basis of fluid mechanics in porous media and elasto-plastic theory. the author presents an equivalent continuum model to simulate fluid flow in fractured low-permeability oil reservoir coupled with geo-stress. The model not only reflects the porosity change of matrix, but also the permeability change due to the opening and closing of fracture. By analyzing of simulation results, the changes in porosity and permeability and their effect on oil development are studied.

  9. Mechanisms of abnormal overpressure generation in Kuqa foreland thrust belt and their impacts on oil and gas reservoir formation

    Institute of Scientific and Technical Information of China (English)

    2002-01-01

    Based on overview for mechanism of abnormal overpressure generation in sedimentary basins, an insight discussion is made by the authors for the distribution, features and generation mechanisms of abnormal overpressure in the Kuqa foreland thrust belt. The abnormal overpressure in the Kelasu structure zone west to the Kuqa foreland thrust belt was primarily distributed in Eogene to lower Cretaceous formations; structural compression and structural emplacement as well as the containment of Eogene gyps-salt formation constituted the main mechanisms for the generation of abnormal overpressure. The abnormal overpressure zone in the eastern Yiqikelike structure zone was distributed primarily in lower Jurassic Ahe Group, resulting from hydrocarbon generation as well as structural stress other than from under-compaction. Various distributions and generating mechanisms have different impacts upon the formation of oil and gas reservoirs. K-E reservoir in the Kelasu zone is an allochthonous abnormal overpressure system. One of the conditions for reservoir accumulation is the migration of hydrocarbon (T-J hydrocarbon source rock) along the fault up to K-E reservoir and accumulated into reservoir. And this migration process was controlled by the abnormal overpressure system in K-E reservoir. The confined abnormal overpressure system in the Yiqikelike structure zone constituted the main cause for the poor developing of dissolved porosity in T-J reservoir, resulting in poor physical property of reservoir. The poor physical property of T-J reservoir of Yinan 2 structure was the main cause for the absence of oil accumulation, but the presence of natural gas reservoir in the structure.

  10. Geologic CO2 Sequestration: Predicting and Confirming Performance in Oil Reservoirs and Saline Aquifers

    Science.gov (United States)

    Johnson, J. W.; Nitao, J. J.; Newmark, R. L.; Kirkendall, B. A.; Nimz, G. J.; Knauss, K. G.; Ziagos, J. P.

    2002-05-01

    Reducing anthropogenic CO2 emissions ranks high among the grand scientific challenges of this century. In the near-term, significant reductions can only be achieved through innovative sequestration strategies that prevent atmospheric release of large-scale CO2 waste streams. Among such strategies, injection into confined geologic formations represents arguably the most promising alternative; and among potential geologic storage sites, oil reservoirs and saline aquifers represent the most attractive targets. Oil reservoirs offer a unique "win-win" approach because CO2 flooding is an effective technique of enhanced oil recovery (EOR), while saline aquifers offer immense storage capacity and widespread distribution. Although CO2-flood EOR has been widely used in the Permian Basin and elsewhere since the 1980s, the oil industry has just recently become concerned with the significant fraction of injected CO2 that eludes recycling and is therefore sequestered. This "lost" CO2 now has potential economic value in the growing emissions credit market; hence, the industry's emerging interest in recasting CO2 floods as co-optimized EOR/sequestration projects. The world's first saline aquifer storage project was also catalyzed in part by economics: Norway's newly imposed atmospheric emissions tax, which spurred development of Statoil's unique North Sea Sleipner facility in 1996. Successful implementation of geologic sequestration projects hinges on development of advanced predictive models and a diverse set of remote sensing, in situ sampling, and experimental techniques. The models are needed to design and forecast long-term sequestration performance; the monitoring techniques are required to confirm and refine model predictions and to ensure compliance with environmental regulations. We have developed a unique reactive transport modeling capability for predicting sequestration performance in saline aquifers, and used it to simulate CO2 injection at Sleipner; we are now

  11. Silica sand for oil and gas production : a technical market overview

    Energy Technology Data Exchange (ETDEWEB)

    Dawson, J.C. [BJ Services Company, Calgary, AB (Canada)

    2006-07-01

    In order to meet the growing demand for oil, petroleum production companies have initiated aggressive globally oriented drilling programs. In Canada and the United States, the average monthly rig count has doubled from 1103 rigs in 1990 to 2213 in 2006, with 53 per cent of the growth taking place in the last 3 years. Extensive damage occurs in the hydrocarbon rich formations during the drilling process of new wells. In order to stimulate and reconnect the well to the reservoir, completion processes such as hydraulic fracturing, are needed. In hydraulic fracturing, a viscous fluid is injected into the well at a rate and pressure sufficient to initiate a crack behind the casing perforations. When the fracture attains adequate width and length, silica sand or other proppants are added to the fluid to fill the created fracture. These may include Ottawa Sand, Brady Sand, bauxite, intermediate strength ceramics or resin coated sands. The use of proppants prevents the fracture from healing and provides a super conductive drainage channel for hydrocarbons. The proppant should provide the highest porosity to maximize permeability of the proppant pack. Hydrocarbon production can therefore be increased at relatively low costs. This paper reviewed the stringent industry specifications that various grades of proppant must meet, as defined by the American Petroleum Institute. The technical aspects of proppant testing were outlined with reference to proppant size, sphericity, acid solubility, turbidity, crush resistance, and testing for ceramic proppants. Despite improved logging and advances in well stimulation treatments, market trends indicate that hydraulic fracturing and proppants will continue to be an important aspect of oil and gas production. 22 refs., 3 tabs., 5 figs.

  12. Isotopic and geochemical tools to assess the feasibility of methanogenesis as a way to enhance hydrocarbon recovery in oil reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Jimenez, N.; Morris, B.E.L.; Richnow, H.H. [Helmholtz-Zentrum fuer Umweltforschung (UFZ), Leipzig (Germany). Abt. Isotopenbiogeochemie; Cai, M.; Yao, Jun [Helmholtz-Zentrum fuer Umweltforschung (UFZ), Leipzig (Germany). Abt. Isotopenbiogeochemie; University of Sicence and Technology, Beijing (China). School of Civil and Environment Engineering; Straaten, N.; Krueger, M. [Bundesanstalt fuer Geowissenschaften und Rohstoffe (BGR), Hannover (Germany). Fachbereich Geochemie

    2013-08-01

    In situ biotransformation of oil to methane was investigated in a thermophilic reservoir in Dagang, China using isotopic analyzes, chemical fingerprinting and molecular and biological methods. Our first results, which were already published, demonstrated that anaerobic oil degradation concomitant with methane production was occurring. The reservoir was highly methanogenic and the oil exhibited varying degrees of degradation between different parts of the reservoir, although it was mainly highly weathered, and nearly devoid of nalkanes, alkylbenzenes, alkyltoluenes, and light PAHs. In addition, the isotopic data from reservoir oil, water and gas was used to elucidate the origin of the methane. The average {delta}{sup 13}C for methane was around -47 permille and CO{sub 2} was highly enriched in {sup 13}C. The bulk isotopic discrimination ({Delta}{delta}{sup 13}C) between methane and CO{sub 2} was between 32 and 65 permille, in accordance with previously reported results for methane formation during hydrocarbon degradation. Subsequent microcosm experiments revealed that autochthonous microbiota are capable of degrading oil under methanogenic conditions and of producing methane and/or CO{sub 2} from {sup 13}C-labelled n-hexadecane, 2-methylnaphthalene or toluene ({delta}{sup 13}C values up to 550 permille). These results demonstrate that methanogenesis is linked to aliphatic and aromatic hydrocarbon degradation. Further experiments will elucidate the activation mechanisms for the different compounds. (orig.)

  13. Feasibility Study on Steam and Gas Push with Dual Horizontal Wells in a Moderate-Depth Heavy Oil Reservoir

    Directory of Open Access Journals (Sweden)

    Jie Fan

    2016-02-01

    Full Text Available Non-condensable gas (NCG with steam co-injection makes steam assisted gravity drainage less energy-intensive as well as reduces greenhouse gas emission and water consumption. Numerous studies have shown that the technology called steam and gas push (SAGP is feasible for heavy oil and bitumen. However, most of these studies have focused on shallow heavy oil reservoirs and only a few works have investigated moderate-depth heavy oil reservoirs. In this study, laboratory experiments and numerical simulations were conducted to study shape change, steam chamber expansion, and temperature change after co-injecting NCG with steam into an actual moderate-depth heavy oil reservoir. Results showed that after co-injecting NCG with steam, the transverse expansion rate of the steam chamber accelerated, vertical expansion slowed down, thermal utilization increased, and oil–steam ratio improved. In addition, the injection parameters of SAGP were also optimized via numerical simulation, which indicated that SAGP could effectively improve development effect and recovery for moderate-depth heavy oil reservoirs.

  14. Sulfidogenesis and Control in Fractured Rock: Laboratory Experiments and Implication for Souring Intervention in Oil Reservoirs

    Science.gov (United States)

    Wu, Y.; Hubbard, C. G.; Geller, J. T.; Ajo Franklin, J. B.

    2016-12-01

    Microbial sulfidogenesis in oil reservoirs, referred to as souring, is commonly encountered during sea water flooding. A better understanding of the souring process and effective control is of great interest to the oil industry. While a large fraction of global oil reserve is found in fractured rock, understanding of sulfidogenesis and control in fractured rock is next to non-existent. Complex and contrasting flow properties between fracture and matrix result in heterogeneous thermal and reaction gradients, posing great challenges to both experimental and modeling studies. We conducted the first experiment on biogenic sulfidogenesis and control in fractured rock. A 2D flow cell was used and straight fractures were created in order to reduce complexity, producing datasets more amenable to models. Heating was applied to simulate temperature gradients from colder sea-water injection. Perchlorate treatment was performed following sulfidogenesis as a thermodynamic control strategy. Synthetic sea water (SSW) with acetate was used as the growth media. Inoculations were carried out with sulfate reducing and perchlorate reducing microbes. A set of control and monitoring methods was applied including temperature, optical and infrared imaging, distributed galvanic sensing and fluid sampling as well as influent/effluent monitoring. Tracer tests were conducted before and after the experiment. Our experiment captured the dynamics of sulfur cycling in fractured rocks. Time-lapse optical imaging recorded the evolution of microbial biomass. Infrared imaging revealed the thermal gradient and the impacts from flow. Such data was essential for the identification of a mesophilic zone and it's co-location with sufidogenesis. Galvanic-potential signals provided the critical dataset for tracking spatial sulfide distribution over time. Our experiment demonstrated for the first time the role of heterogeneous flow and temperature controlling sulfidogenesis and treatment in fractured rock

  15. Heavy-oil recovery in naturally fractured reservoirs with varying wettability by steam solvent co-injection

    Energy Technology Data Exchange (ETDEWEB)

    Al Bahlani, A. [Alberta Univ., Edmonton, AB (Canada); Babadagli, T. [Society of Petroleum Engineers, Canadian Section, Calgary, AB (Canada)]|[Alberta Univ., Edmonton, AB (Canada)

    2008-10-15

    Steam injection may not be an efficient oil recovery process in certain circumstances, such as in deep reservoirs, where steam injection may be ineffective because of hot-water flooding due to excessive heat loss. Steam injection may also be ineffective in oil-wet fractured carbonates, where steam channels through fracture zones without effectively sweeping the matrix oil. Steam flooding is one of the many solutions for heavy oil recovery in unconsolidated sandstones that is in commercial production. However, heavy-oil fractured carbonates are more challenging, where the recovery is generally limited only to matrix oil drainage gravity due to unfavorable wettability or thermal expansion if heat is introduced during the process. This paper proposed a new approach to improve steam/hot-water injection and efficiency for heavy-oil fractured carbonate reservoirs. The paper provided background information on oil recovery from fractured carbonates and provided a statement of the problem. Three phases were described, including steam/hot-waterflooding phase (spontaneous imbibition); miscible flooding phase (diffusion); and steam/hot-waterflooding phase (spontaneous imbibition or solvent retention). The paper also discussed core preparation and saturation procedures. It was concluded that efficient oil recovery is possible using alternate injection of steam/hot water and solvent. 43 refs., 1 tab., 13 figs.

  16. 30 CFR 250.1157 - How do I receive approval to produce gas-cap gas from an oil reservoir with an associated gas cap?

    Science.gov (United States)

    2010-07-01

    ... 30 Mineral Resources 2 2010-07-01 2010-07-01 false How do I receive approval to produce gas-cap gas from an oil reservoir with an associated gas cap? 250.1157 Section 250.1157 Mineral Resources... do I receive approval to produce gas-cap gas from an oil reservoir with an associated gas cap? (a...

  17. Cracked and full of sand: microstructural insights into how oil gets into a crystalline basement reservoir

    Science.gov (United States)

    Holdsworth, Bob; McCaffrey, Ken; Dempsey, Eddie

    2017-04-01

    The fractured Neoarchaean orthogneisses forming the 200km long, NE-SW trending Rona Ridge lie offshore along the southeast margin of the Faroe-Shetland Basin (FSB). The basement ridge was uplifted during Cretaceous-age normal faulting and is flanked and immediately overlain by Devonian to Cretaceous cover sequences. Basement-hosted oil is known to occur in significant volumes in at least two fields (Clair, Lancaster). Re-Os dating of bitumen samples from the Clair Field suggests that oil was generated in the period 64-72Ma. A new microstructural study of basement cores was carried out to assess the mechanisms and timing of oil charge and other fracture-hosted mineralization. Oil charge is everywhere associated with quartz-adularia-calcite-pyrite mineralization and is hosted in a complex mesh of interconnected shear and tensile fractures that formed during a single protracted episode of brittle deformation. This association is recognized in all basement cores containing oil and also in locally overlying well-cemented Devonian (Lower Clair Group) and Jurassic (Rona Sandstone) sequences. Mineralization and oil charge is everywhere associated with clastic sedimentary infillings which occur either as vein-hosted injected slurries, or as little deformed laminated infills in mm to dm-scale open fractures. The latter preserve delicate way-up criteria and geopetal structures. The largest accumulations of oil are found either in these poorly-cemented sedimentary infills, or in fracture-hosted vuggy cavities up to several cm across. All these features, together with the widespread development of zoned mineral cements and cockade textures suggest a low-temperature hydrothermal system that likely formed in a near surface (process may have also helped to drive oil migration from the Jurassic source rocks located to the west in the FSB, through the basement ridge and up into the overlying Clair Group and other cover sequences during the 64-72Ma time period. Our findings have

  18. Microbial redox processes in deep subsurface environments and the potential application of (perchlorate in oil reservoirs

    Directory of Open Access Journals (Sweden)

    Martin G Liebensteiner

    2014-09-01

    Full Text Available The ability of microorganisms to thrive under oxygen-free conditions in subsurface environments relies on the enzymatic reduction of oxidized elements, such as sulfate, ferric iron or CO2, coupled to the oxidation of inorganic or organic compounds. A broad phylogenetic and functional diversity of microorganisms from subsurface environments has been described using isolation-based and advanced molecular ecological techniques. The physiological groups reviewed here comprise iron-, manganese- and nitrate-reducing microorganisms. In the context of recent findings also the potential of chlorate and perchlorate [jointly termed (perchlorate] reduction in oil reservoirs will be discussed. Special attention is given to elevated temperatures that are predominant in the deep subsurface. Microbial reduction of (perchlorate is a thermodynamically favorable redox process, also at high temperature. However, knowledge about (perchlorate reduction at elevated temperatures is still scarce and restricted to members of the Firmicutes and the archaeon Archaeoglobus fulgidus. By analyzing the diversity and phylogenetic distribution of functional genes in (metagenome databases and combining this knowledge with extrapolations to earlier-made physiological observations we speculate on the potential of (perchlorate reduction in the subsurface and more precisely oil fields. In addition, the application of (perchlorate for bioremediation, souring control and microbial enhanced oil recovery are addressed.

  19. Effects of nitrate injection on microbial enhanced oil recovery and oilfield reservoir souring.

    Science.gov (United States)

    da Silva, Marcio Luis Busi; Soares, Hugo Moreira; Furigo, Agenor; Schmidell, Willibaldo; Corseuil, Henry Xavier

    2014-11-01

    Column experiments were utilized to investigate the effects of nitrate injection on sulfate-reducing bacteria (SRB) inhibition and microbial enhanced oil recovery (MEOR). An indigenous microbial consortium collected from the produced water of a Brazilian offshore field was used as inoculum. The presence of 150 mg/L volatile fatty acids (VFA´s) in the injection water contributed to a high biological electron acceptors demand and the establishment of anaerobic sulfate-reducing conditions. Continuous injection of nitrate (up to 25 mg/L) for 90 days did not inhibit souring. Contrariwise, in nitrogen-limiting conditions, the addition of nitrate stimulated the proliferation of δ-Proteobacteria (including SRB) and the associated sulfide concentration. Denitrification-specific nirK or nirS genes were not detected. A sharp decrease in water interfacial tension (from 20.8 to 14.5 mN/m) observed concomitantly with nitrate consumption and increased oil recovery (4.3 % v/v) demonstrated the benefits of nitrate injection on MEOR. Overall, the results support the notion that the addition of nitrate, at this particular oil reservoir, can benefit MEOR by stimulating the proliferation of fortuitous biosurfactant-producing bacteria. Higher nitrate concentrations exceeding the stoichiometric volatile fatty acid (VFA) biodegradation demands and/or the use of alternative biogenic souring control strategies may be necessary to warrant effective SRB inhibition down gradient from the injection wells.

  20. Using Biosurfactants Produced from Agriculture Process Waste Streams to Improve Oil Recovery in Fractured Carbonate Reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Stephen Johnson; Mehdi Salehi; Karl Eisert; Sandra Fox

    2009-01-07

    This report describes the progress of our research during the first 30 months (10/01/2004 to 03/31/2007) of the original three-year project cycle. The project was terminated early due to DOE budget cuts. This was a joint project between the Tertiary Oil Recovery Project (TORP) at the University of Kansas and the Idaho National Laboratory (INL). The objective was to evaluate the use of low-cost biosurfactants produced from agriculture process waste streams to improve oil recovery in fractured carbonate reservoirs through wettability mediation. Biosurfactant for this project was produced using Bacillus subtilis 21332 and purified potato starch as the growth medium. The INL team produced the biosurfactant and characterized it as surfactin. INL supplied surfactin as required for the tests at KU as well as providing other microbiological services. Interfacial tension (IFT) between Soltrol 130 and both potential benchmark chemical surfactants and crude surfactin was measured over a range of concentrations. The performance of the crude surfactin preparation in reducing IFT was greater than any of the synthetic compounds throughout the concentration range studied but at low concentrations, sodium laureth sulfate (SLS) was closest to the surfactin, and was used as the benchmark in subsequent studies. Core characterization was carried out using both traditional flooding techniques to find porosity and permeability; and NMR/MRI to image cores and identify pore architecture and degree of heterogeneity. A cleaning regime was identified and developed to remove organic materials from cores and crushed carbonate rock. This allowed cores to be fully characterized and returned to a reproducible wettability state when coupled with a crude-oil aging regime. Rapid wettability assessments for crushed matrix material were developed, and used to inform slower Amott wettability tests. Initial static absorption experiments exposed limitations in the use of HPLC and TOC to determine

  1. Technical bio-oils. Fundamentals - products - framework conditions; Technische Biooele. Grundlagen - Produkte - Rahmenbedingungen

    Energy Technology Data Exchange (ETDEWEB)

    NONE

    2012-03-27

    The Fachagentur Nachwachsende Rohstoffe e.V. (Guelzow-Pruezen, Federal Republic of Germany) and the Federal Ministry of Food, Agriculture and Consumer Protection (Bonn, Federal Republic of Germany) report on technical bio-oils. The contribution under consideration consists of the following chapters: Fundamentals, technical properties, applications, environmental aspects, legal framework conditions, funding measures; market of biological lubricants, economic operation with biological lubricants.

  2. Correlation of fluid inclusions and reservoired oils to infer trap fill history in the South Viking Graben, North Sea

    Energy Technology Data Exchange (ETDEWEB)

    Isaksen, G.H.; Pottorf, R.J. [Exxon Production Research Company, Houston, Texas (United States); Jenssen, A.I. [Esson Norge a.s., Forus (Norway)

    1998-02-01

    Organic geochemical correlations between fluid inclusions and associated oils and oil-shows in Mesozoic reservoirs in the Sleipner area demonstrate generation from the same source rock organic facies (type II) for inclusions in wells 15/9-1 and 15/9-19. For well 15/9-9 the oil show is from a mixed type II/III source rock, whereas the fluid inclusion is from a type II source. all fluid inclusions are less thermally mature than the associated free oils and are thought to represent the earliest hydrocarbon yield from the source rocks. GC/MS/MS analyses of the fluid inclusions proved essential for resolving biomarker compounds and correlating them to reservoired fluids. Among the biomarkers, bisnorhopane contents in the fluid inclusions are consistently lower than the associated reservoired oil. The expected dilution effect of bisnorhopane as progressively more hydrocarbons are generated from kerogen maturation is not observed. The difference in bisnorhopane amounts in fluid inclusions and oils is primarily due to varying hydrocarbon yields, through time, from different source rocks.

  3. Investigating the effect of steam, CO{sub 2}, and surfactant on the recovery of heavy oil reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Tian, S.; He, S. [China Univ. of Petroleum, Beijing (China). MOE Key Laboratory of Petroleum Engineering; Qu, L. [Shengli Oil Field Co. (China)]|[SINOPEC, Shengli (China)

    2008-10-15

    This paper presented the results of a laboratory study and numerical simulation in which the mechanisms of steam injection with carbon dioxide (CO{sub 2}) and surfactant were investigated. The incremental recoveries of 4 different scenarios were compared and analyzed in terms of phase behaviour. The study also investigated the effect of CO{sub 2} dissolution in oil and water; variation of properties of CO{sub 2}-oil phase equilibrium and CO{sub 2}-water phase equilibrium; variation of viscosity; and, oil volume and interfacial tension (IFT) during the recovery process. The expansion of a steam and CO{sub 2} front was also examined. A field application case of a horizontal well in a heavy oil reservoir in Shengli Oilfield in China was used to determine the actual dynamic performance of the horizontal well and to optimize the injection parameters of the CO{sub 2} and surfactant. The study revealed that oil recovery with the simultaneous injection of steam, CO{sub 2} and surfactant was higher than that of steam injection, steam with CO{sub 2} and steam with surfactant. The improved flow performance in super heavy oil reservoirs could be attributed to CO{sub 2} dissolution in oil which can swell the oil and reduce oil viscosity significantly. The proportion of CO{sub 2} in the free gas phase, oil phase and water phase varies with changes in reservoir pressure and temperature. CO{sub 2} decreases the temperature of the steam slightly, while the surfactant decreases the interfacial tension and helps to improve oil recovery. The study showed that the amount of injected CO{sub 2} and steam has a large effect on heavy oil recovery. Although oil production was found to increase with an increase in injected amounts, the ratio of oil to injected fluids must be considered to achieve optimum recovery. High steam quality and temperature can also improve super heavy oil recovery. The oil recovery was less influenced by the effect of the surfactant than by the effect of CO{sub 2

  4. FUNDAMENTALS OF RESERVOIR SURFACE ENERGY AS RELATED TO SURFACE PROPERTIES, WETTABILITY, CAPILLARY ACTION, AND OIL RECOVERY FROM FRACTURED RESERVOIRS BY SPONTANEOUS IMBIBITION

    Energy Technology Data Exchange (ETDEWEB)

    Norman R. Morrow

    2004-07-01

    The objective of this project is to increase oil recovery from fractured reservoirs through improved fundamental understanding of the process of spontaneous imbibition by which oil is displaced from the rock matrix into the fractures. Spontaneous imbibition is fundamentally dependent on the reservoir surface free energy but this has never been investigated for rocks. In this project, the surface free energy of rocks will be determined by using liquids that can be solidified within the rock pore space at selected saturations. Thin sections of the rock then provide a two-dimensional view of the rock minerals and the occupant phases. Saturations and oil/rock, water/rock, and oil/water surface areas will be determined by advanced petrographic analysis and the surface free energy which drives spontaneous imbibition will be determined as a function of increase in wetting phase saturation. The inherent loss in surface free energy resulting from capillary instabilities at the microscopic (pore level) scale will be distinguished from the decrease in surface free energy that drives spontaneous imbibition. A mathematical network/numerical model will be developed and tested against experimental results of recovery versus time over broad variation of key factors such as rock properties, fluid phase viscosities, sample size, shape and boundary conditions. Two fundamentally important, but not previously considered, parameters of spontaneous imbibition, the capillary pressure acting to oppose production of oil at the outflow face and the pressure in the nonwetting phase at the no-flow boundary versus time, will also be measured and modeled. Simulation and network models will also be tested against special case solutions provided by analytic models. In the second stage of the project, application of the fundamental concepts developed in the first stage of the project will be demonstrated. The fundamental ideas, measurements, and analytic/numerical modeling will be applied to mixed

  5. Fundamentals of Reservoir Surface Energy as Related to Surface Properties, Wettability, Capillary Action, and Oil Recovery from Fractured Reservoirs by Spontaneous Imbibition

    Energy Technology Data Exchange (ETDEWEB)

    Norman Morrow; Herbert Fischer; Yu Li; Geoffrey Mason; Douglas Ruth; Siddhartha Seth; Zhengxin Tong; Evren Unsal; Siluni Wickramathilaka; Shaochang Wo; Peigui Yin

    2008-06-30

    The objective of this project is to increase oil recovery from fractured reservoirs through improved fundamental understanding of the process of spontaneous imbibition by which oil is displaced from the rock matrix into the fractures. Spontaneous imbibition is fundamentally dependent on the reservoir surface free energy but this has never been investigated for rocks. In this project, the surface free energy of rocks will be determined by using liquids that can be solidified within the rock pore space at selected saturations. Thin sections of the rock then provide a two-dimensional view of the rock minerals and the occupant phases. Saturations and oil/rock, water/rock, and oil/water surface areas will be determined by advanced petrographic analysis and the surface free energy which drives spontaneous imbibition will be determined as a function of increase in wetting phase saturation. The inherent loss in surface free energy resulting from capillary instabilities at the microscopic (pore level) scale will be distinguished from the decrease in surface free energy that drives spontaneous imbibition. A mathematical network/numerical model will be developed and tested against experimental results of recovery versus time over broad variation of key factors such as rock properties, fluid phase viscosities, sample size, shape and boundary conditions. Two fundamentally important, but not previously considered, parameters of spontaneous imbibition, the capillary pressure acting to oppose production of oil at the outflow face and the pressure in the non-wetting phase at the no-flow boundary versus time, will also be measured and modeled. Simulation and network models will also be tested against special case solutions provided by analytic models. In the second stage of the project, application of the fundamental concepts developed in the first stage of the project will be demonstrated. The fundamental ideas, measurements, and analytic/numerical modeling will be applied to mixed

  6. FUNDAMENTALS OF RESERVOIR SURFACE ENERGY AS RELATED TO SURFACE PROPERTIES, WETTABILITY, CAPILLARY ACTION, AND OIL RECOVERY FROM FRACTURED RESERVOIRS BY SPONTANEOUS IMBIBITION

    Energy Technology Data Exchange (ETDEWEB)

    Norman R. Morrow; Herbert Fischer; Yu Li; Geoffrey Mason; Douglas Ruth; Siddhartha Seth; Peigui Yin; Shaochang Wo

    2005-02-01

    The objective of this project is to increase oil recovery from fractured reservoirs through improved fundamental understanding of the process of spontaneous imbibition by which oil is displaced from the rock matrix into the fractures. Spontaneous imbibition is fundamentally dependent on the reservoir surface free energy but this has never been investigated for rocks. In this project, the surface free energy of rocks will be determined by using liquids that can be solidified within the rock pore space at selected saturations. Thin sections of the rock then provide a two-dimensional view of the rock minerals and the occupant phases. Saturations and oil/rock, water/rock, and oil/water surface areas will be determined by advanced petrographic analysis and the surface free energy which drives spontaneous imbibition will be determined as a function of increase in wetting phase saturation. The inherent loss in surface free energy resulting from capillary instabilities at the microscopic (pore level) scale will be distinguished from the decrease in surface free energy that drives spontaneous imbibition. A mathematical network/numerical model will be developed and tested against experimental results of recovery versus time over broad variation of key factors such as rock properties, fluid phase viscosities, sample size, shape and boundary conditions. Two fundamentally important, but not previously considered, parameters of spontaneous imbibition, the capillary pressure acting to oppose production of oil at the outflow face and the pressure in the nonwetting phase at the no-flow boundary versus time, will also be measured and modeled. Simulation and network models will also be tested against special case solutions provided by analytic models. In the second stage of the project, application of the fundamental concepts developed in the first stage of the project will be demonstrated. The fundamental ideas, measurements, and analytic/numerical modeling will be applied to mixed

  7. FUNDAMENTALS OF RESERVOIR SURFACE ENERGY AS RELATED TO SURFACE PROPERTIES, WETTABILITY, CAPILLARY ACTION, AND OIL RECOVERY FROM FRACTURED RESERVOIRS BY SPONTANEOUS IMBIBITION

    Energy Technology Data Exchange (ETDEWEB)

    Norman R. Morrow; Herbert Fischer; Yu Li; Geoffrey Mason; Douglas Ruth; Siddhartha Seth; Peigui Yin; Shaochang Wo

    2004-10-01

    The objective of this project is to increase oil recovery from fractured reservoirs through improved fundamental understanding of the process of spontaneous imbibition by which oil is displaced from the rock matrix into the fractures. Spontaneous imbibition is fundamentally dependent on the reservoir surface free energy but this has never been investigated for rocks. In this project, the surface free energy of rocks will be determined by using liquids that can be solidified within the rock pore space at selected saturations. Thin sections of the rock then provide a two-dimensional view of the rock minerals and the occupant phases. Saturations and oil/rock, water/rock, and oil/water surface areas will be determined by advanced petrographic analysis and the surface free energy which drives spontaneous imbibition will be determined as a function of increase in wetting phase saturation. The inherent loss in surface free energy resulting from capillary instabilities at the microscopic (pore level) scale will be distinguished from the decrease in surface free energy that drives spontaneous imbibition. A mathematical network/numerical model will be developed and tested against experimental results of recovery versus time over broad variation of key factors such as rock properties, fluid phase viscosities, sample size, shape and boundary conditions. Two fundamentally important, but not previously considered, parameters of spontaneous imbibition, the capillary pressure acting to oppose production of oil at the outflow face and the pressure in the nonwetting phase at the no-flow boundary versus time, will also be measured and modeled. Simulation and network models will also be tested against special case solutions provided by analytic models. In the second stage of the project, application of the fundamental concepts developed in the first stage of the project will be demonstrated. The fundamental ideas, measurements, and analytic/numerical modeling will be applied to mixed

  8. FUNDAMENTALS OF RESERVOIR SURFACE ENERGY AS RELATED TO SURFACE PROPERTIES, WETTABILITY, CAPILLARY ACTION, AND OIL RECOVERY FROM FRACTURED RESERVOIRS BY SPONTANEOUS IMBIBITION

    Energy Technology Data Exchange (ETDEWEB)

    Norman R. Morrow; Herbert Fischer; Yu Li; Geoffrey Mason; Douglas Ruth; Siddhartha Seth; Peigui Yin; Shaochang Wo

    2005-04-01

    The objective of this project is to increase oil recovery from fractured reservoirs through improved fundamental understanding of the process of spontaneous imbibition by which oil is displaced from the rock matrix into the fractures. Spontaneous imbibition is fundamentally dependent on the reservoir surface free energy but this has never been investigated for rocks. In this project, the surface free energy of rocks will be determined by using liquids that can be solidified within the rock pore space at selected saturations. Thin sections of the rock then provide a two-dimensional view of the rock minerals and the occupant phases. Saturations and oil/rock, water/rock, and oil/water surface areas will be determined by advanced petrographic analysis and the surface free energy which drives spontaneous imbibition will be determined as a function of increase in wetting phase saturation. The inherent loss in surface free energy resulting from capillary instabilities at the microscopic (pore level) scale will be distinguished from the decrease in surface free energy that drives spontaneous imbibition. A mathematical network/numerical model will be developed and tested against experimental results of recovery versus time over broad variation of key factors such as rock properties, fluid phase viscosities, sample size, shape and boundary conditions. Two fundamentally important, but not previously considered, parameters of spontaneous imbibition, the capillary pressure acting to oppose production of oil at the outflow face and the pressure in the nonwetting phase at the no-flow boundary versus time, will also be measured and modeled. Simulation and network models will also be tested against special case solutions provided by analytic models. In the second stage of the project, application of the fundamental concepts developed in the first stage of the project will be demonstrated. The fundamental ideas, measurements, and analytic/numerical modeling will be applied to mixed

  9. Fundamentals of reservoir surface energy as related to surface properties, wettability, capillary action, and oil recovery from fractured reservoirs by spontaneous imbibition

    Energy Technology Data Exchange (ETDEWEB)

    Norman R. Morrow; Herbert Fischer; Yu Li; Geoffrey Mason; Douglas Ruth; Siddhartha Seth; Jason Zhengxin Tong; Peigui Yin; Shaochang Wo

    2006-02-01

    The objective of this project is to increase oil recovery from fractured reservoirs through improved fundamental understanding of the process of spontaneous imbibition by which oil is displaced from the rock matrix into the fractures. Spontaneous imbibition is fundamentally dependent on the reservoir surface free energy but this has never been investigated for rocks. In this project, the surface free energy of rocks will be determined by using liquids that can be solidified within the rock pore space at selected saturations. Thin sections of the rock then provide a two-dimensional view of the rock minerals and the occupant phases. Saturations and oil/rock, water/rock, and oil/water surface areas will be determined by advanced petrographic analysis and the surface free energy which drives spontaneous imbibition will be determined as a function of increase in wetting phase saturation. The inherent loss in surface free energy resulting from capillary instabilities at the microscopic (pore level) scale will be distinguished from the decrease in surface free energy that drives spontaneous imbibition. A mathematical network/numerical model will be developed and tested against experimental results of recovery versus time over broad variation of key factors such as rock properties, fluid phase viscosities, sample size, shape and boundary conditions. Two fundamentally important, but not previously considered, parameters of spontaneous imbibition, the capillary pressure acting to oppose production of oil at the outflow face and the pressure in the nonwetting phase at the no-flow boundary versus time, will also be measured and modeled. Simulation and network models will also be tested against special case solutions provided by analytic models. In the second stage of the project, application of the fundamental concepts developed in the first stage of the project will be demonstrated. The fundamental ideas, measurements, and analytic/numerical modeling will be applied to mixed

  10. Optimization of perforation interval for fire flood in thick heavy oil reservoirs%厚层稠油油藏火驱射孔层段优化探讨

    Institute of Scientific and Technical Information of China (English)

    张方礼

    2013-01-01

    火烧油层(火驱)技术已成为辽河油田稠油油藏蒸汽吞吐后主体接替技术之一,目前主要应用于厚层块状普通稠油油藏、薄互层状普通稠油油藏以及超稠油油藏.厚层油藏在火驱过程中火线超覆严重,影响了火驱开发效果.重点针对制约火驱开发效果的注采井射孔技术进行研究探讨,通过室内物理模拟研究认识了厚层火驱二次燃烧现象,通过现场测试及数值模拟认识了厚层油藏平面及纵向火驱动用状况,并应用数值模拟和油藏工程方法对厚层常规火驱、重力火驱注采井射孔层段进行了优化设计,提出了不同火驱方式注采井射孔优化方案.该研究可为厚层稠油油藏火驱开发提供一定的技术借鉴.%In situ combustion (fire flood) has become one of the major substitute techniques for heavy oil recovery after cyclic steam stimulation in the Liaohe oilfield involving thick massive conventional heavy oil reservoir, thin interbedded conventional heavy oil reservoir and ultra heavy oil reservoir. Thick reservoirs exhibit severe fire front override in fire flooding process, thus affected the development result. This research focuses on perforation technique which may restrict fire flood response. The phenomenon of secondary combustion in fire flood for thick reservoirs has been understood through physical simulations; the areal and vertical producing degree of fire flood in thick reservoirs has been understood through field tests and numerical simulations; the perforation interval of injection and production wells in conventional and gravity fire floods for thick reservoirs has been optimized by employing numerical simulation and reservoir engineering methods; and an optimum perforation plan has been proposed for different fire flood schemes. This research offers certain technical reference to fire flood in thick heavy oil reservoirs.

  11. Evolution of seismic velocities in heavy oil sand reservoirs during thermal recovery process

    CERN Document Server

    Nauroy, Jean-François; Guy, N; Baroni, Axelle; Delage, Pierre; Mainguy, Marc; 10.2516/ogst/2012027

    2013-01-01

    In thermally enhanced recovery processes like cyclic steam stimulation (CSS) or steam assisted gravity drainage (SAGD), continuous steam injection entails changes in pore fluid, pore pressure and temperature in the rock reservoir, that are most often unconsolidated or weakly consolidated sandstones. This in turn increases or decreases the effective stresses and changes the elastic properties of the rocks. Thermally enhanced recovery processes give rise to complex couplings. Numerical simulations have been carried out on a case study so as to provide an estimation of the evolution of pressure, temperature, pore fluid saturation, stress and strain in any zone located around the injector and producer wells. The approach of Ciz and Shapiro (2007) - an extension of the poroelastic theory of Biot-Gassmann applied to rock filled elastic material - has been used to model the velocity dispersion in the oil sand mass under different conditions of temperature and stress. A good agreement has been found between these pre...

  12. Inverse Problems in Geosciences: Modelling the Rock Properties of an Oil Reservoir

    DEFF Research Database (Denmark)

    Lange, Katrine

    the probability that a model adhere to prior knowledge by having specific multiple-point statistics, for instance, learned from a training image. Existing methods efficiently sample an a priori probability density function to create a set of acceptable models; but they cannot evaluate the probability of a model......Even the most optimistic forecasts predict that Danish oil production will decrease by 80% in the period between 2006 and 2040, and only a strong innovative technological effort can change that. Due to the geological structures of the subsurface in the Danish part of the North Sea, Denmark...... of the subsurface of the reservoirs. Hence the focus of this work has been on acquiring models of spatial parameters describing rock properties of the subsurface using geostatistical a priori knowledge and available geophysical data. Such models are solutions to often severely under-determined, inverse problems...

  13. Structural style and reservoir development in the west Netherlands oil province

    Energy Technology Data Exchange (ETDEWEB)

    Racero-Baena, A. (Nederlandse Aardolie Maatschappij, Assen (Netherlands)); Drake, S. (Nederlandse Aardolie Maatschappij, Schiedam (Netherlands))

    1993-09-01

    The area of the Rijswijk concession largely coincides with the onshore extent of the west Netherlands basin. To date, oil has been produced from a total of 15 fields within the Rijswijk concession, which have a total STOIIP of about 210 x 10[sup 6]m[sup 3] (1.3 x 10[sup 9] bbl). Reservoirs generally comprise continental and shallow marine clastics of the Upper Jurassic of Lower Cretaceous deposited in synrift and postrift settings. The west netherlands basin was created during a phase of Late Jurassic and Early Cretaceous rifting, characterized by divergent oblique-slip faulting. This resulted in a northwest-southeast-trending block-faulted depression between the London-Brabant Massif to the south, and the Zandvoort Ridge to the north. In the subsequent postrift stage, shallow marine clastics and marls were deposited in a wide basin, with only mild synsedimentary faulting. At the end of the Cretaceous, regional uplift and convergent oblique-slip faulting resulted in basin inversion and the reverse reactivation of preexisting normal faults. Due to the transpressional nature of the basin inversion, narrow asymmetric anticlines were formed, often bounded by upward diverging reverse faults, in the hanging-wall blocks of the former normal faults. These type of structures constitute the general trap geometry of the Cretaceous oil fields in this basin. The acquisition of three-dimensional seismic data has resulted in significantly enhanced structural definition and has lead to the development of new structural and depositional models, which improve the prediction of reservoir distribution and risk assessment.

  14. Effect of Thermophilic Nitrate Reduction on Sulfide Production in High Temperature Oil Reservoir Samples

    Directory of Open Access Journals (Sweden)

    Gloria N. Okpala

    2017-08-01

    Full Text Available Oil fields can experience souring, the reduction of sulfate to sulfide by sulfate-reducing microorganisms. At the Terra Nova oil field near Canada’s east coast, with a reservoir temperature of 95°C, souring was indicated by increased hydrogen sulfide in produced waters (PW. Microbial community analysis by 16S rRNA gene sequencing showed the hyperthermophilic sulfate-reducing archaeon Archaeoglobus in Terra Nova PWs. Growth enrichments in sulfate-containing media at 55–70°C with lactate or volatile fatty acids yielded the thermophilic sulfate-reducing bacterium (SRB Desulfotomaculum. Enrichments at 30–45°C in nitrate-containing media indicated the presence of mesophilic nitrate-reducing bacteria (NRB, which reduce nitrate without accumulation of nitrite, likely to N2. Thermophilic NRB (tNRB of the genera Marinobacter and Geobacillus were detected and isolated at 30–50°C and 40–65°C, respectively, and only reduced nitrate to nitrite. Added nitrite strongly inhibited the isolated thermophilic SRB (tSRB and tNRB and SRB could not be maintained in co-culture. Inhibition of tSRB by nitrate in batch and continuous cultures required inoculation with tNRB. The results suggest that nitrate injected into Terra Nova is reduced to N2 at temperatures up to 45°C but to nitrite only in zones from 45 to 65°C. Since the hotter zones of the reservoir (65–80°C are inhabited by thermophilic and hyperthermophilic sulfate reducers, souring at these temperatures might be prevented by nitrite production if nitrate-reducing zones of the system could be maintained at 45–65°C.

  15. Petrophysical Clasification of Different Rocks in Carbonate Reservoirs of the Northern Cuban Heavy Oil Belt

    Directory of Open Access Journals (Sweden)

    Odalys Reyes Paredes

    2014-09-01

    Full Text Available The permeability is one of the main parameters to classify the porosity environment, this parametercan't be measured by log's tools, and it has no direct relation with the total porosity. It is closely relatedto the kind of rock (size and distribution of particles. In the Northern Cuban Heavy Oil Belt (FNCPC,the reservoirs are made up of carbonate rocks (mudstone / wackestone, with fracture porosity andother types of porosity such as: joins of dissolution and estilolitos formed from diagenetic processes.The different formations frequently show heterogeneities that can be noticeable hindering their owncharacterization. The cores present a very poor recuperation and on numerous occasions recoveringonly intervals that don't contribute anything to the flow of fluids. The analysis about different kinds ofrocks is done in this article; it is conceived throughout data of cores and thin sections. The petrophysicalclassification of different kinds of rocks for carbonate reservoirs are established from the porosity andpermeability relationships and porosity environment structure.

  16. Advanced reservoir characterization for improved oil recovery in a New Mexico Delaware basin project

    Energy Technology Data Exchange (ETDEWEB)

    Martin, F.D.; Kendall, R.P.; Whitney, E.M. [Dave Martin and Associates, Inc., Socorro, NM (United States)] [and others

    1997-08-01

    The Nash Draw Brushy Canyon Pool in Eddy County, New Mexico is a field demonstration site in the Department of Energy Class III program. The basic problem at the Nash Draw Pool is the low recovery typically observed in similar Delaware fields. By comparing a control area using standard infill drilling techniques to a pilot area developed using advanced reservoir characterization methods, the goal of the project is to demonstrate that advanced technology can significantly improve oil recovery. During the first year of the project, four new producing wells were drilled, serving as data acquisition wells. Vertical seismic profiles and a 3-D seismic survey were acquired to assist in interwell correlations and facies prediction. Limited surface access at the Nash Draw Pool, caused by proximity of underground potash mining and surface playa lakes, limits development with conventional drilling. Combinations of vertical and horizontal wells combined with selective completions are being evaluated to optimize production performance. Based on the production response of similar Delaware fields, pressure maintenance is a likely requirement at the Nash Draw Pool. A detailed reservoir model of pilot area was developed, and enhanced recovery options, including waterflooding, lean gas, and carbon dioxide injection, are being evaluated.

  17. Diagenesis of the Silurian oil reservoir rock from the Kudirka Atoll in Lithuania

    Energy Technology Data Exchange (ETDEWEB)

    Stentoft, N.; Lapinskas, P.; Musteikis, P.; Kristensen, L.

    2001-07-01

    The Upper Solurian limestone rocks of the Kudirka Atoll reef-complex show a complex diagnetic history. By thin section petrography on 50 samples from 7 wells the following sequence of diagenetic events (from oldest to youngest) could be established with a rather high degree of certainty: Compaction/dewatering {yields} Early lithification {yields} Insignificant fracturing {yields} ?First generation of leaching {yields} Precipitation of first generation of inter-/intra-granular calcite cement {yields} Precipitation of second generation of inter-/intra-granular calcite cement {yields} Recrystallization of lime mud, sparry calcite cements, and fossils {yields} Chemical compaction with formation of stylolite-associated fractures {yields} Precipitation of dolomite, pyrite and silica crystals {yields} Second generation of leaching with stylolite surfaces acting as conduits for aggressive fluids {yields} Oil emplacement. In all types of reef rock the late diagenetic leaching phase has favourably influenced the present reservoir quality ({kappa} and {phi}). No clear correlation was found between rock texture and reservoir quality. The numerous crinoid fragments in samples of biosparite/biosparrudite and poorly washed biosparite/biosparudite are primarily responsible for that, as the rate of growth of syntaxial rimcement on the single-crystalline echinoderm fragments was far greater than the rate og growth of cement on associated multi-crystalline fossils. However, the calcite-replacing calcitic dolomite-crystals, that are associated with the stylolitic joints, have also inplaces contributed to the lacking correlation (au)

  18. Reservoir heterogeneities, in fractured fluvial reservoirs of the Buchan oil field (Central North Sea); Heterogeneites du reservoir fluvial et fracture du champ petrolifere de Buchan (partie centrale de la mer du Nord)

    Energy Technology Data Exchange (ETDEWEB)

    Benzagouta, M.S. [Universite de Constantine, Dept. de Geologie, Constantine (Algeria); Turner, B.R. [University of Durham, Dept. of Geological Sciences, Durham DH (United Kingdom); Nezzal, F. [Universite de Bab Ezzouar, Faculte des Sciences de la Terre, Alger (Algeria); Kaabi, A. [Universite de Constantine, Institut de Genie Civil, Constantine (Algeria)

    2001-07-01

    The Buchan Oil field in the central North Sea is a structurally complex, pervasively fractured Upper Devonian-Carboniferous reservoir comprising vertically stacked, sandstone-dominated, fining-upward sequences deposited predominantly by braided streams. Hierarchical analysis of reservoir quality at the micro-scale (thin sections), meso-scale (litho-facies and facies sequences) and mega-scale (zones composed of more than one mesoscale sequence) levels shows that the reservoir can be divided into six mega-scale units based on their sedimentological properties, poro-permeability values and electric log response. The micro-scale and mesoscale properties of these units, particularly the presence of fractures and variations in the correlation coefficient between the logarithm of permeability and porosity, provide a means of defining effective and non-effective reservoir zones, which correspond with, or occur within the units. The most effective zone, between 2738 and 2788 m, consists predominantly of extensively fractured sub-arkoses which differ from other sandstones in the reservoir in that they contain more preserved primary intergranular porosity and secondary fracture porosity, with porosity values up to 30.2%, and permeabilities up to 1475 mD. This zone extends across most of the field where it defines, more precisely than has previously been possible, the best quality and most productive part of the reservoir section. (authors)

  19. Geological and petrophysical characterization of the Ferron Sandstone for 3-D simulation of a fluvial-deltaic reservoir. Technical progress report, January 1, 1995--March 31, 1995

    Energy Technology Data Exchange (ETDEWEB)

    Allison, M.L.

    1995-05-02

    The objective of this project is to develop a comprehensive, interdisciplinary, and quantitative characterization of a fluvial-deltaic reservoir which will allow realistic inter-well and reservoir-scale modeling to be developed for improved oil-field development in similar reservoirs world-wide. The geological and petrophysical properties of the Cretaceous Ferron Sandstone in east-central Utah will be quantitatively determined. Both new and existing data will be integrated into a three-dimensional representation of spatial variations in porosity, storativity, and tensorial rock permeability at a scale appropriate for inter-well to regional-scale reservoir simulation. Results could improve reservoir management through proper infill and extension drilling strategies, reduction of economic risks, increased recovery from existing oil fields, and more reliable reserve calculations. Transfer of the project results to the petroleum industry is an integral component of the project.

  20. Sequential Extraction on Oil Sandstones from TZ401 Well——A Case Study on Filling History of Hydrocarbon Reservoir

    Institute of Scientific and Technical Information of China (English)

    Pan Changchun; Liu Dayong

    2008-01-01

    Sequential extraction was performed on two oil sandstones from the Upper Carboniferous oil columns of TZ401 well.The free oils of these two oil sandstones and a crude oil from the Lower Carboniferous oil column of this well have low ratios of C28/C27+C28+ C29) steranes and gammacerane/C31 hopanes,ranging of 0.11-0.16 and 0.09-0.15,respectively,similar to those from the Middle-Upper Ordovician source rock.However,these two ratios for the adsorbed and inclusion oils of these two oil sandstones are relatively high,ranging of 0.29-0.31 and 0.26-0.40,respectively,similar to those of the Cambrian-Lower Ordovician source rock.This result demonstrates that the initial oil charging the reservoirs was derived from the Cambrian-Lower Ordovician source rock,whereas the later charging oil was derived from the Middle--Upper Ordovician source rock.

  1. Geochemical controls of the oils acidity in petroleum reservoirs; Controles geochimiques de l'acidite des huiles dans les reservoirs petroliers

    Energy Technology Data Exchange (ETDEWEB)

    Rouquette, N.

    2004-12-01

    Within the framework of this thesis, we were interested in the study of acid oils. Thus, after having developed an analytical method to separate acids from crude oils, this one was applied to the analysis of several series of acid oils presenting various degrees of biodegradation. In the first chapter devoted to their molecular study, it was shown that the alteration of the organic matter proceeds according to a quasi-stepwise order and that the major part of the carboxylic acids appeared as an Unresolved Complex Mixture. The only identified resolved compounds were apparently not formed by biodegradation of the oil in place but rather seem either to have been incorporated during oil migration, or to correspond to compounds initially present in the reservoir rock. Among those, we isolated and identified by NMR a new higher plant tri-terpenic derivative, the 24-nor,28-lupanoic acid. In the second chapter, a new method to evaluate acidity, applicable to small quantities of oil, was developed. This one is based on the methylation of the acid species by iodo-methane marked with carbon 13. In the case of a series from the Gulf of Guinea tested initially, the enrichment after labelling presents a perfect correlation with the values of acidity measured by the TAN method (for 'Total Acid Number'). The isotopic labelling method was applied later to a broader range of oil samples. As a whole, a linear correlation seems to exist between {sup 13}C labelling and TAN index, which lets consider that this method could represent an interesting alternative to the measurement of the TAN index in oil exploration. (author)

  2. 3-D RESERVOIR AND STOCHASTIC FRACTURE NETWORK MODELING FOR ENHANCED OIL RECOVERY, CIRCLE RIDGE PHOSPHORIA/TENSLEEP RESERVOIR, WIND RIVER RESERVATION, ARAPAHO AND SHOSHONE TRIBES, WYOMING

    Energy Technology Data Exchange (ETDEWEB)

    Paul La Pointe; Jan Hermanson; Robert Parney; Thorsten Eiben; Mike Dunleavy; Ken Steele; John Whitney; Darrell Eubanks; Roger Straub

    2002-11-18

    This report describes the results made in fulfillment of contract DE-FG26-00BC15190, ''3-D Reservoir and Stochastic Fracture Network Modeling for Enhanced Oil Recovery, Circle Ridge Phosphoria/Tensleep Reservoir, Wind River Reservation, Arapaho and Shoshone Tribes, Wyoming''. The goal of this project is to improve the recovery of oil from the Tensleep and Phosphoria Formations in Circle Ridge Oilfield, located on the Wind River Reservation in Wyoming, through an innovative integration of matrix characterization, structural reconstruction, and the characterization of the fracturing in the reservoir through the use of discrete fracture network models. Fields in which natural fractures dominate reservoir permeability, such as the Circle Ridge Field, often experience sub-optimal recovery when recovery processes are designed and implemented that do not take advantage of the fracture systems. For example, a conventional waterflood in a main structural block of the Field was implemented and later suspended due to unattractive results. It is estimated that somewhere less than 20% of the OOIP in the Circle Ridge Field have been recovered after more than 50 years' production. Marathon Oil Company identified the Circle Ridge Field as an attractive candidate for several advanced IOR processes that explicitly take advantage of the natural fracture system. These processes require knowledge of the distribution of matrix porosity, permeability and oil saturations; and understanding of where fracturing is likely to be well-developed or poorly developed; how the fracturing may compartmentalize the reservoir; and how smaller, relatively untested subthrust fault blocks may be connected to the main overthrust block. For this reason, the project focused on improving knowledge of the matrix properties, the fault block architecture and to develop a model that could be used to predict fracture intensity, orientation and fluid flow/connectivity properties. Knowledge

  3. Advanced Oil Recovery Technologies for Improved Recovery from Slope Basin Clastic Reservoirs, Nash Draw Brushy Canyon Pool, Eddy County, NM

    Energy Technology Data Exchange (ETDEWEB)

    Mark B. Murphy

    2005-09-30

    The Nash Draw Brushy Canyon Pool in Eddy County New Mexico was a cost-shared field demonstration project in the U.S. Department of Energy Class III Program. A major goal of the Class III Program was to stimulate the use of advanced technologies to increase ultimate recovery from slope-basin clastic reservoirs. Advanced characterization techniques were used at the Nash Draw Pool (NDP) project to develop reservoir management strategies for optimizing oil recovery from this Delaware reservoir. The objective of the project was to demonstrate that a development program, which was based on advanced reservoir management methods, could significantly improve oil recovery at the NDP. Initial goals were (1) to demonstrate that an advanced development drilling and pressure maintenance program can significantly improve oil recovery compared to existing technology applications and (2) to transfer these advanced methodologies to other oil and gas producers. Analysis, interpretation, and integration of recently acquired geological, geophysical, and engineering data revealed that the initial reservoir characterization was too simplistic to capture the critical features of this complex formation. Contrary to the initial characterization, a new reservoir description evolved that provided sufficient detail regarding the complexity of the Brushy Canyon interval at Nash Draw. This new reservoir description was used as a risk reduction tool to identify 'sweet spots' for a development drilling program as well as to evaluate pressure maintenance strategies. The reservoir characterization, geological modeling, 3-D seismic interpretation, and simulation studies have provided a detailed model of the Brushy Canyon zones. This model was used to predict the success of different reservoir management scenarios and to aid in determining the most favorable combination of targeted drilling, pressure maintenance, well stimulation, and well spacing to improve recovery from this reservoir. An

  4. Technical aspects of biodiesel production from vegetable oils

    Directory of Open Access Journals (Sweden)

    Krishnakumar Janahiraman

    2008-01-01

    Full Text Available Biodiesel, a promising substitute as an alternative fuel has gained significant attention due to the finite nature of fossil energy sources and does not produce sulfur oxides and minimize the soot particulate in comparison with the existing one from petroleum diesel. The utilization of liquid fuels such as biodiesel produced from vegetable oil by transesterification process represents one of the most promising options for the use of conventional fossil fuels. In the first step of this experimental research, edible rice bran oil used as test material and converted into methyl ester and non-edible jatropha vegetable oil is converted into jatropha oil methyl ester, which are known as biodiesel and they are prepared in the presence of homogeneous acid catalyst and optimized their operating parameters like reaction temperature, quantity of alcohol and the catalyst requirement, stirring rate and time of esterification. In the second step, the physical properties such as density, flash point, kinematic viscosity, cloud point, and pour point were found out for the above vegetable oils and their methyl esters. The same characteristics study was also carried out for the diesel fuel for obtaining the baseline data for analysis. The values obtained from the rice bran oil methyl ester and jatropha oil methyl ester are closely matched with the values of conventional diesel and it can be used in the existing diesel engine without any hardware modification. In the third step the storage characteristics of biodiesel are also studied. .

  5. Design and Operation of Laboratory Combustion Cell for Air Injection into Light Oil Reservoirs: Potential Application in Sindh Field

    Directory of Open Access Journals (Sweden)

    Abdul Haque Tunio

    2011-01-01

    Full Text Available Historical experimental work on the combustion oil recovery processes consists of both laboratory and field studies. Although field experiments are the ultimate test of any oil recovery process, they are costly, time consuming and difficult to analyze quantitatively. Laboratory CC (Combustion Cell experiments are cost effective and less time consuming, but are subject to scaling and interpretation challenges. Experimental set up has been developed to understand air injection process for improving oil recovery from light oil reservoirs taking into account the sand pack petro physical and fluid properties. Some important design problems; operational criteria and considerations important to interpretation of results are pointed out. To replicate subsurface reservoir conditions or pressure and temperature, experiments up to 6895 KPa, at non-isothermal conditions with 5oC/min ramp-up are performed on unconsolidated cores with reservoir oil samples. Correlations were obtained for low temperature oxidation rate of oil, the fuel deposition rate and the rate of burning fuel as a fuel concentration. Various parameters such as (sand pack, pressure, oil saturation and flow rate/air flux were changed to investigate their impact on reaction and chemical nature of the fuel burned. To determine the importance of distribution and pyrolysis on these reactions, the hydrogen-carbon ratio and m-ratio was calculated. For further confirmation Arrhenius graphs were drawn by assuming 1.0 order of reaction with carbon concentration which is also confirmed.This research will contribute to the overall understanding of air injection process;help to determine the most appropriate

  6. Impact of an indigenous microbial enhanced oil recovery field trial on microbial community structure in a high pour-point oil reservoir.

    Science.gov (United States)

    Zhang, Fan; She, Yue-Hui; Li, Hua-Min; Zhang, Xiao-Tao; Shu, Fu-Chang; Wang, Zheng-Liang; Yu, Long-Jiang; Hou, Du-Jie

    2012-08-01

    Based on preliminary investigation of microbial populations in a high pour-point oil reservoir, an indigenous microbial enhanced oil recovery (MEOR) field trial was carried out. The purpose of the study is to reveal the impact of the indigenous MEOR process on microbial community structure in the oil reservoir using 16Sr DNA clone library technique. The detailed monitoring results showed significant response of microbial communities during the field trial and large discrepancies of stimulated microorganisms in the laboratory and in the natural oil reservoir. More specifically, after nutrients injection, the original dominant populations of Petrobacter and Alishewanella in the production wells almost disappeared. The expected desirable population of Pseudomonas aeruginosa, determined by enrichment experiments in laboratory, was stimulated successfully in two wells of the five monitored wells. Unexpectedly, another potential population of Pseudomonas pseudoalcaligenes which were not detected in the enrichment culture in laboratory was stimulated in the other three monitored production wells. In this study, monitoring of microbial community displayed a comprehensive alteration of microbial populations during the field trial to remedy the deficiency of culture-dependent monitoring methods. The results would help to develop and apply more MEOR processes.

  7. Eos modeling and reservoir simulation study of bakken gas injection improved oil recovery in the elm coulee field, Montana

    Science.gov (United States)

    Pu, Wanli

    The Bakken Formation in the Williston Basin is one of the most productive liquid-rich unconventional plays. The Bakken Formation is divided into three members, and the Middle Bakken Member is the primary target for horizontal wellbore landing and hydraulic fracturing because of its better rock properties. Even with this new technology, the primary recovery factor is believed to be only around 10%. This study is to evaluate various gas injection EOR methods to try to improve on that low recovery factor of 10%. In this study, the Elm Coulee Oil Field in the Williston Basin was selected as the area of interest. Static reservoir models featuring the rock property heterogeneity of the Middle Bakken Member were built, and fluid property models were built based on Bakken reservoir fluid sample PVT data. By employing both compositional model simulation and Todd-Longstaff solvent model simulation methods, miscible gas injections were simulated and the simulations speculated that oil recovery increased by 10% to 20% of OOIP in 30 years. The compositional simulations yielded lower oil recovery compared to the solvent model simulations. Compared to the homogeneous model, the reservoir model featuring rock property heterogeneity in the vertical direction resulted in slightly better oil recovery, but with earlier CO2 break-through and larger CO2 production, suggesting that rock property heterogeneity is an important property for modeling because it has a big effect on the simulation results. Long hydraulic fractures shortened CO2 break-through time greatly and increased CO 2 production. Water-alternating-gas injection schemes and injection-alternating-shut-in schemes can provide more options for gas injection EOR projects, especially for gas production management. Compared to CO2 injection, separator gas injection yielded slightly better oil recovery, meaning separator gas could be a good candidate for gas injection EOR; lean gas generated the worst results. Reservoir

  8. An Integrated Approach to Characterizing Bypassed Oil in Heterogeneous and Fractured Reservoirs Using Partitioning Tracers

    Energy Technology Data Exchange (ETDEWEB)

    Akhil Datta-Gupta

    2006-12-31

    . The approach is very fast and avoids much of the subjective judgments and time-consuming trial-and-errors associated with manual history matching. We demonstrate the power and utility of our approach using a synthetic example and two field examples. We have also explored the use of a finite difference reservoir simulator, UTCHEM, for field-scale design and optimization of partitioning interwell tracer tests. The finite-difference model allows us to include detailed physics associated with reactive tracer transport, particularly those related with transverse and cross-streamline mechanisms. We have investigated the potential use of downhole tracer samplers and also the use of natural tracers for the design of partitioning tracer tests. Finally, we discuss several alternative ways of using partitioning interwell tracer tests (PITTs) in oil fields for the calculation of oil saturation, swept pore volume and sweep efficiency, and assess the accuracy of such tests under a variety of reservoir conditions.

  9. Alteration of Na+ and K+ ion composition of microbial consortium isolated from oil reservoir at high salinities

    DEFF Research Database (Denmark)

    Rudyk, Svetlana Nikolayevna; Søgaard, Erik Gydesen

    2010-01-01

    The microbes being injected into the oil layers for the purpose of Microbial Enhanced Oil Recovery (MEOR) undergo the influence of extreme environment of oil reservoir like high salinity, high temperature and high pressure which can suppress their viability and production of the desired by...... concentration, but for K+ that effect can be just due to the processes that occurred within microbes. Moreover, the K+-concentration significantly increases and Na+-concentration decreases after 8th day of experiment showing that K+ move out of the cell and Na+ move in. Negative correlation between pH change...... in the adaption to salinity [1-3]. The change in the concentration of Na+ and K+ cations in the microbial solution exposed to higher concentrations of sodium chloride was under investigation. The experiment was conducted with the consortium of microbes isolated from the oil-saturated core sample extracted from...

  10. Comparison of bacterial community in aqueous and oil phases of water-flooded petroleum reservoirs using pyrosequencing and clone library approaches.

    Science.gov (United States)

    Wang, Li-Ying; Ke, Wen-Ji; Sun, Xiao-Bo; Liu, Jin-Feng; Gu, Ji-Dong; Mu, Bo-Zhong

    2014-05-01

    Bacterial communities in both aqueous and oil phases of water-flooded petroleum reservoirs were characterized by molecular analysis of bacterial 16S rRNA genes obtained from Shengli Oil Field using DNA pyrosequencing and gene clone library approaches. Metagenomic DNA was extracted from the aqueous and oil phases and subjected to polymerase chain reaction amplification with primers targeting the bacterial 16S rRNA genes. The analysis by these two methods showed that there was a large difference in bacterial diversity between the aqueous and oil phases of the reservoir fluids, especially in the reservoirs with lower water cut. At a high phylogenetic level, the predominant bacteria detected by these two approaches were identical. However, pyrosequencing allowed the detection of more rare bacterial species than the clone library method. Statistical analysis showed that the diversity of the bacterial community of the aqueous phase was lower than that of the oil phase. Phylogenetic analysis indicated that the vast majority of sequences detected in the water phase were from members of the genus Arcobacter within the Epsilonproteobacteria, which is capable of degrading the intermediates of hydrocarbon degradation such as acetate. The oil phase of reservoir fluid samples was dominated by members of the genus Pseudomonas within the Gammaproteobacteria and the genus Sphingomonas within the Alphaproteobacteria, which have the ability to degrade crude oil through adherence to hydrocarbons under aerobic conditions. In addition, many anaerobes that could degrade the component of crude oil were also found in the oil phase of reservoir fluids, mainly in the reservoir with lower water cut. These were represented by Desulfovibrio spp., Thermodesulfovibrio spp., Thermodesulforhabdus spp., Thermotoga spp., and Thermoanaerobacterium spp. This research suggested that simultaneous analysis of DNA extracted from both aqueous and oil phases can facilitate a better understanding of the

  11. Evolution of overpressured and underpressured oil and gas reservoirs, Anadarko Basin of Oklahoma, Texas, and Kansas

    Science.gov (United States)

    Nelson, Phillip H.; Gianoutsos, Nicholas J.

    2011-01-01

    Departures of resistivity logs from a normal compaction gradient indicate that overpressure previously extended north of the present-day overpressured zone. These indicators of paleopressure, which are strongest in the deep basin, are mapped to the Kansas-Oklahoma border in shales of Desmoinesian age. The broad area of paleopressure has contracted to the deep basin, and today the overpressured deep basin, as determined from drillstem tests, is bounded on the north by strata with near normal pressures (hydrostatic), grading to the northwest to pressures that are less than hydrostatic (underpressured). Thus the pressure regime in the northwest portion of the Anadarko Basin has evolved from paleo-overpressure to present-day underpressure. Using pressure data from drillstem tests, we constructed cross sections and potentiometric maps that illustrate the extent and nature of present-day underpressuring. Downcutting and exposure of Lower Permian and Pennsylvanian strata along, and east of, the Nemaha fault zone in central Oklahoma form the discharge locus where pressure reaches near atmospheric. From east to west, hydraulic head increases by several hundred feet in each rock formation, whereas elevation increases by thousands of feet. The resulting underpressuring of the aquifer-supported oil and gas fields, which also increases from east to west, is a consequence of the vertical separation between surface elevation and hydraulic head. A 1,000-ft thick cap of Permian evaporites and shales isolates the underlying strata from the surface, preventing re-establishment of a normal hydrostatic gradient. Thus, the present-day pressure regime of oil and gas reservoirs, overpressured in the deep basin and underpressured on the northwest flank of the basin, is the result of two distinct geologic events-rapid burial and uplift/erosion-widely separated in time.

  12. Oil biodegradation by Bacillus strains isolated from the rock of an oil reservoir located in a deep-water production basin in Brazil

    Energy Technology Data Exchange (ETDEWEB)

    Duarte da Cunha, C.; Rosado, A.S.; Seldin, L.; Weid, I. von der [Universidade Federal do Rio de Janeiro (Brazil). Dept. de Microbiologia Geral; Sebastian, G.V. [CENPES, Petrobras, Ilha do Fundao, Rio de Janeiro (Brazil)

    2006-12-15

    Sixteen spore forming Gram-positive bacteria were isolated from the rock of an oil reservoir located in a deep-water production basin in Brazil. These strains were identified as belonging to the genus Bacillus using classical biochemical techniques and API 50CH kits, and their identity was confirmed by sequencing of part of the 16S rRNA gene. All strains were tested for oil degradation ability in microplates using Arabian Light and Marlin oils and only seven strains showed positive results in both kinds of oils. They were also able to grow in the presence of carbazole, n-hexadecane and polyalphaolefin (PAO), but not in toluene, as the only carbon sources. The production of key enzymes involved with aromatic hydrocarbons biodegradation process by Bacillus strains (catechol 1,2-dioxygenase and catechol 2,3-dioxygenase) was verified spectrophotometrically by detection of cis,cis-muconic acid and 2-hydroxymuconic semialdehyde, and results indicated that the ortho ring cleavage pathway is preferential. Furthermore, polymerase chain reaction (PCR) products were obtained when the DNA of seven Bacillus strains were screened for the presence of catabolic genes encoding alkane monooxygenase, catechol 1,2-dioxygenase, and/or catechol 2,3-dioxygenase. This is the first study on Bacillus strains isolated from an oil reservoir in Brazil. (orig.)

  13. Oil and gas reservoir exploration based on hyperspectral remote sensing and super-low-frequency electromagnetic detection

    Science.gov (United States)

    Qin, Qiming; Zhang, Zili; Chen, Li; Wang, Nan; Zhang, Chengye

    2016-01-01

    This paper proposes a method that combined hyperspectral remote sensing with super-low-frequency (SLF) electromagnetic detection to extract oil and gas reservoir characteristics from surface to underground, for the purpose of determining oil and gas exploration target regions. The study area in Xinjiang Karamay oil-gas field, China, was investigated. First, a Hyperion dataset was used to extract altered minerals (montmorillonite, chlorite, and siderite), which were comparatively verified by field survey and spectral measurement. Second, the SLF electromagnetic datasets were then acquired where the altered minerals were distributed. An inverse distance weighting method was utilized to acquire two-dimensional profiles of the electrical feature distribution of different formations on the subsurface. Finally, existing geological data, field work, and the results derived from Hyperion images and SLF electromagnetic datasets were comprehensively analyzed to confirm the oil and gas exploration target region. The results of both hyperspectral remote sensing and SLF electromagnetic detection had a good consistency with the geological materials in this study. This paper demonstrates that the combination of hyperspectral remote sensing and SLF electromagnetic detection is suitable for the early exploration of oil and gas reservoirs, which is characterized by low exploration costs, large exploration areas, and a high working efficiency.

  14. In-depth Permeability Modifier for Improvement of Sweep Efficiency in a Heterogeneous Oil Reservoir: A Review

    Directory of Open Access Journals (Sweden)

    Abdelazim Abbas Ahmed

    2015-01-01

    Full Text Available This study reviews and assessed some of in-depth permeability modification techniques used in the industry with regards to improving conformance problems in heterogeneous oil reservoirs. Reservoir conformance problems frequently limit the success of many of water and chemical EOR flooding projects. Basically, there are many types of conformance problems and many different conformance improvement techniques. The challenge is to properly identify and then to select a suitable conformance improvement technology. Conventionally, In-situ gels have been widely used and placed near the well-bore of injectors or producers to improve conformance. However, in heterogeneous reservoirs permeability variation extends throughout the whole reservoir structure and in some cases presence of cross-flow between adjacent layers limits the effectiveness of in-situ gels. Alternatively, conformance improvement has been obtained by continuous polymer injection. This method still by-passes significant amounts of oil as evidenced from a number of recent reports. Preformed cross-linked gel particles have become an interesting technology to overcome some of the distinct drawbacks of in In-situ gels and polymer flooding. Although, this method show promising oil improvement, lack of in-depth knowledge is available as well as their mechanisms to plug rock pores are not fully understood. It's the aim of the study to review the reservoir conformance problems as well as conformance improvement techniques. The focus has been given to studies of current in-depth permeability modifiers and highlight chemistry, applications and inadequacy of these technologies. Finally we briefly outline the major challenges, which must be addressed to successfully implement preformed cross-liked particles in improving sweep efficiency applications are highlighted.

  15. Optimization of Vertical Well Placement for Oil Field Development Based on Basic Reservoir Rock Properties using Genetic Algorithm

    Directory of Open Access Journals (Sweden)

    Tutuka Ariadji

    2012-07-01

    Full Text Available Comparing the quality of basic reservoir rock properties is a common practice to locate new infills or development wells for optimizing an oil field development using a reservoir simulation. The conventional technique employs a manual trial and error process to find new well locations, which proves to be time-consuming, especially, for a large field. Concerning this practical matter, an alternative in the form of a robust technique was introduced in order that time and efforts could be reduced in finding best new well locations capable of producing the highest oil recovery. The objective of the research was to apply Genetic Algorithm (GA in determining wells locations using reservoir simulation to avoid the manual conventional trial and error method. GA involved the basic rock properties, i.e., porosity, permeability, and oil saturation, of each grid block obtained from a reservoir simulation model, which was applied into a newly generated fitness function formulated through translating the common engineering practice in the reservoir simulation into a mathematical equation and then into a computer program. The maximum of the fitness value indicated a final searching of the best grid location for a new well location. In order to evaluate the performance of the generated GA program, two fields that had different production profile characteristics, namely the X and Y fields, were applied to validate the proposed method. The proposed GA method proved to be a robust and accurate method to find the best new well locations for field development. The key success of this proposed GA method is in the formulation of the objective function.

  16. Analysis of the heavy oil production technology effectiveness using natural thermal convection with heat agent recirculation method in reservoirs with varying initial water saturation

    Science.gov (United States)

    Osnos, V. B.; Kuneevsky, V. V.; Larionov, V. M.; Saifullin, E. R.; Gainetdinov, A. V.; Vankov, Yu V.; Larionova, I. V.

    2017-01-01

    The method of natural thermal convection with heat agent recirculation (NTC HAR) in oil reservoirs is described. The analysis of the effectiveness of this method for oil reservoir heating with the values of water saturation from 0 to 0.5 units is conducted. As the test element Ashalchinskoye oil field is taken. CMG STARS software was used for calculations. Dynamics of cumulative production, recovery factor and specific energy consumption per 1 m3 of crude oil produced in the application of the heat exchanger with heat agent in cases of different initial water saturation are defined and presented as graphs.

  17. Technical review of enhanced oil recovery literature. Final report

    Energy Technology Data Exchange (ETDEWEB)

    None

    1980-04-01

    This report represents the work done under DOE grant No. DE-FG05-79ER10086. It reviews the chemical, miscible and thermal areas of enhanced and recovery (EOR) and has produced a comprehensive bibliography and glossary of terms. The analysis looks into several areas of interest, including: screening criteria, process design, variable interaction and reservoir applicability. In this summary section, the following are shown: (1) screening criteria for process selection; (2) screening guide summary for EOR process; and (3) representative schematics of three major process operations.

  18. Identification and evaluation of fluvial-dominated deltaic (Class I oil) reservoirs in Oklahoma. Final report, August 1998

    Energy Technology Data Exchange (ETDEWEB)

    Banken, M.K.

    1998-11-01

    The Oklahoma Geological Survey (OGS), the Geo Information Systems department, and the School of Petroleum and Geological Engineering at the University of Oklahoma have engaged in a five-year program to identify and address Oklahoma`s oil recovery opportunities in fluvial-dominated deltaic (FDD) reservoirs. This program included a systematic and comprehensive collection and evaluation of information on all FDD oil reservoirs in Oklahoma and the recovery technologies that have been (or could be) applied to those reservoirs with commercial success. The execution of this project was approached in phases. The first phase began in January, 1993 and consisted of planning, play identification and analysis, data acquisition, database development, and computer systems design. By the middle of 1994, many of these tasks were completed or nearly finished including the identification of all FDD reservoirs in Oklahoma, data collection, and defining play boundaries. By early 1995, a preliminary workshop schedule had been developed for project implementation and technology transfer activities. Later in 1995, the play workshop and publication series was initiated with the Morrow and the Booch plays. Concurrent with the initiation of the workshop series was the opening of a computer user lab that was developed for use by the petroleum industry. Industry response to the facility initially was slow, but after the first year lab usage began to increase and is sustaining. The remaining six play workshops were completed through 1996 and 1997, with the project ending on December 31, 1997.

  19. Improved Oil Recovery in Mississippian Carbonate Reservoirs of Kansas - Near-Term, Class II

    Energy Technology Data Exchange (ETDEWEB)

    Carr, Timothy R.; Green, Don W.; Willhite, G. Paul

    2001-10-30

    The focus of this project was development and demonstration of cost-effective reservoir description and management technologies to extend the economic life of mature reservoirs in Kansas and the mid-continent.

  20. Pressure Transient Behavior of Horizontal Well with Time-Dependent Fracture Conductivity in Tight Oil Reservoirs

    Directory of Open Access Journals (Sweden)

    Qihong Feng

    2017-01-01

    Full Text Available This work presents a discussion on the pressure transient response of multistage fractured horizontal well in tight oil reservoirs. Based on Green’s function, a semianalytical model is put forward to obtain the behavior. Our proposed model accounts for fluid flow in four contiguous regions of the tight formation by using pressure continuity and mass conservation. The time-dependent conductivity of hydraulic fractures, which is ignored in previous models but highlighted by recent experiments, is also taken into account in our proposed model. We also include the effect of pressure drop along a horizontal wellbore. We substantiate the validity of our model and analyze the different flow regimes, as well as the effects of initial conductivity, fracture distribution, and geometry on the pressure transient behavior. Our results suggest that the decrease of fracture conductivity has a tremendous effect on the well performance. Finally, we compare our model results with the field data from a multistage fractured horizontal well in Jimsar sag, Xinjiang oilfield, and a good agreement is obtained.

  1. Semi-supervised least squares support vector machine algorithm: application to offshore oil reservoir

    Science.gov (United States)

    Luo, Wei-Ping; Li, Hong-Qi; Shi, Ning

    2016-06-01

    At the early stages of deep-water oil exploration and development, fewer and further apart wells are drilled than in onshore oilfields. Supervised least squares support vector machine algorithms are used to predict the reservoir parameters but the prediction accuracy is low. We combined the least squares support vector machine (LSSVM) algorithm with semi-supervised learning and established a semi-supervised regression model, which we call the semi-supervised least squares support vector machine (SLSSVM) model. The iterative matrix inversion is also introduced to improve the training ability and training time of the model. We use the UCI data to test the generalization of a semi-supervised and a supervised LSSVM models. The test results suggest that the generalization performance of the LSSVM model greatly improves and with decreasing training samples the generalization performance is better. Moreover, for small-sample models, the SLSSVM method has higher precision than the semi-supervised K-nearest neighbor (SKNN) method. The new semisupervised LSSVM algorithm was used to predict the distribution of porosity and sandstone in the Jingzhou study area.

  2. On an inverse source problem for enhanced oil recovery by wave motion maximization in reservoirs

    KAUST Repository

    Karve, Pranav M.

    2014-12-28

    © 2014, Springer International Publishing Switzerland. We discuss an optimization methodology for focusing wave energy to subterranean formations using strong motion actuators placed on the ground surface. The motivation stems from the desire to increase the mobility of otherwise entrapped oil. The goal is to arrive at the spatial and temporal description of surface sources that are capable of maximizing mobility in the target reservoir. The focusing problem is posed as an inverse source problem. The underlying wave propagation problems are abstracted in two spatial dimensions, and the semi-infinite extent of the physical domain is negotiated by a buffer of perfectly-matched-layers (PMLs) placed at the domain’s truncation boundary. We discuss two possible numerical implementations: Their utility for deciding the tempo-spatial characteristics of optimal wave sources is shown via numerical experiments. Overall, the simulations demonstrate the inverse source method’s ability to simultaneously optimize load locations and time signals leading to the maximization of energy delivery to a target formation.

  3. Technical costs and economics of some typical oil and gas exploration and development projects

    Energy Technology Data Exchange (ETDEWEB)

    Kassler, P.

    1984-04-01

    Information from a number of actual projects, mainly located outside the Middle East region, analyzes the technical costs and economics of past, present, and future oil and gas exploration and development projects. The article identifies various cost components, and notes that these costs reflect the behavior of international and local markets for the resources concerned. Technical costs show a strong tendency to increase with time, the growth rate depending on the complexity of recovery of development and the need for enhanced recovery methods. Besides technical costs and taxes, potential investors should also consider energy values in evaluating a project. 1 figure, 1 table.

  4. Arrow Lakes Reservoir Fertilization Experiment; Years 4 and 5, Technical Report 2002-2003.

    Energy Technology Data Exchange (ETDEWEB)

    Schindler, E.

    2007-02-01

    This report presents the fourth and fifth year (2002 and 2003, respectively) of a five-year fertilization experiment on the Arrow Lakes Reservoir. The goal of the experiment was to increase kokanee populations impacted from hydroelectric development on the Arrow Lakes Reservoir. The impacts resulted in declining stocks of kokanee, a native land-locked sockeye salmon (Oncorhynchus nerka), a key species of the ecosystem. Arrow Lakes Reservoir, located in southeastern British Columbia, has undergone experimental fertilization since 1999. It is modeled after the successful Kootenay Lake fertilization experiment. The amount of fertilizer added in 2002 and 2003 was similar to the previous three years. Phosphorus loading from fertilizer was 52.8 metric tons and nitrogen loading from fertilizer was 268 metric tons. As in previous years, fertilizer additions occurred between the end of April and the beginning of September. Surface temperatures were generally warmer in 2003 than in 2002 in the Arrow Lakes Reservoir from May to September. Local tributary flows to Arrow Lakes Reservoir in 2002 and 2003 were generally less than average, however not as low as had occurred in 2001. Water chemistry parameters in select rivers and streams were similar to previous years results, except for dissolved inorganic nitrogen (DIN) concentrations which were significantly less in 2001, 2002 and 2003. The reduced snow pack in 2001 and 2003 would explain the lower concentrations of DIN. The natural load of DIN to the Arrow system ranged from 7200 tonnes in 1997 to 4500 tonnes in 2003; these results coincide with the decrease in DIN measurements from water samples taken in the reservoir during this period. Water chemistry parameters in the reservoir were similar to previous years of study except for a few exceptions. Seasonal averages of total phosphorus ranged from 2.11 to 7.42 {micro}g/L from 1997 through 2003 in the entire reservoir which were indicative of oligo-mesotrophic conditions

  5. Partitioning of Organic Compounds into Supercritical CO2 in Depleted Oil Reservoirs - A Review

    Science.gov (United States)

    Burant, A.; Lowry, G. V.; Karamalidis, A.

    2012-12-01

    Depleted oil reservoirs, with enhanced oil recovery, will be one of the first adopters of carbon capture and storage (CCS), which is a promising mitigation strategy for global climate change. The large scale implementation of CCS mandates better understanding of the risks associated with CO2 injection, especially in regards to potential leakage of the stored CO2. Organics, in the residual oil and dissolved in the brine, can partition into supercritical CO2 (sc-CO2) and move with that phase if it leaks. This review presents an overview of the thermodynamic models and trends in experimental partitioning data needed to understand what compounds may be expected to move with the sc-CO2. There are two main types of thermodynamic models used for predicting the solubility of organic compounds in sc-CO2, equations of state and quantitative structure activity relationships. Both can predict the partitioning behavior of one compound in sc-CO2, however only equations of state can predict solubility in multicomponent systems. In addition, equations of state have been developed to determine the effect of electrolytes on the partitioning behavior of organics dissolved in brines. There are three main trends in the partitioning behavior of organics in sc-CO2: Pure phase solubility follows trends in vapor pressure; compounds with higher volatility have higher solubility in sc-CO2. Second, the partitioning from water to sc-CO2 follows trends in Henry's constants, which follow the relative solubility of a compound in both the sc-CO2 and aqueous phases. Thirdly, the solubility of a compound can be enhanced by the presence of another; highly volatile compounds enhance the solubility of compounds with lower volatility. Finally, the review presents the gaps in experimental research that can be used to improve the modeling of the partitioning behavior of organics in sc-CO2, specifically in regards to co-solvency effects and the effects of electrolytes on the partitioning of dissolved

  6. Application of a New Wavelet Threshold Method in Unconventional Oil and Gas Reservoir Seismic Data Denoising

    Directory of Open Access Journals (Sweden)

    Guxi Wang

    2015-01-01

    Full Text Available Seismic data processing is an important aspect to improve the signal to noise ratio. The main work of this paper is to combine the characteristics of seismic data, using wavelet transform method, to eliminate and control such random noise, aiming to improve the signal to noise ratio and the technical methods used in large data systems, so that there can be better promotion and application. In recent years, prestack data denoising of all-digital three-dimensional seismic data is the key to data processing. Contrapose the characteristics of all-digital three-dimensional seismic data, and, on the basis of previous studies, a new threshold function is proposed. Comparing between conventional hard threshold and soft threshold, this function not only is easy to compute, but also has excellent mathematical properties and a clear physical meaning. The simulation results proved that this method can well remove the random noise. Using this threshold function in actual seismic processing of unconventional lithologic gas reservoir with low porosity, low permeability, low abundance, and strong heterogeneity, the results show that the denoising method can availably improve seismic processing effects and enhance the signal to noise ratio (SNR.

  7. Artificial Neural Network Model for Alkali-Surfactant-Polymer Flooding in Viscous Oil Reservoirs: Generation and Application

    Directory of Open Access Journals (Sweden)

    Si Le Van

    2016-12-01

    Full Text Available Chemical flooding has been widely utilized to recover a large portion of the oil remaining in light and viscous oil reservoirs after the primary and secondary production processes. As core-flood tests and reservoir simulations take time to accurately estimate the recovery performances as well as analyzing the feasibility of an injection project, it is necessary to find a powerful tool to quickly predict the results with a level of acceptable accuracy. An approach involving the use of an artificial neural network to generate a representative model for estimating the alkali-surfactant-polymer flooding performance and evaluating the economic feasibility of viscous oil reservoirs from simulation is proposed in this study. A typical chemical flooding project was referenced for this numerical study. A number of simulations have been made for training on the basis of a base case from the design of 13 parameters. After training, the network scheme generated from a ratio data set of 50%-20%-30% corresponding to the number of samples used for training-validation-testing was selected for estimation with the total coefficient of determination of 0.986 and a root mean square error of 1.63%. In terms of model application, the chemical concentration and injection strategy were optimized to maximize the net present value (NPV of the project at a specific oil price from the just created ANN model. To evaluate the feasibility of the project comprehensively in terms of market variations, a range of oil prices from 30 $/bbl to 60 $/bbl referenced from a real market situation was considered in conjunction with its probability following a statistical distribution on the NPV computation. Feasibility analysis of the optimal chemical injection scheme revealed a variation of profit from 0.42 $MM to 1.0 $MM, corresponding to the changes in oil price. In particular, at the highest possible oil prices, the project can earn approximately 0.61 $MM to 0.87 $MM for a quarter

  8. The intellectual information system for management of geological and technical arrangements during oil field exploitation

    Science.gov (United States)

    Markov, N. G.; Vasilyeva, E. E.; Evsyutkin, I. V.

    2017-01-01

    The intellectual information system for management of geological and technical arrangements during oil fields exploitation is developed. Service-oriented architecture of its software is a distinctive feature of the system. The results of the cluster analysis of real field data received by means of this system are shown.

  9. Silurian "Clinton" Sandstone Reservoir Characterization for Evaluation of CO2-EOR Potential in the East Canton Oil Field, Ohio

    Energy Technology Data Exchange (ETDEWEB)

    Riley, Ronald; Wicks, John; Perry, Christopher

    2009-12-30

    The purpose of this study was to evaluate the efficacy of using CO2-enhanced oil recovery (EOR) in the East Canton oil field (ECOF). Discovered in 1947, the ECOF in northeastern Ohio has produced approximately 95 million barrels (MMbbl) of oil from the Silurian “Clinton” sandstone. The original oil-in-place (OOIP) for this field was approximately 1.5 billion bbl and this study estimates by modeling known reservoir parameters, that between 76 and 279 MMbbl of additional oil could be produced through secondary recovery in this field, depending on the fluid and formation response to CO2 injection. A CO2 cyclic test (“Huff-n-Puff”) was conducted on a well in Stark County to test the injectivity in a “Clinton”-producing oil well in the ECOF and estimate the dispersion or potential breakthrough of the CO2 to surrounding wells. Eighty-one tons of CO2 (1.39 MMCF) were injected over a 20-hour period, after which the well was shut in for a 32-day “soak” period before production was resumed. Results demonstrated injection rates of 1.67 MMCF of gas per day, which was much higher than anticipated and no CO2 was detected in gas samples taken from eight immediately offsetting observation wells. All data collected during this test was analyzed, interpreted, and incorporated into the reservoir characterization study and used to develop the geologic model. The geologic model was used as input into a reservoir simulation performed by Fekete Associates, Inc., to estimate the behavior of reservoir fluids when large quantities of CO2 are injected into the “Clinton” sandstone. Results strongly suggest that the majority of the injected CO2 entered the matrix porosity of the reservoir pay zones, where it diffused into the oil. Evidence includes: (A) the volume of injected CO2 greatly exceeded the estimated capacity of the hydraulic fracture and natural fractures; (B) there was a gradual injection and pressure rate build-up during the test; (C) there was a subsequent

  10. Silurian "Clinton" Sandstone Reservoir Characterization for Evaluation of CO2-EOR Potential in the East Canton Oil Field, Ohio

    Energy Technology Data Exchange (ETDEWEB)

    Ronald Riley; John Wicks; Christopher Perry

    2009-12-30

    The purpose of this study was to evaluate the efficacy of using CO2-enhanced oil recovery (EOR) in the East Canton oil field (ECOF). Discovered in 1947, the ECOF in northeastern Ohio has produced approximately 95 million barrels (MMbbl) of oil from the Silurian 'Clinton' sandstone. The original oil-in-place (OOIP) for this field was approximately 1.5 billion bbl and this study estimates by modeling known reservoir parameters, that between 76 and 279 MMbbl of additional oil could be produced through secondary recovery in this field, depending on the fluid and formation response to CO2 injection. A CO2 cyclic test ('Huff-n-Puff') was conducted on a well in Stark County to test the injectivity in a 'Clinton'-producing oil well in the ECOF and estimate the dispersion or potential breakthrough of the CO2 to surrounding wells. Eighty-one tons of CO2 (1.39 MMCF) were injected over a 20-hour period, after which the well was shut in for a 32-day 'soak' period before production was resumed. Results demonstrated injection rates of 1.67 MMCF of gas per day, which was much higher than anticipated and no CO2 was detected in gas samples taken from eight immediately offsetting observation wells. All data collected during this test was analyzed, interpreted, and incorporated into the reservoir characterization study and used to develop the geologic model. The geologic model was used as input into a reservoir simulation performed by Fekete Associates, Inc., to estimate the behavior of reservoir fluids when large quantities of CO2 are injected into the 'Clinton' sandstone. Results strongly suggest that the majority of the injected CO2 entered the matrix porosity of the reservoir pay zones, where it diffused into the oil. Evidence includes: (A) the volume of injected CO2 greatly exceeded the estimated capacity of the hydraulic fracture and natural fractures; (B) there was a gradual injection and pressure rate build-up during the test

  11. Study of Reservoir Heterogencities and Structural Features Affecting Production in the Shallow Oil Zone, Eastern Elk Hills Area, California

    Energy Technology Data Exchange (ETDEWEB)

    Janice Gillespie

    2004-11-01

    Late Neogene (Plio-Pleistocene) shallow marine strata of the western Bakersfield Arch and Elk Hills produce hydrocarbons from several different reservoirs. This project focuses on the shallow marine deposits of the Gusher and Calitroleum reservoirs in the Lower Shallow Oil Zone (LSOZ). In the eastern part of the study area on the Bakersfield Arch at North and South Coles Levee field and in two wells in easternmost Elk Hills, the LSOZ reservoirs produce dry (predominantly methane) gas. In structurally higher locations in western Elk Hills, the LSOZ produces oil and associated gas. Gas analyses show that gas from the eastern LSOZ is bacterial and formed in place in the reservoirs, whereas gas associated with oil in the western part of the study area is thermogenic and migrated into the sands from deeper in the basin. Regional mapping shows that the gas-bearing LSOZ sands in the Coles Levee and easternmost Elk Hills area are sourced from the Sierra Nevada to the east whereas the oil-bearing sands in western Elk Hills appear to be sourced from the west. The eastern Elk Hills area occupied the basin depocenter, farthest from either source area. As a result, it collected mainly low-permeability offshore shale deposits. This sand-poor depocenter provides an effective barrier to the updip migration of gases from east to west. The role of small, listric normal faults as migration barriers is more ambiguous. Because our gas analyses show that the gas in the eastern LSOZ reservoirs is bacterial, it likely formed in-place near the reservoirs and did not have to migrate far. Therefore, the gas could have been generated after faulting and accumulated within the fault blocks as localized pools. However, bacterial gas is present in both the eastern AND western parts of Elk Hills in the Dry Gas Zone (DGZ) near the top of the stratigraphic section even though the measured fault displacement is greatest in this zone. Bacterial gas is not present in the west in the deeper LSOZ which

  12. Potential technical solutions to recover tight oil: Literature and simulation study of tight oil development

    OpenAIRE

    Zhang, Kai

    2014-01-01

    Over past decades, technology innovation drove unconventional resourcesbecome conventional. Incorporating the technologies applied in shale gasdevelopment, exploiting tight oil comes into stage recently. Advanced technology such as long horizontal wells combined with massivelyhydraulic fracturing was established as necessity to exploit tight oil reserve, however,primary recovery remains as low as 5.0-10.0% of original oil in place in tight oilreservoir with these technologies applied.[1] ...

  13. Low resistivity oil(gas)-bearing reservoir conductive model --Dual water clay matrix conductive model in the north area of Tarim Basin, Xinjiang, China

    Institute of Scientific and Technical Information of China (English)

    潘和平; 王家映; 樊政军; 马勇; 柳建华; 李明强

    2001-01-01

    Shaly sands reservoir is one of the most distributive types of the oil(gas)-bearing reservoirs discovered in China, and low resistivity oil(gas)-bearing reservoirs are mostly shaly sands reservoirs. Therefore, shaly sands reservoir conductive model is the key to evaluate low resistivity oil(gas)-bearing reservoirs using logging information. Some defects were found when we studied the clay distribution type conductive model, dual-water conductive model, conductive rock matrix model, etc. Some models could not distinguish the conductive path and nature of microporosity water and clay water and some models did not consider the clay distribution type and the mount of clay volume. So, we utilize the merits,overcome the defects of the above models, and put forward a new shaly sands conductive model-dual water clay matrix conductive model (DWCMCM) in which dual water is the free water and the microporosity water in shaly sands and the clay matrix(wet clay) is the clay grain containing water. DWCMCM is presented here, the advantages of which can tell the nature and conductive path from different water (microporosity water and freewater), in consid-eration of the clay distribution type and the mount of clay volume in shaly sands. So, the results of logging interpretation in the oil(gas)-bearing reservoirs in the north of Tarim Basin area, China with DWCMCM are better than those interpreted by the above models.

  14. Application of oil-water discrimination technology in fractured reservoirs using the differences between fast and slow shear-waves

    Science.gov (United States)

    Luo, Cong; Li, Xiangyang; Huang, Guangtan

    2017-08-01

    Oil-water discrimination is of great significance in the design and adjustment of development projects in oil fields. For fractured reservoirs, based on anisotropic S-wave splitting information, it becomes possible to effectively solve such problems which are difficult to deal with in traditional longitudinal wave exploration, due to the similar bulk modulus and density of these two fluids. In this paper, by analyzing the anisotropic character of the Chapman model (2009 Geophysics 74 97-103), the velocity and reflection coefficient differences between the fast and slow S-wave caused by fluid substitution have been verified. Then, through a wave field response analysis of the theoretical model, we found that water saturation causes a longer time delay, a larger time delay gradient and a lower amplitude difference between the fast and slow S-wave, while the oil case corresponds to a lower time delay, a lower gradient and a higher amplitude difference. Therefore, a new class attribute has been proposed regarding the amplitude energy of the fast and slow shear wave, used for oil-water distinction. This new attribute, as well as that of the time delay gradient, were both applied to the 3D3C seismic data of carbonate fractured reservoirs in the Luojia area of the Shengli oil field in China. The results show that the predictions of the energy attributes are more consistent with the well information than the time delay gradient attribute, hence demonstrating the great advantages and potential of this new attribute in oil-water recognition.

  15. Advanced Oil Recovery Technologies for Improved Recovery from Slope Basin Clastic Reservoirs, Nash Draw Brushy Canyon Pool, Eddy County, NM

    Energy Technology Data Exchange (ETDEWEB)

    Mark B. Murphy

    2005-09-30

    The Nash Draw Brushy Canyon Pool in Eddy County New Mexico was a cost-shared field demonstration project in the U.S. Department of Energy Class III Program. A major goal of the Class III Program was to stimulate the use of advanced technologies to increase ultimate recovery from slope-basin clastic reservoirs. Advanced characterization techniques were used at the Nash Draw Pool (NDP) project to develop reservoir management strategies for optimizing oil recovery from this Delaware reservoir. The objective of the project was to demonstrate that a development program, which was based on advanced reservoir management methods, could significantly improve oil recovery at the NDP. Initial goals were (1) to demonstrate that an advanced development drilling and pressure maintenance program can significantly improve oil recovery compared to existing technology applications and (2) to transfer these advanced methodologies to other oil and gas producers. Analysis, interpretation, and integration of recently acquired geological, geophysical, and engineering data revealed that the initial reservoir characterization was too simplistic to capture the critical features of this complex formation. Contrary to the initial characterization, a new reservoir description evolved that provided sufficient detail regarding the complexity of the Brushy Canyon interval at Nash Draw. This new reservoir description was used as a risk reduction tool to identify 'sweet spots' for a development drilling program as well as to evaluate pressure maintenance strategies. The reservoir characterization, geological modeling, 3-D seismic interpretation, and simulation studies have provided a detailed model of the Brushy Canyon zones. This model was used to predict the success of different reservoir management scenarios and to aid in determining the most favorable combination of targeted drilling, pressure maintenance, well stimulation, and well spacing to improve recovery from this reservoir. An

  16. Application of integrated reservoir management and reservoir characterization to optimize infill drilling. Annual technical progress report, June 13, 1996--June 12, 1997

    Energy Technology Data Exchange (ETDEWEB)

    Nevans, J.W.; Pregger, B. [Fina Oil and Chemical Co., Midland, TX (United States); Blasingame, T.; Doublet, L. [Texas A and M Univ., College Station, TX (United States); Freeman, G.; Callard, J. [Univ. of Tulsa, OK (United States); Moore, D. [Scientific Software, Inc. (United States); Davies, D.; Vessell, R. [David K. Davies and Associates (United States)

    1997-08-01

    Infill drilling of wells on a uniform spacing, without regard to reservoir performance and characterization, does not optimize reservoir development because it fails to account for the complex nature of reservoir heterogeneities present in many low permeability reservoirs, and carbonate reservoirs in particular. New and emerging technologies, such as geostatistical modeling, rigorous decline curve analysis, reservoir rock typing, and special core analysis can be used to develop a 3-D simulation model for prediction of infill locations. The purpose of this project is to demonstrate the application of advanced secondary recovery technologies to remedy producibility problems in typical shallow shelf carbonate reservoirs of the Permian Basin, Texas. Typical problems include poor sweep efficiency, poor balancing of injection and production rates, and completion techniques that are inadequate for optimal production and injection.

  17. Application of Integrated Reservoir Management and Reservoir Characterization to Optimize Infill Drillings. Annual technical progress report, June 13, 1996 to June 12, 1998

    Energy Technology Data Exchange (ETDEWEB)

    Nevans, Jerry W.; Blasingame, Tom; Doublet, Louis; Kelkar, Mohan; Freeman, George; Callard, Jeff; Moore, David; Davies, David; Vessell, Richard; Pregger, Brian; Dixon, Bill

    1999-04-27

    Infill drilling of wells on a uniform spacing, without regard to reservoir performance and characterization, does not optimize reservoir development because it fails to account for the complex nature of reservoir heterogeneities present in many low permeability reservoirs, and carbonate reservoirs in particular. New and emerging technologies, such as geostatistical modeling, rigorous decline curve analysis, reservoir rock typing, and special core analysis can be used to develop a 3-D simulation model for prediction of infill locations. Other technologies, such as inter-well injection tracers and magnetic flow conditioners, can also aid in the efficient evaluation and operation of both injection and producing wells. The purpose of this project was to demonstrate useful and cost effective methods of exploitation of the shallow shelf carbonate reservoirs of the Permian Basin located in West Texas.

  18. Analysis of nitrogen injection as alternative fluid to steam in heavy oil reservoir; Analise da injecao de nitrogenio como fluido alternativo ao vapor em reservatorio de oleo pesado

    Energy Technology Data Exchange (ETDEWEB)

    Rodrigues, Marcos Allyson Felipe; Galvao, Edney Rafael Viana Pinheiro; Barillas, Jennys Lourdes; Mata, Wilson da; Dutra Junior, Tarcilio Viana [Universidade Federal do Rio Grande do Norte (UFRN), RN (Brazil)

    2012-07-01

    Many of hydrocarbon reserves existing in the world are formed by heavy oils (deg API between 10 and 20). Moreover, several heavy oil fields are mature and, thus, offer great challenges for oil industry. Among the thermal methods used to recover these resources, steam flooding has been the main economically viable alternative. Latent heat carried by steam heats the reservoir, reducing oil viscosity and facilitating the production. This method has many variations and has been studied both theoretically and experimentally (in pilot projects and in full field applications). In order to increase oil recovery and reduce steam injection costs, the injection of alternative fluid has been used on three main ways: alternately, co-injected with steam and after steam injection interruption. The main objective of these injection systems is to reduce the amount of heat supplied to the reservoir, using cheaper fluids and maintaining the same oil production levels. In this paper, the use of N{sub 2} as an alternative fluid to the steam was investigated. The analyzed parameters were oil recoveries and net cumulative oil productions. The reservoir simulation model corresponds to an oil reservoir of 100 m x 100 m x 28 m size, on a Cartesian coordinates system (x, y and z directions). It is a semi synthetic model with some reservoir data similar to those found in Potiguar Basin, Brazil. All studied cases were done using the simulator STARS from CMG (Computer Modelling Group, version 2009.10). It was found that N{sub 2} injection after steam injection interruption achieved the highest net cumulative oil compared to others injection system. Moreover, it was observed that N2 as alternative fluid to steam did not present increase on oil recovery. (author)

  19. Post Waterflood CO2 Miscible Flood in Light Oil, Fluvial-Dominated Deltaic Reservoir (Pre-Work and Project Proposal - Appendix)

    Energy Technology Data Exchange (ETDEWEB)

    Bou-Mikael, Sami

    2002-02-05

    The main objective of the Port Neches Project was to determine the feasibility and producibility of CO2 miscible flooding techniques enhanced with horizontal drilling applied to a Fluvial Dominated Deltaic reservoir. The second was to disseminate the knowledge gained through established Technology Transfer mechanisms to support DOE's programmatic objectives of increasing domestic oil production and reducing abandonment of oil fields.

  20. Lateral seismic prediction of 3rd member sand reservoir in Shahejie formation in Southern Bohai oil field and the prediction result

    Energy Technology Data Exchange (ETDEWEB)

    Wengong, H.; Hongming, C.; Jinlian, L. (Geophysical Exploration Corporation, Hengli Oil Management Bureau, Niuzhuang, (Dongying City))

    1992-01-01

    Major reservoir in Southern Bohar Oil Field is the 3rd member turbidite sand in the Shahejie formation. The lateral seismic prediction involves the following interpretation jobs: comprehensive analysis of average velocity, synthetic seismogram and VSP data in the area; recognition of reservoir reflection characters in high-resolution seismic section which goes through well; lateral reservoir prediction using the reflection characters; plotting the structural map and isopach map of the reservoir; and offering favourable exploratory well site after reasonable reservoir evaluation that uses relevant materials, such as dynamic and static data of hydrocarbon. In this paper, using the technique, the authors have interpreted 17 sand bodies covering 38 km[sup 2] totally, and offered 25 exploration and development well sites. 8 wells have been completed, of which 7 wells produce industrial oil flow. The predicted horizons coincide with the drilled ones very well. Very good exploration effect has been received satisfactorily.

  1. An improved multilevel Monte Carlo method for estimating probability distribution functions in stochastic oil reservoir simulations

    Science.gov (United States)

    Lu, Dan; Zhang, Guannan; Webster, Clayton; Barbier, Charlotte

    2016-12-01

    In this work, we develop an improved multilevel Monte Carlo (MLMC) method for estimating cumulative distribution functions (CDFs) of a quantity of interest, coming from numerical approximation of large-scale stochastic subsurface simulations. Compared with Monte Carlo (MC) methods, that require a significantly large number of high-fidelity model executions to achieve a prescribed accuracy when computing statistical expectations, MLMC methods were originally proposed to significantly reduce the computational cost with the use of multifidelity approximations. The improved performance of the MLMC methods depends strongly on the decay of the variance of the integrand as the level increases. However, the main challenge in estimating CDFs is that the integrand is a discontinuous indicator function whose variance decays slowly. To address this difficult task, we approximate the integrand using a smoothing function that accelerates the decay of the variance. In addition, we design a novel a posteriori optimization strategy to calibrate the smoothing function, so as to balance the computational gain and the approximation error. The combined proposed techniques are integrated into a very general and practical algorithm that can be applied to a wide range of subsurface problems for high-dimensional uncertainty quantification, such as a fine-grid oil reservoir model considered in this effort. The numerical results reveal that with the use of the calibrated smoothing function, the improved MLMC technique significantly reduces the computational complexity compared to the standard MC approach. Finally, we discuss several factors that affect the performance of the MLMC method and provide guidance for effective and efficient usage in practice.

  2. Reservoir Modeling of Carbonate on Fika Field: The Challenge to Capture the Complexity of Rock and Oil Types

    Directory of Open Access Journals (Sweden)

    Erawati Fitriyani Adji

    2014-09-01

    Full Text Available DOI: 10.17014/ijog.v1i2.181The carbonate on Fika Field has a special character, because it grew above a basement high with the thickness and internal character variation. To develop the field, a proper geological model which can be used in reservoir simulation was needed. This model has to represent the complexity of the rock type and the variety of oil types among the clusters. Creating this model was challenging due to the heterogeneity of the Baturaja Formation (BRF: Early Miocene reef, carbonate platform, and breccia conglomerate grew up above the basement with a variety of thickness and quality distributions. The reservoir thickness varies between 23 - 600 ft and 3D seismic frequency ranges from 1 - 80 Hz with 25 Hz dominant frequency. Structurally, the Fika Field has a high basement slope, which has an impact on the flow unit layering slope. Based on production data, each area shows different characteristics and performance: some areas have high water cut and low cumulative production. Oil properties from several clusters also vary in wax content. The wax content can potentially build up a deposit inside tubing and flow-line, resulted in a possible disturbance to the operation. Five well cores were analyzed, including thin section and XRD. Seven check-shot data and 3D seismic Pre-Stack Time Migration (PSTM were available with limited seismic resolution. A seismic analysis was done after well seismic tie was completed. This analysis included paleogeography, depth structure map, and distribution of reservoir and basement. Core and log data generated facies carbonate distribution and rock typing, defining properties for log analysis and permeability prediction for each zone. An Sw prediction for each well was created by J-function analysis. This elaborates capillary pressure from core data, so it is very similar to the real conditions. Different stages of the initial model were done i.e. scale-up properties, data analysis, variogram modeling

  3. Assist in the recovery of bypassed oil from reservoirs in the Gulf of Mexico. Annual report, February 18, 1993--February 18, 1994

    Energy Technology Data Exchange (ETDEWEB)

    Schenewerk, P.A.

    1994-03-17

    The objective of this research is to assist the recovery of non-contacted oil from known reservoirs on the Outer Continental Shelf in the Gulf of Mexico. Thus far, research has consisted of data collection from Minerals Management Service (MMS), literature and operators; detailed studies of several screened reservoirs; modification of three public domain simulators; development of a predictive model; and design and construction of several laboratory experiments for studying attic oil recovery. The methodology for data collection from MMS, literature and operators is keyed on 208 sands containing 1,289 reservoirs, representing 60% of the original oil in place (OOIP) in the Gulf of Mexico. This data collection has been completed after several delays concerning confidentiality agreements between MMS, DOE, and LSU and its subcontractors. Secondary recovery by downdip gas injection in steeply dipping oil reservoirs has been widely used successfully since the 1950`s. Methane and nitrogen have been the primary gases used. Reservoirs which had been subjected to this type of recovery or had the potential to be subjected to this type of recovery were screened for detailed studies. Three reservoirs were identified which possessed the proper criteria and which had data available for detailed studies, the B-35-K and B-65-G reservoirs of South Marsh Island Block 73 Field and Reservoir 3 of Field 2, which was blind-coded by operator request. Detailed data sets for simulating these reservoirs were created. This included the review and analysis of the geology of the reservoirs to define reasonable grid configurations for use in the simulator and review of well histories, including production, gas injection, and pressure data.

  4. Phylogenetic diversity of microbial communities associated with the crude-oil, large-insoluble-particle and formation-water components of the reservoir fluid from a non-flooded high-temperature petroleum reservoir.

    Science.gov (United States)

    Kobayashi, Hajime; Endo, Keita; Sakata, Susumu; Mayumi, Daisuke; Kawaguchi, Hideo; Ikarashi, Masayuki; Miyagawa, Yoshihiro; Maeda, Haruo; Sato, Kozo

    2012-02-01

    The diversity of microbial communities associated with non-water-flooded high-temperature reservoir of the Niibori oilfield was characterized. Analysis of saturated hydrocarbons revealed that n-alkanes in crude oil from the reservoir were selectively depleted, suggesting that crude oil might be mildly biodegraded in the reservoir. To examine if any specific microorganism(s) preferentially attached to the crude oil or the other components (large insoluble particles and formation water) of the reservoir fluid, 16S rRNA gene clone libraries were constructed from each component of the reservoir fluid. The clones in the archaeal libraries (414 clones in total) represented 16 phylotypes, many of which were closely related to methanogens. The bacterial libraries (700 clones in total) were composed of 49 phylotypes belonging to one of 16 phylum-level groupings, with Firmicutes containing the greatest diversity of the phylotypes. In the crude-oil- and large-insoluble-particle-associated communities, a Methanosaeta-related phylotype dominated the archaeal sequences, whereas hydrogenotrophic methanogens occupied a major portion of sequences in the library of the formation-water-associated community. The crude-oil associated bacterial community showed the largest diversity, containing 35 phylotypes, 16 of which were not detected in the other bacterial communities. Thus, although the populations associated with the reservoir-fluid components largely shared common phylogenetic context, a specific fraction of microbial species preferentially attached to the crude oil and insoluble particles. Copyright © 2011 The Society for Biotechnology, Japan. Published by Elsevier B.V. All rights reserved.

  5. Technical-economic parameters of the new oil shale mining-chemical complex in Northeast Estonia

    Energy Technology Data Exchange (ETDEWEB)

    Kuzmiv, I. [Estonian Oil Shale Company ' Eesti Polevkivi, Johvi (Estonia); Fraiman, J. [Mining Engineer, Kohtla-Jarve (Estonia)

    2006-05-15

    The history of oil shale mining in Estonia has reached its century mark. Three oil shale branches have been formed and have been working on the basis of Estonian oil shale deposits: the mining industry (underground and surface extraction), the power industry (heat and electric energy generation), and the chemical industry (gas and synthetic oils). The authors attempted to summarize the experience of the activities of these branches and to make into a whole the results of their research developments in the past years, as well as to form a notion about perspectives of oil shale in Estonia. Variants of the mining-chemical oil shale complex production and trade patterns differed from used ones. Mining methods, thermal processing of oil shale, and solid, liquid, and gas waste recovery have been studied, analyzed, and worked out up to the present. Setting up a flexible trade structure within the framework of that complex is considered the main economic mechanism capable of balancing production costs of such a complex with its earnings, which could respond properly to any, even peak, fluctuations of the market for final products processed from oil shale. Data of the working 'Estonia' oil shale mine were used as the basis of the analysis and practical conclusions. Information on the mine being projected in the region of Ojamaa in the northeast of Estonia was taken as the data of the worthwhile supplier. Oil shale processing chemical complex is considered in two structural alternatives: in technological chain with the 'Estonia' mine (the first variant), and the projected mine of a new technical level (the second variant). (author)

  6. Heavy oil reservoir evaluation : performing an injection test using DST tools in the marine region of Mexico

    Energy Technology Data Exchange (ETDEWEB)

    Loaiza, J.; Ruiz, P. [Halliburton, Mexico City (Mexico); Barrera, D.; Gutierrez, F. [Pemex, Mexico City (Mexico)

    2010-07-01

    This paper described an injection test conducted to evaluate heavy oil reserves in an offshore area of Mexico. The drill-stem testing (DST) evaluation used a fluid injection technique in order to eliminate the need for artificial lift and coiled tubing. A pressure transient analysis method was used to determine the static pressure of the reservoir, effective hydrocarbon permeability, and formation damage. Boundary effects were also characterized. The total volume of the fluid injection was determined by analyzing various reservoir parameters. The timing of the shut-in procedure was determined by characterizing rock characteristics and fluids within the reservoir. The mobility and diffusivity relationships between the zones with the injection fluids and reservoir fluids were used to defined sweep fluids. A productivity analysis was used to predict various production scenarios. DST tools were then used to conduct a pressure-production assessment. Case histories were used to demonstrate the method. The studies showed that the method provides a cost-effective means of providing high quality data for productivity analyses. 4 refs., 2 tabs., 15 figs.

  7. A numerical/empirical technique for history matching and predicting cyclic steam performance in Canadian oil sands reservoirs

    Science.gov (United States)

    Leshchyshyn, Theodore Henry

    The oil sands of Alberta contain some one trillion barrels of bitumen-in-place, most contained in the McMurray, Wabiskaw, Clearwater, and Grand Rapids formations. Depth of burial is 0--550 m, 10% of which is surface mineable, the rest recoverable by in-situ technology-driven enhanced oil recovery schemes. To date, significant commercial recovery has been attributed to Cyclic Steam Stimulation (CSS) using vertical wellbores. Other techniques, such as Steam Assisted Gravity Drainage (SAGD) are proving superior to other recovery methods for increasing early oil production but at initial higher development and/or operating costs. Successful optimization of bitumen production rates from the entire reservoir is ultimately decided by the operator's understanding of the reservoir in its original state and/or the positive and negative changes which occur in oil sands and heavy oil deposits upon heat stimulation. Reservoir description is the single most important factor in attaining satisfactory history matches and forecasts for optimized production of the commercially-operated processes. Reservoir characterization which lacks understanding can destroy a project. For example, incorrect assumptions in the geological model for the Wolf Lake Project in northeast Alberta resulted in only about one-half of the predicted recovery by the original field process. It will be shown here why the presence of thin calcite streaks within oil sands can determine the success or failure of a commercial cyclic steam project. A vast amount of field data, mostly from the Primrose Heavy Oil Project (PHOP) near Cold Lake, Alberta, enabled the development a simple set of correlation curves for predicting bitumen production using CSS. A previously calibtrated thermal numerical simulation model was used in its simplist form, that is, a single layer, radial grid blocks, "fingering" or " dilation" adjusted permeability curves, and no simulated fracture, to generate the first cycle production

  8. Remaining oil distribution in Ng33 bottom water reservoir of Lin 2-6 fault-block in Huimin depression and potential tapping in horizontal well

    Institute of Scientific and Technical Information of China (English)

    HAN Zuo-zhen; YANG Ren-chao; FAN Ai-ping; CHEN Qing-chun; SHAO Yun-tang

    2009-01-01

    Oil reservoirs with secondary bottom water in Ng33 members (in Guantao formation, Paleogene system) of Lin2-6 fault block in Huimin depression (Bohai Bay Basin) have entered the late stage of ultra-high water-containing-exploitation. Oil exploita-tion from vertical wells is becoming more and more inefficient. The reservoir type, with water displacing oil and the remaining oil distribution are specifically studied in order to improve the efficiency of the recovery ratio. An integrated scheme for adjusting horizontal wells has been designed and the key technique of the scheme optimized. The study shows that: 1) the positive rhythm of fluvial depositional features is the internal cause of the flooding of oil reservoirs while water injection, injection-production patterns and accumulative petroleum production are the external causes; 2) oil-water driving patterns have transferred from edge water ad-vancing to bottom-water-coning; distribution of the remaining oil mainly concentrates in the upper rhythm and top of the middle rhythm in Ng33 members; 3) a great deal of remaining oil is enriched in high positions of faults, in axes of tiny structures, in stagna-tion areas among water-injection wells and oil-wells and in tectonic saddle areas with sparse wells. Compared with vertical wells, horizontal wells have advantages such as high recovery, high off-take potential, high critical output, large controlling areas and long time of bottom-water breakthrough.

  9. Feasibility Study and Potential Evaluation of Steam Flooding for Shallow Extra-Heavy Oil Reservoir%浅层超稠油油藏蒸汽驱可行性及潜力评价

    Institute of Scientific and Technical Information of China (English)

    孙永杰

    2014-01-01

    随着超稠油油藏蒸汽吞吐注汽周期的增加,地层压力大幅下降,开采效果变差。在分析油藏温度、压力和饱和度“三场”的基础上,论证油藏蒸汽吞吐转蒸汽驱进一步提高采收率的可行性。并通过油藏数值模拟方法确定该区块蒸汽驱最优注采参数,对最优参数预测结果进行经济评价。研究表明,蒸汽驱在技术和经济上都具备可行性,可以作为蒸汽吞吐后续接替技术,进一步提高稠油油藏采收率。%Reservoir pressure will drop greatly with the increment of steam inj ection cycle.Meanwhile production effect of huff and puff will become worse.Feasibility of steam flooding for shallow extra-heavy oil reservoir was researched through the analysis of reservoir temperature,pressure and oil saturation after several steam inj ection cycles.Production performance of steam flooding was predicted based on parameter optimization.Meanwhile economic evaluation was discussed.The results show that steam flooding for extra-heavy oil reservoir is technically and economically feasible.

  10. Advanced reservoir characterization in the Antelope Shale to establish the viability of CO2 enhanced oil recovery in California`s Monterey Formation siliceous shales. Annual report, February 7, 1997--February 6, 1998

    Energy Technology Data Exchange (ETDEWEB)

    Morea, M.F.

    1998-06-01

    The primary objective of this research is to conduct advanced reservoir characterization and modeling studies in the Antelope Shale reservoir. Characterization studies will be used to determine the technical feasibility of implementing a CO{sub 2} enhanced oil recovery project in the antelope Shale in Buena Vista Hills Field. The proposed pilot consists of four existing producers on 20 acre spacing with a new 10 acre infill well drilled as the pilot CO{sub 2} injector. Most of the reservoir characterization during Phase 1 of the project will be performed using data collected in the pilot pattern wells. During this period the following tasks have been completed: laboratory wettability; specific permeability; mercury porosimetry; acoustic anisotropy; rock mechanics analysis; core description; fracture analysis; digital image analysis; mineralogical analysis; hydraulic flow unit analysis; petrographic and confocal thin section analysis; oil geochemical fingerprinting; production logging; carbon/oxygen logging; complex lithologic log analysis; NMR T2 processing; dipole shear wave anisotropy logging; shear wave vertical seismic profile processing; structural mapping; and regional tectonic synthesis. Noteworthy technological successes for this reporting period include: (1) first (ever) high resolution, crosswell reflection images of SJV sediments; (2) first successful application of the TomoSeis acquisition system in siliceous shales; (3) first detailed reservoir characterization of SJV siliceous shales; (4) first mineral based saturation algorithm for SJV siliceous shales, and (5) first CO{sub 2} coreflood experiments for siliceous shale. Preliminary results from the CO{sub 2} coreflood experiments (2,500 psi) suggest that significant oil is being produced from the siliceous shale.

  11. 4D reservoir characterization using well log data for feasible CO2-enhanced oil recovery at Ankleshwar, Cambay Basin - A rock physics diagnostic and modeling approach

    Science.gov (United States)

    Ganguli, Shib Sankar; Vedanti, Nimisha; Dimri, V. P.

    2016-12-01

    In recent years, rock physics modeling has become an integral part of reservoir characterization as it provides the fundamental relationship between geophysical measurements and reservoir rock properties. These models are also used to quantify the effect of fluid saturation and stress on reservoir rocks by tracking the changes in elastic properties during production. Additionally, various rock physics models can be applied to obtain the information of rock properties away from existing drilled wells, which can play a crucial role in the feasibility assessment of CO2-enhanced oil recovery (EOR) operation at field. Thus, the objective of this study is to develop a rock-physics model of the Ankleshwar reservoir to predict the reservoir response under CO2-EOR. The Ankleshwar oil field is a mature field situated in Cambay Basin (Western India) that witnessed massive peripheral water flooding for around 40 years. Since the field was under water flooding for a long term, reasonable changes in reservoir elastic properties might have occurred. To identify potential reservoir zone with significant bypassed (or residual) oil saturation, we applied the diagnostic rock physics models to two available wells from the Ankleshwar oil field. The results clearly indicate transitions from clean sands to shaly sands at the base, and from sandy shale to pure shale at the top of the reservoir pay zone, suggesting a different seismic response at the top when compared to the base of the reservoir in both the wells. We also found that clay content and sorting affects the elastic properties of these sands, indicating different depositional scenario for the oil sands encountered in the Ankleshwar formation. Nevertheless, the rock physics template (RPT) analysis of the well data provides valuable information about the residual oil zone, a potential target for CO2-EOR. Further, a 4D reservoir characterization study has been conducted to assess the seismic detectability of CO2-EOR, and we

  12. Technical Note: Stability of a Levee Made of Bottom Sediments From a Dam Reservoir

    Directory of Open Access Journals (Sweden)

    Koś Karolina

    2015-02-01

    Full Text Available Stability analysis of a levee made of the bottom sediments from Czorsztyn-Niedzica Reservoir is presented in the paper. These sediments were classified as silty sands and, based on the authors' own research, their geotechnical parameters were beneficial, so the possibility of using this material for the hydraulic embankments was considered. Stability and filtration calculations were carried out for a levee that had the same top width - 3 m, slope inclinations 1:2 and different heights: 4, 6 and 8 m. Two methods were used: analytical and numerical. Calculations were carried out without and with a steady and unsteady seepage filtration. Based on the analysis carried out it was stated that the levee made of the bottom sediments is stable even at the height of 8.0 m, although because of the seepage on the downstream side it is recommended to use a drainage at the toe of the slope.

  13. Improved oil recovery in Mississippian carbonate reservoirs of Kansas near term Class 2. Annual report, September 18, 1994--March 15, 1997

    Energy Technology Data Exchange (ETDEWEB)

    Carr, T.R.; Green, D.W.; Willhite, G.P.

    1998-04-01

    This annual report describes progress during the second year of the project entitled {open_quotes}Improved Oil Recovery in Mississippian Carbonate Reservoirs in Kansas{close_quotes}. This project funded under the Department of Energy`s Class 2 program targets improving the reservoir performance of mature oil fields located in shallow shelf carbonate reservoirs. The focus of this project is development and demonstration of cost-effective reservoir description and management technologies to extend the economic life of mature reservoirs in Kansas and the mid-continent. As part of the project, several tools and techniques for reservoir description and management were developed, modified and demonstrated. These include: (1) a new approach to subsurface visualization using electric logs ({open_quotes}Pseudoseismic{open_quotes}); (2) a low-cost easy-to-use spreadsheet log analysis software (PfEFFER); and (3) an extension of the BOAST-3 computer program for full field reservoir simulation. The world-wide-web was used to provide rapid and flexible dissemination of the project results through the Internet. Included in this report is a summary of significant project results at the demonstration site (Schaben Field, Ness County, Kansas). These results include an outline of the reservoir description based on available and newly acquired data and reservoir simulation results. Detailed information is available on-line through the Internet. Based on the reservoir simulation, three infill wells will be drilled to validate the reservoir description and demonstrate the effectiveness of the proposed reservoir management strategies. The demonstration phase of the project has just begun and will be presented in the next annual report.

  14. Fracture density determination using a novel hybrid computational scheme: a case study on an Iranian Marun oil field reservoir

    Science.gov (United States)

    Nouri-Taleghani, Morteza; Mahmoudifar, Mehrzad; Shokrollahi, Amin; Tatar, Afshin; Karimi-Khaledi, Mina

    2015-04-01

    Most oil production all over the world is from carbonated reservoirs. Carbonate reservoirs are abundant in the Middle East, the Gulf of Mexico and in other major petroleum fields that are regarded as the main oil producers. Due to the nature of such reservoirs that are associated with low matrix permeability, the fracture is the key parameter that governs the fluid flow in porous media and consequently oil production. Conventional methods to determine the fracture density include utilizing core data and the image log family, which are both time consuming and costly processes. In addition, the cores are limited to certain intervals and there is no image log for the well drilled before the introduction of this tool. These limitations motivate petroleum engineers to try to find appropriate alternatives. Recently, intelligent systems on the basis of machine learning have been applied to various branches of science and engineering. The objective of this study is to develop a mathematical model to predict the fracture density using full set log data as inputs based on a combination of three intelligent systems namely, the radial basis function neural network, the multilayer perceptron neural network and the least square supported vector machine. The developed committee machine intelligent system (CMIS) is the weighted average of the individual results of each expert. Proper corresponding weights are determined using a genetic algorithm (GA). The other important feature of the proposed model is its generalization capability. The ability of this model to predict data that have not been introduced during the training stage is very good.

  15. Study on the connectivity of heavy oil reservoirs by ultraviolet spectrum technique in the western part of the QHD32-6 oilfield

    Institute of Scientific and Technical Information of China (English)

    XU Yaohui; CHEN Dan

    2008-01-01

    As a new method, the ultraviolet spectrum technique is applied to studying the connectivity of biodegradable heavy oil reservoirs. The similarity of crude oils can be judged according to the extinction coefficient (E)because aromatic hydrocarbons and non-hydrocarbons have conjugated bonds and obvious absorption in the ultraviolet range, and different materials have different characteristics and additives. The relationship diagram is made in terms of the extinction coefficients (E) of the samples by taking E as the Y-axis and wavelength as the X-axis. The connectivity of oil reservoirs is estimated according to the curve positions and characteristic fingerprints of the samples. The connectivity of part of the reservoirs in the western part of the QHD32-6 oilfieid was studied with this method. The results showed that the connectivity of samples from wells F7 and F8 in the Nm-2 oil reservoir zone is good, that of samples from wells F17 and F20 in the Nm-1 oil reservoir zone also is good, and that of samples from wells F17, F19, and F20 is poor.

  16. Integration of Seismic and Petrophysics to Characterize Reservoirs in “ALA” Oil Field, Niger Delta

    Directory of Open Access Journals (Sweden)

    P. A. Alao

    2013-01-01

    Full Text Available In the exploration and production business, by far the largest component of geophysical spending is driven by the need to characterize (potential reservoirs. The simple reason is that better reservoir characterization means higher success rates and fewer wells for reservoir exploitation. In this research work, seismic and well log data were integrated in characterizing the reservoirs on “ALA” field in Niger Delta. Three-dimensional seismic data was used to identify the faults and map the horizons. Petrophysical parameters and time-depth structure maps were obtained. Seismic attributes was also employed in characterizing the reservoirs. Seven hydrocarbon-bearing reservoirs with thickness ranging from 9.9 to 71.6 m were delineated. Structural maps of horizons in six wells containing hydrocarbon-bearing zones with tops and bottoms at range of −2,453 to −3,950 m were generated; this portrayed the trapping mechanism to be mainly fault-assisted anticlinal closures. The identified prospective zones have good porosity, permeability, and hydrocarbon saturation. The environments of deposition were identified from log shapes which indicate a transitional-to-deltaic depositional environment. In this research work, new prospects have been recommended for drilling and further research work. Geochemical and biostratigraphic studies should be done to better characterize the reservoirs and reliably interpret the depositional environments.

  17. Preliminary technical and legal evaluation of disposing of nonhazardous oil field waste into salt caverns

    Energy Technology Data Exchange (ETDEWEB)

    Veil, J.; Elcock, D.; Raivel, M.; Caudle, D.; Ayers, R.C. Jr.; Grunewald, B.

    1996-06-01

    Caverns can be readily formed in salt formations through solution mining. The caverns may be formed incidentally, as a result of salt recovery, or intentionally to create an underground chamber that can be used for storing hydrocarbon products or compressed air or disposing of wastes. The purpose of this report is to evaluate the feasibility, suitability, and legality of disposing of nonhazardous oil and gas exploration, development, and production wastes (hereafter referred to as oil field wastes, unless otherwise noted) in salt caverns. Chapter 2 provides background information on: types and locations of US subsurface salt deposits; basic solution mining techniques used to create caverns; and ways in which salt caverns are used. Later chapters provide discussion of: federal and state regulatory requirements concerning disposal of oil field waste, including which wastes are considered eligible for cavern disposal; waste streams that are considered to be oil field waste; and an evaluation of technical issues concerning the suitability of using salt caverns for disposing of oil field waste. Separate chapters present: types of oil field wastes suitable for cavern disposal; cavern design and location; disposal operations; and closure and remediation. This report does not suggest specific numerical limits for such factors or variables as distance to neighboring activities, depths for casings, pressure testing, or size and shape of cavern. The intent is to raise issues and general approaches that will contribute to the growing body of information on this subject.

  18. Determination of installation capacity in reservoir hydro-power plants considering technical, economical and reliability indices

    DEFF Research Database (Denmark)

    Hosseini, S.M.H.; Forouzbakhsh, Farshid; Fotouh-Firuzabad, Mahmood

    2008-01-01

    One of the most important issues in planning the ‘‘reservoir” type of hydro-power plants (HPP) is to determine the installation capacity of the HPPs and estimate its annual energy value. In this paper, a method is presented. A computer program has been developed to analyze energy calculation...... the technical, economic and reliability indices will determine the installation capacity of an HPP. By applying the above-mentioned algorithm to an existing HPP named ‘‘Bookan” (located in the westnorth of Iran); the capacity of 30 MW is obtained....

  19. Play Analysis and Digital Portfolio of Major Oil Reservoirs in the Permian Basin: Application and Transfer of Advanced Geological and Engineering Technologies for Incremental Production Opportunities

    Energy Technology Data Exchange (ETDEWEB)

    Shirley P. Dutton; Eugene M. Kim; Ronald F. Broadhead; Caroline L. Breton; William D. Raatz; Stephen C. Ruppel; Charles Kerans

    2004-01-13

    A play portfolio is being constructed for the Permian Basin in west Texas and southeast New Mexico, the largest onshore petroleum-producing basin in the United States. Approximately 1,300 reservoirs in the Permian Basin have been identified as having cumulative production greater than 1 MMbbl (1.59 x 10{sup 5} m{sup 3}) of oil through 2000. Of these significant-sized reservoirs, approximately 1,000 are in Texas and 300 in New Mexico. There are 32 geologic plays that have been defined for Permian Basin oil reservoirs, and each of the 1,300 major reservoirs was assigned to a play. The reservoirs were mapped and compiled in a Geographic Information System (GIS) by play. The final reservoir shapefile for each play contains the geographic location of each reservoir. Associated reservoir information within the linked data tables includes RRC reservoir number and district (Texas only), official field and reservoir name, year reservoir was discovered, depth to top of the reservoir, production in 2000, and cumulative production through 2000. Some tables also list subplays. Play boundaries were drawn for each play; the boundaries include areas where fields in that play occur but are smaller than 1 MMbbl (1.59 x 10{sup 5} m{sup 3}) of cumulative production. Oil production from the reservoirs in the Permian Basin having cumulative production of >1 MMbbl (1.59 x 10{sup 5} m{sup 3}) was 301.4 MMbbl (4.79 x 10{sup 7} m{sup 3}) in 2000. Cumulative Permian Basin production through 2000 was 28.9 Bbbl (4.59 x 10{sup 9} m{sup 3}). The top four plays in cumulative production are the Northwest Shelf San Andres Platform Carbonate play (3.97 Bbbl [6.31 x 10{sup 8} m{sup 3}]), the Leonard Restricted Platform Carbonate play (3.30 Bbbl [5.25 x 10{sup 8} m{sup 3}]), the Pennsylvanian and Lower Permian Horseshoe Atoll Carbonate play (2.70 Bbbl [4.29 x 10{sup 8} m{sup 3}]), and the San Andres Platform Carbonate play (2.15 Bbbl [3.42 x 10{sup 8} m{sup 3}]). Detailed studies of three reservoirs

  20. Reservoir Characterization of Upper Devonian Gordon Sandstone, Jacksonburg, Stringtown Oil Field, Northwestern West Virginia

    Energy Technology Data Exchange (ETDEWEB)

    Ameri, S.; Aminian, K.; Avary, K.L.; Bilgesu, H.I.; Hohn, M.E.; McDowell, R.R.; Patchen, D.L.

    2002-05-21

    The purpose of this work was to establish relationships among permeability, geophysical and other data by integrating geologic, geophysical and engineering data into an interdisciplinary quantification of reservoir heterogeneity as it relates to production.

  1. A Systems Approach to Bio-Oil Stabilization - Final Technical Report

    Energy Technology Data Exchange (ETDEWEB)

    Brown, Robert C; Meyer, Terrence; Fox, Rodney; Submramaniam, Shankar; Shanks, Brent; Smith, Ryan G

    2011-12-23

    The objective of this project is to develop practical, cost effective methods for stabilizing biomass-derived fast pyrolysis oil for at least six months of storage under ambient conditions. The U.S. Department of Energy has targeted three strategies for stabilizing bio-oils: (1) reducing the oxygen content of the organic compounds comprising pyrolysis oil; (2) removal of carboxylic acid groups such that the total acid number (TAN) of the pyrolysis oil is dramatically reduced; and (3) reducing the charcoal content, which contains alkali metals known to catalyze reactions that increase the viscosity of bio-oil. Alkali and alkaline earth metals (AAEM), are known to catalyze decomposition reactions of biomass carbohydrates to produce light oxygenates that destabilize the resulting bio-oil. Methods envisioned to prevent the AAEM from reaction with the biomass carbohydrates include washing the AAEM out of the biomass with water or dilute acid or infusing an acid catalyst to passivate the AAEM. Infusion of acids into the feedstock to convert all of the AAEM to salts which are stable at pyrolysis temperatures proved to be a much more economically feasible process. Our results from pyrolyzing acid infused biomass showed increases in the yield of anhydrosugars by greater than 300% while greatly reducing the yield of light oxygenates that are known to destabilize bio-oil. Particulate matter can interfere with combustion or catalytic processing of either syngas or bio-oil. It also is thought to catalyze the polymerization of bio-oil, which increases the viscosity of bio-oil over time. High temperature bag houses, ceramic candle filters, and moving bed granular filters have been variously suggested for syngas cleaning at elevated temperatures. High temperature filtration of bio-oil vapors has also been suggested by the National Renewable Energy Laboratory although there remain technical challenges to this approach. The fast pyrolysis of biomass yields three main organic

  2. Reservoir structures detection and hydrocarbons exploration using wavelet transform method in 2 oil fields in southwestern of Iran

    Science.gov (United States)

    Hassani, H.; Saadatinejad, M. R.

    2012-04-01

    Spectral decomposition provides better methods for quantifying and visualizing subtle seismic features and by decomposing the seismic signal into discrete frequency components, allows the geoscientist to analyze and map features. Through these methods, continuous wavelet transform (CWT) is an effective and widely-applied. It provides a different approach to time-frequency analysis and produces a time-scale map. The application of CWT is extensive and in this paper, we applied two major capacities of CWT in seismic investigations. It operated to detect reservoir structural characteristics and low-frequency shadows below gas reservoirs to develop a producing reservoir and discover a new petroleum reservoir in 2 oilfields in southwestern of Iran successfully. At the first and significant application in reservoir structure study, CWT enabled to providing clear images from kind of structural systems especially to identify hidden structural features such as extensional ruptures and faults for better drilling, injection and recovery operations and be able to increase production of oilfield. According to properties of tectonic events as fault and their effect (velocity diffraction) on seismic signals, it had been observed that CWT results show some discontinuities in location of ruptures and be able to display them more obvious than other spectral results, especially on horizon slices. Then, by picking and interpretation those, we obtain map, kind, strike and deep direction of faults easily. In petroleum exploration case, low-frequency shadows in CWT results appear due to energy attenuation of seismic signal in high frequencies by the presence of gas; this means there are no high frequencies under the gas reservoir. This phenomenon accounts as an indicator and attribute to explore reservoirs containing gas. As the frequency increases, these shadows decrease and finally disappear. The ranges of these shadows are usually between 8 to 20 Hz in gaz and 28 to 35 Hz in oil

  3. Investigation of oil-pool formation from the homogenization temperatures of fluid inclusions and biomarkers in reservoir rocks: a genetic model for the Deng-2 oil-pool in the Jiyuan Depression

    Energy Technology Data Exchange (ETDEWEB)

    Zhao Weiwei [Geochemical Institute of Chinese Academy, Guizhou (China); University of Petroleum, Shandong (China); Li Zhaoyang [University of Petroleum, Shandong (China); Jin Qiang; Wang Weifeng [Geochemical Institute of Chinese Academy, Guizhou (China)

    2002-11-01

    The Jiyuan Depression is a frontier area for oil and gas exploration in Henan Province, China. In recent years, oil was discovered in the Deng-2 well in the lower Tertiary, though the tectonics and petroleum geology of the Depression are very complex. A series of experiments on fluid inclusions in the oil-bearing sandstones from the Deng-2 well were made that included measurement of the homogenization temperatures of gas-liquid inclusions and GC-MS analysis of biomarkers either in the sandstone pores or in the fluid inclusions. The Deng-2 oil-reservoir was formed at about 78{sup o}C, corresponding to a burial depth of about 2200 m. The present burial depth is about 700 m because of erosion and fault-block uplift in Oligocene time. Although oil in the sandstone pores is now heavily biodegraded, the biomarkers in the inclusions show slight biodegradation representing a watering and biodegradation process that did not occur before formation of the Deng-2 oil- pool. Having investigated the structural evolution of the Deng-2 trap, it is concluded that the oil discovered in the Tertiary reservoir of Deng-2 well migrated from Mesozoic reservoirs through active faults around the Deng-2 trap. As the oil migrated from the Mesozoic to the Tertiary reservoir, the Deng-2 trap was uplifted close to the depth of active biodegradation (subsurface temperature lower than 80{sup o}C and to a burial depth shallower than 2250 m from the thermal gradient of 3.1{sup o}C/100 m) so that the oil in the inclusions shows a slight biodegradation. Because of the continuous uplift of the Deng-2 trap during the Tertiary and Quaternary, the reservoired oil has been more heavily biodegraded compared to that in the inclusions. (author)

  4. Model building for Chang-8 low permeability sandstone reservoir in the Yanchang formation of the Xifeng oil field

    Institute of Scientific and Technical Information of China (English)

    SONG Fan; HOU Jia-gen; SU Ni-na

    2009-01-01

    In order to build a model for the Chang-8 low permeability sandstone reservoir in the Yanchang formation of the Xifeng oil field, we studied sedlimentation and diagenesis of sandstone and analyzed major factors controlling this low permeability reser-voir. By doing so, we have made clear that the spatial distribution of reservoir attribute parameters is controlled by the spatial dis-tribution of various kinds of sandstone bodies. By taking advantage of many coring wells and high quality logging data, we used regression analysis for a single well with geological conditions as constraints, to build the interpretation model for logging data and to calculate attribute parameters for a single well, which ensured accuracy of the 1-D vertical model. On this basis, we built a litho-facies model to replace the sedimentary facies model. In addition, we also built a porosity model by using a sequential Gaussian simulation with the lithofacies model as the constraint. In the end, we built a permeability model by using Markov-Bayes simula-tion, with the porosity attribute as the covariate. The results show that the permeability model reflects very well the relative differ-ences between low permeability values, which is of great importance for locating high permeability zones and forecasting zones favorable for exploration and exploitation.

  5. Role of reservoir engineering in the assessment of undiscovered oil and gas resources in the National Petroleum Reserve, Alaska

    Science.gov (United States)

    Verma, M.K.; Bird, K.J.

    2005-01-01

    The geology and reservoir-engineering data were integrated in the 2002 U.S. Geological Survey assessment of the National Petroleum Reserve in Alaska (NPRA). VVhereas geology defined the analog pools and fields and provided the basic information on sizes and numbers of hypothesized petroleum accumulations, reservoir engineering helped develop necessary equations and correlations, which allowed the determination of reservoir parameters for better quantification of in-place petroleum volumes and recoverable reserves. Seismic- and sequence-stratigraphic study of the NPRA resulted in identification of 24 plays. Depth ranges in these 24 plays, however, were typically greater than depth ranges of analog plays for which there were available data, necessitating the need for establishing correlations. The basic parameters required were pressure, temperature, oil and gas formation volume factors, liquid/gas ratios for the associated and nonassociated gas, and recovery factors. Finally, the re sults of U.S. Geological Survey deposit simulation were used in carrying out an economic evaluation, which has been separately published. Copyright ?? 2005. The American Association of Petroleum Geologists. All rights reserved.

  6. 76 FR 3142 - Release of Exposure Draft Technical Bulletins; Accounting for Oil and Gas Resources and Federal...

    Science.gov (United States)

    2011-01-19

    ... From the Federal Register Online via the Government Publishing Office FEDERAL ACCOUNTING STANDARDS ADVISORY BOARD Release of Exposure Draft Technical Bulletins; Accounting for Oil and Gas Resources and Federal Natural Resources Other Than Oil and Gas AGENCY: Federal Accounting Standards Advisory...

  7. Increased oil production and reserves utilizing secondary/tertiary recovery techniques on small reservoirs in the Paradox basin, Utah. Annual report, February 9, 1996--February 8, 1997

    Energy Technology Data Exchange (ETDEWEB)

    Chidsey, T.C. Jr.

    1997-08-01

    The Paradox basin of Utah, Colorado, and Arizona contains nearly 100 small oil fields producing from carbonate buildups or mounds within the Pennsylvanian (Desmoinesian) Paradox Formation. These fields typically have one to four wells with primary production ranging from 700,000 to 2,000,000 barrels of oil per field at a 15 to 20% recovery rate. At least 200 million barrels of oil is at risk of being unrecovered in these small fields because of inefficient recovery practices and undrained heterogeneous reservoirs. Five fields (Anasazi, Mule, Blue Hogan, Heron North, and Runway) within the Navajo Nation of southeastern Utah are being evaluated for waterflood or carbon-dioxide-miscible flood projects based upon geological characterization and reservoir modeling. The results can be applied to other fields in the Paradox basin and the Rocky Mountain region, the Michigan and Illinois basins, and the Midcontinent. The Anasazi field was selected for the initial geostatistical modeling and reservoir simulation. A compositional simulation approach is being used to model primary depletion, waterflood, and CO{sub 2}-flood processes. During this second year of the project, team members performed the following reservoir-engineering analysis of Anasazi field: (1) relative permeability measurements of the supra-mound and mound-core intervals, (2) completion of geologic model development of the Anasazi reservoir units for use in reservoir simulation studies including completion of a series of one-dimensional, carbon dioxide-displacement simulations to analyze the carbon dioxide-displacement mechanism that could operate in the Paradox basin system of reservoirs, and (3) completion of the first phase of the full-field, three-dimensional Anasazi reservoir simulation model, and the start of the history matching and reservoir performance prediction phase of the simulation study.

  8. Potential for technically recoverable unconventional gas and oil resources in the Polish-Ukrainian Foredeep, Poland, 2012

    Science.gov (United States)

    Gautier, Donald L.; Pitman, Janet K.; Charpentier, Ronald R.; Cook, Troy; Klett, Timothy R.; Schenk, Christopher J.

    2012-01-01

    Using a performance-based geological assessment methodology, the U.S. Geological Survey estimated mean volumes of 1,345 billion cubic feet of potentially technically recoverable gas and 168 million barrels of technically recoverable oil and natural gas liquids in Ordovician and Silurian age shales in the Polish- Ukrainian Foredeep basin of Poland.

  9. WETTABILITY AND PREDICTION OF OIL RECOVERY FROM RESERVOIRS DEVELOPED WITH MODERN DRILLING AND COMPLETION FLUIDS

    Energy Technology Data Exchange (ETDEWEB)

    Jill S. Buckley; Norman R. Morrow

    2004-11-01

    Contamination of crude oils by surface-active agents from drilling fluids or other oil-field chemicals is more difficult to detect and quantify than bulk contamination with, for example, base fluids from oil-based muds. Bulk contamination can be detected by gas chromatography or other common analytical techniques, but surface-active contaminants can be influential at much lower concentrations that are more difficult to detect analytically, especially in the context of a mixture as complex as a crude oil. In this report we present a baseline study of interfacial tensions of 39 well-characterized crude oil samples with aqueous phases that vary in pH and ionic composition. This extensive study will provide the basis for assessing the effects of surface-active contaminant on interfacial tension and other surface properties of crude oil/brine/rock ensembles.

  10. The use of secondary and tertiary methods of working oil reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Szabo, J.; Karlos, A.

    1985-01-01

    Oil policy in recent years has led to the efficient use of resources and to a reduction in oil demand by the import nations. The high cost of oil has led to a situation where oil recovery with a higher specific cost has also become cost effective. The broad use of secondary methods of recovery from operating mines has caused a temporary drop in total expenditures on exploration and prospecting. Tertiary development methods aimed at increasing oil recovery have already passed their experimental phase. The broad utilization of these methods will follow the need for more efficient utilization of expensive reserves of natural resources. The current utilization of methods for increasing oil recovery are analyzed together with methods for use in the near future.

  11. Electrofacies vs. lithofacies sandstone reservoir characterization Campanian sequence, Arshad gas/oil field, Central Sirt Basin, Libya

    Science.gov (United States)

    Burki, Milad; Darwish, Mohamed

    2017-06-01

    The present study focuses on the vertically stacked sandstones of the Arshad Sandstone in Arshad gas/oil field, Central Sirt Basin, Libya, and is based on the conventional cores analysis and wireline log interpretation. Six lithofacies types (F1 to F6) were identified based on the lithology, sedimentary structures and biogenic features, and are supported by wireline log calibration. From which four types (F1-F4) represent the main Campanian sandstone reservoirs in the Arshad gas/oil field. Lithofacies F5 is the basal conglomerates at the lower part of the Arshad sandstones. The Paleozoic Gargaf Formation is represented by lithofacies F6 which is the source provenance for the above lithofacies types. Arshad sediments are interpreted to be deposited in shallow marginal and nearshore marine environment influenced by waves and storms representing interactive shelf to fluvio-marine conditions. The main seal rocks are the Campanian Sirte shale deposited in a major flooding events during sea level rise. It is contended that the syn-depositional tectonics controlled the distribution of the reservoir facies in time and space. In addition, the post-depositional changes controlled the reservoir quality and performance. Petrophysical interpretation from the porosity log values were confirmed by the conventional core measurements of the different sandstone lithofacies types. Porosity ranges from 5 to 20% and permeability is between 0 and 20 mD. Petrophysical cut-off summary of the lower part of the clastic dominated sequence (i. e. Arshad Sandstone) calculated from six wells includes net pay sand ranging from 19.5‧ to 202.05‧, average porosity from 7.7 to 15% and water saturation from 19 to 58%.

  12. CO2 for enhanced oil recovery and secure storage of CO2 in reservoirs

    OpenAIRE

    Li, Yunhang

    2015-01-01

    CO2-EOR(Enhanced Oil Recovery) is an effective and useful technology that can not only increase the oil production to meet the increasing need for energy around the world, but also mitigate the negtive influence of global green house effect. Different categories of oil recovery methods including primary recovery, secondary recovery, and EOR technologies are introduced at first. Then the history, global distribution, screening criteria, mechanisms, advantages and disadvantages of CO2-EOR are d...

  13. PLAY ANALYSIS AND DIGITAL PORTFOLIO OF MAJOR OIL RESERVOIRS IN THE PERMIAN BASIN: APPLICATION AND TRANSFER OF ADVANCED GEOLOGICAL AND ENGINEERING TECHNOLOGIES FOR INCREMENTAL PRODUCTION OPPORTUNITIES

    Energy Technology Data Exchange (ETDEWEB)

    Shirley P. Dutton; Eugene M. Kim; Ronald F. Broadhead; William Raatz; Cari Breton; Stephen C. Ruppel; Charles Kerans; Mark H. Holtz

    2003-04-01

    A play portfolio is being constructed for the Permian Basin in west Texas and southeast New Mexico, the largest petroleum-producing basin in the US. Approximately 1300 reservoirs in the Permian Basin have been identified as having cumulative production greater than 1 MMbbl of oil through 2000. Of these major reservoirs, approximately 1,000 are in Texas and 300 in New Mexico. On a preliminary basis, 32 geologic plays have been defined for Permian Basin oil reservoirs and assignment of each of the 1300 major reservoirs to a play has begun. The reservoirs are being mapped and compiled in a Geographic Information System (GIS) by play. Detailed studies of three reservoirs are in progress: Kelly-Snyder (SACROC unit) in the Pennsylvanian and Lower Permian Horseshoe Atoll Carbonate play, Fullerton in the Leonardian Restricted Platform Carbonate play, and Barnhart (Ellenburger) in the Ellenburger Selectively Dolomitized Ramp Carbonate play. For each of these detailed reservoir studies, technologies for further, economically viable exploitation are being investigated.

  14. Oil industry first field trial of inter-well reservoir nanoagent tracers

    Science.gov (United States)

    Kanj, Mazen Y.; Kosynkin, Dmitry V.

    2015-05-01

    This short manuscript highlights the industry's first proven reservoir nanoagents' design and demonstrates a successful multi-well field trial using these agents. Our fundamental nanoparticles tracer template, A-Dots or Arab-D Dots, is intentionally geared towards the harsh but prolific Arab-D carbonate reservoir environment of 100+°C temperature, 150,000+ppm salinity, and an abundant presence of divalent ions in the connate water. Preliminary analyses confirmed nanoparticles' breakthrough at a producer nearly 500m from the injector at the reservoir level; thus, proving the tracer nanoparticles' mobility and transport capability. This is considered industry-first and a breakthrough achievement complementing earlier accomplishments in regard to the nanoagents' reservoir stability with the first successful single well test and ease of scale up with the synthesis of one metric ton of this material. The importance of this accomplishment is not in how sophisticated is the sensing functionalities of this design but rather in its stability, mobility, scalability, and field application potentials. This renders the concept of having active, reactive, and even communicative, in-situ reservoir nanoagents for underground sensing and intervention a well anticipated near-future reality.

  15. Investigation on behavior of bacteria in reservoir for microbial enhanced oil recovery; Biseibutsuho (MEOR) no tameno yusonai saikin katsudo ni kansuru chosa

    Energy Technology Data Exchange (ETDEWEB)

    Fujiwara, K.; Tanaka, S.; Otsuka, M.; Nakaya, K. [Kansai Research Institute, Kyoto (Japan). Lifescience Research Center; Maezumi, S.; Yazawa, N. [Japan National Oil Corp., Tokyo (Japan). Technology Research Center; Hong, C.; Chida, T.; Enomoto, H. [Tohoku University, Miyagi (Japan). Graduate School of Engineering

    2000-07-01

    Behavior of bacteria activated in reservoir though molasses-injection-tests, was investigated using the restriction fragment length polymorphism analysis with the polymerase chain reaction (PCR-RFLP) method, for elucidating potential bacteria to suppress in situ growth of microbes to be injected into the reservoir in the microbial enhanced oil recovery (MEOR) process. As a result, some bacteria belonging to Enterobacteriaceae species or their close relative species were grown predominantly in the reservoir, among bacteria inhibiting in the ground-water. The foregoing indicates that behavior of these bacteria in reservoir must be taken into consideration when giving a full account of behavior of microbes to be injected into the reservoir to put the MEOR process into operation. Potential proliferation using molasses to activate those bacteria was also estimated on the laboratory tests, to clarify the growth of microbes to be injected into the reservoir to operate the MEOR process. In consequence, it became clear that these bacteria have a potential growth exceeding 10{sup 8} CFU/ml, utilizing molasses. These facts indicated that microbes to be injected into the reservoir at the MEOR field tests are necessary to grow more excellently than bacteria inhabiting in the ground-water. In addition, as flow, the injection fluid is influenced by reservoir heterogeneity caused by injection of molasses, it was inferred that microbes to be injected into the reservoir at the MEOR field process are also necessary to grow more remarkably than bacteria inhabiting in the reservoir brine at high permeability zones and bacteria inhabiting in the reservoir rock. Furthermore, the results of the functional testing for MEOR conducted in the presence of bacteria activated through molasses-injection-tests indicated the importance of effective use of microbes to be injected, taking into account the characteristics of the reservoir and function for MEOR of those microbes. (author)

  16. PLAY ANALYSIS AND DIGITAL PORTFOLIO OF MAJOR OIL RESERVOIRS IN THE PERMIAN BASIN: APPLICATION AND TRANSFER OF ADVANCED GEOLOGICAL AND ENGINEERING TECHNOLOGIES FOR INCREMENTAL PRODUCTION OPPORTUNITIES

    Energy Technology Data Exchange (ETDEWEB)

    Shirley P. Dutton; Eugene M. Kim; Ronald F. Broadhead; Caroline L. Breton; William D. Raatz; Stephen C. Ruppel; Charles Kerans

    2004-05-01

    The Permian Basin of west Texas and southeast New Mexico has produced >30 Bbbl (4.77 x 10{sup 9} m{sup 3}) of oil through 2000, most of it from 1,339 reservoirs having individual cumulative production >1 MMbbl (1.59 x 10{sup 5} m{sup 3}). These significant-sized reservoirs are the focus of this report. Thirty-two Permian Basin oil plays were defined, and each of the 1,339 significant-sized reservoirs was assigned to a play. The reservoirs were mapped and compiled in a Geographic Information System (GIS) by play. Associated reservoir information within linked data tables includes Railroad Commission of Texas reservoir number and district (Texas only), official field and reservoir name, year reservoir was discovered, depth to top of the reservoir, production in 2000, and cumulative production through 2000. Some tables also list subplays. Play boundaries were drawn for each play; the boundaries include areas where fields in that play occur but are <1 MMbbl (1.59 x 10{sup 5} m{sup 3}) of cumulative production. This report contains a summary description of each play, including key reservoir characteristics and successful reservoir-management practices that have been used in the play. The CD accompanying the report contains a pdf version of the report, the GIS project, pdf maps of all plays, and digital data files. Oil production from the reservoirs in the Permian Basin having cumulative production >1 MMbbl (1.59 x 10{sup 5} m{sup 3}) was 301.4 MMbbl (4.79 x 10{sup 7} m{sup 3}) in 2000. Cumulative Permian Basin production through 2000 from these significant-sized reservoirs was 28.9 Bbbl (4.59 x 10{sup 9} m{sup 3}). The top four plays in cumulative production are the Northwest Shelf San Andres Platform Carbonate play (3.97 Bbbl [6.31 x 10{sup 8} m{sup 3}]), the Leonard Restricted Platform Carbonate play (3.30 Bbbl 5.25 x 10{sup 8} m{sup 3}), the Pennsylvanian and Lower Permian Horseshoe Atoll Carbonate play (2.70 Bbbl [4.29 x 10{sup 8} m{sup 3}]), and the San Andres

  17. Reviving Abandoned Reservoirs with High-Pressure Air Injection: Application in a Fractured and Karsted Dolomite Reservoir

    Energy Technology Data Exchange (ETDEWEB)

    Robert Loucks; Stephen C. Ruppel; Dembla Dhiraj; Julia Gale; Jon Holder; Jeff Kane; Jon Olson; John A. Jackson; Katherine G. Jackson

    2006-09-30

    Despite declining production rates, existing reservoirs in the United States contain vast volumes of remaining oil that is not being effectively recovered. This oil resource constitutes a huge target for the development and application of modern, cost-effective technologies for producing oil. Chief among the barriers to the recovery of this oil are the high costs of designing and implementing conventional advanced recovery technologies in these mature, in many cases pressure-depleted, reservoirs. An additional, increasingly significant barrier is the lack of vital technical expertise necessary for the application of these technologies. This lack of expertise is especially notable among the small operators and independents that operate many of these mature, yet oil-rich, reservoirs. We addressed these barriers to more effective oil recovery by developing, testing, applying, and documenting an innovative technology that can be used by even the smallest operator to significantly increase the flow of oil from mature U.S. reservoirs. The Bureau of Economic Geology and Goldrus Producing Company assembled a multidisciplinary team of geoscientists and engineers to evaluate the applicability of high-pressure air injection (HPAI) in revitalizing a nearly abandoned carbonate reservoir in the Permian Basin of West Texas. The Permian Basin, the largest oil-bearing basin in North America, contains more than 70 billion barrels of remaining oil in place and is an ideal venue to validate this technology. We have demonstrated the potential of HPAI for oil-recovery improvement in preliminary laboratory tests and a reservoir pilot project. To more completely test the technology, this project emphasized detailed characterization of reservoir properties, which were integrated to access the effectiveness and economics of HPAI. The characterization phase of the project utilized geoscientists and petroleum engineers from the Bureau of Economic Geology and the Department of Petroleum

  18. An Integrated Approach to Characterizing Bypassed Oil in Heterogeneous and Fractured Reservoirs Using Partitioning Tracers

    Energy Technology Data Exchange (ETDEWEB)

    Akhil Datta-Gupta

    2005-08-01

    We explore the use of efficient streamline-based simulation approaches for modeling and analysis partitioning interwell tracer tests in heterogeneous and fractured hydrocarbon reservoirs. We compare the streamline-based history matching techniques developed during the first two years of the project with the industry standard assisted history matching. We enhance the widely used assisted history matching in two important aspects that can significantly improve its efficiency and effectiveness. First, we utilize streamline-derived analytic sensitivities to relate the changes in reservoir properties to the production response. These sensitivities can be computed analytically and contain much more information than that used in the assisted history matching. Second, we utilize the sensitivities in an optimization procedure to determine the spatial distribution and magnitude of the changes in reservoir parameters needed to improve the history-match. By intervening at each iteration during the optimization process, we can retain control over the history matching process as in assisted history matching. This allows us to accept, reject, or modify changes during the automatic history matching process. We demonstrate the power of our method using two field examples with model sizes ranging from 10{sup 5} to 10{sup 6} grid blocks and with over one hundred wells. We have also extended the streamline-based production data integration technique to naturally fractured reservoirs using the dual porosity approach. The principal features of our method are the extension of streamline-derived analytic sensitivities to account for matrix-fracture interactions and the use of our previously proposed generalized travel time inversion for history matching. Our proposed workflow has been demonstrated by using both a dual porosity streamline simulator and a commercial finite difference simulator. Our approach is computationally efficient and well suited for large scale field applications in

  19. Modification of reservoir chemical and physical factors in steamfloods to increase heavy oil recovery. [Quarterly report], January 1--March 31, 1996

    Energy Technology Data Exchange (ETDEWEB)

    Yortsos, Y.C.

    1996-07-01

    Thermal methods, and particularly steam injection, are currently recognized as the most promising for the efficient recovery of heavy oil. Despite significant progress, however, important technical issues remain open. Specifically, still inadequate is our knowledge of the complex interaction between porous media and the various fluids of thermal recovery (steam, water, heavy oil, gases, and chemicals). While, the interplay of heat transfer and fluid flow with pore- and macro-scale heterogeneity is largely unexplored. The objectives of this contract are to continue previous work and to carry out new fundamental studies in the following areas of interest to thermal recovery: displacement and flow properties of fluids involving phase change in porous media; flow properties of mobility control fluids (such as foam); and the effect of reservoir heterogeneity on thermal recovery. During this quarter, we focused on the development of relative permeabilities during steam displacement. Two particular directions were pursued: One involves the derivation of relative permeabilities based on a recently completed work on the pore-level mechanics of steam displacement. Progress has been made to relate the relative permeabilities to effects such as heat transfer and condensation, which are specific to steam injection problems. The second direction involves the development of three-phase relative permeabilities using invasion percolation concepts. We have developed models that predict the specific dependence of the permeabilities of three immiscible phases (e.g. awe, water and gas) on saturations and the saturation history. Both works are still in progress. In addition, work continues in the analysis of the stability of phase change fronts in porous media using a macroscopic approach.

  20. Effect of matrix wettability CO2 assisted gas-oil garvity drainage in naturally fractured reservoirs

    NARCIS (Netherlands)

    Amerighasrodashti, A.; Farajzadeh, R.; Shojai Kaveh, N.; Suicmez, S.; Wolf, K.H.A.A.; Bruining, J.

    2015-01-01

    The wettability behavior of the matrix block is one of the major factors controlling the effectiveness of the employed EOR methods in NFRs. Water injection in NFRs with mixed-wet or effectively oil-wet matrix blocks usually results in low oil recoveries. In this case, gas injection is considered to

  1. Prediction of Interfacial Tensions of Reservoir Crude Oil and Gas Condensate Systems

    DEFF Research Database (Denmark)

    Zuo, You-Xiang; Stenby, Erling Halfdan

    1998-01-01

    In this work, the linear gradient theory (LGT) model, the simplified linear gradient theory (SLGT) model, the corresponding-states (CS) correlation, and the parachor method developed by the authors were extended to calculate interfacial tensions (IFT's) of crude oil and gas condensate systems...... model and the parachor model. For gas condensate systems, the predictions by use of the SLGT model are in good agreement with the measured IFT data. In the near-critical region, a correlation was proposed for estimations of IFT’s for CO2/oil systems, and satisfactory correlated results were obtained....... the CS correlation were in good agreement with the measured IFT data for several crude oil and CO2/oil systems. The SLGT model and the parachor model perform better than the LGT model and the CS correlation. For N 2 volatile oil systems, the performance of the LGT model is better than that of the SLGT...

  2. A dynamic model for geological sequestration of CO{sub 2} in mature oil reservoirs.; Modelo dinamico de sequestro geologico de CO{sub 2} em reservatorios de petroleo

    Energy Technology Data Exchange (ETDEWEB)

    Ravagnani, Ana Teresa F. da S. Gaspar [Universidade Estadual de Campinas (DEP/FEM/UNICAMP), SP (Brazil). Fac. de Engenharia Mecanica. Dept. de Engenharia de Petroleo], E-mail: atgaspar@dep.fem.unicamp.br; Suslick, Saul B. [Universidade Estadual de Campinas (CEPETRO/UNICAMP), Campinas, SP (Brazil). Inst. de Geociencias. Dept. de Geologia e Recursos Naturais], E-mail: suslick@ige.unicamp.br

    2008-03-15

    The geologic formations, which can be utilized for CO{sub 2} storage include: deep saline aquifers, oil and gas reservoirs and coal bed reservoirs. The fluids in the subsurface fill the porous rock as occurs with water, oil, natural gas, carbon dioxide, among others. In these formations, carbon dioxide is stored by different trapping mechanisms; the exact mechanism depends on the type of rock. The main mechanisms are: hydrodynamic trapping, solubility trapping and mineral trapping. Among the geologic formations, oil reservoirs are strong candidates to be used in the reduction of carbon dioxide in the atmosphere due to the technological knowledge acquired by the oil industry. These reservoirs are proved geologic traps with capacity to retain fluids and gases for long term. The CO{sub 2} injection technique for enhanced recovery is a common practice in the oil industry and it can be used in carbon sequestration. The storage of some part of the injected gas in reservoirs submitted to Enhanced Oil Recovery operations is a direct consequence of CO{sub 2} utilization since the gas produced with the oil be captured and re-injected in the reservoir. This work presents a global dynamic model of the carbon sequestration process in enhanced oil recovery operations in a typical mature oil reservoir aiming to quantify the real contribution of the stored gas. (author)

  3. Analysis of real-time reservoir monitoring : reservoirs, strategies, & modeling.

    Energy Technology Data Exchange (ETDEWEB)

    Mani, Seethambal S.; van Bloemen Waanders, Bart Gustaaf; Cooper, Scott Patrick; Jakaboski, Blake Elaine; Normann, Randy Allen; Jennings, Jim (University of Texas at Austin, Austin, TX); Gilbert, Bob (University of Texas at Austin, Austin, TX); Lake, Larry W. (University of Texas at Austin, Austin, TX); Weiss, Chester Joseph; Lorenz, John Clay; Elbring, Gregory Jay; Wheeler, Mary Fanett (University of Texas at Austin, Austin, TX); Thomas, Sunil G. (University of Texas at Austin, Austin, TX); Rightley, Michael J.; Rodriguez, Adolfo (University of Texas at Austin, Austin, TX); Klie, Hector (University of Texas at Austin, Austin, TX); Banchs, Rafael (University of Texas at Austin, Austin, TX); Nunez, Emilio J. (University of Texas at Austin, Austin, TX); Jablonowski, Chris (University of Texas at Austin, Austin, TX)

    2006-11-01

    survivability issues. Our findings indicate that packaging represents the most significant technical challenge associated with application of sensors in the downhole environment for long periods (5+ years) of time. These issues are described in detail within the report. The impact of successful reservoir monitoring programs and coincident improved reservoir management is measured by the production of additional oil and gas volumes from existing reservoirs, revitalization of nearly depleted reservoirs, possible re-establishment of already abandoned reservoirs, and improved economics for all cases. Smart Well monitoring provides the means to understand how a reservoir process is developing and to provide active reservoir management. At the same time it also provides data for developing high-fidelity simulation models. This work has been a joint effort with Sandia National Laboratories and UT-Austin's Bureau of Economic Geology, Department of Petroleum and Geosystems Engineering, and the Institute of Computational and Engineering Mathematics.

  4. Geologic, geochemical, and geographic controls on NORM in produced water from Texas oil, gas, and geothermal reservoirs. Final report

    Energy Technology Data Exchange (ETDEWEB)

    Fisher, R.

    1995-08-01

    Water from Texas oil, gas, and geothermal wells contains natural radioactivity that ranges from several hundred to several thousand Picocuries per liter (pCi/L). This natural radioactivity in produced fluids and the scale that forms in producing and processing equipment can lead to increased concerns for worker safety and additional costs for handling and disposing of water and scale. Naturally occurring radioactive materials (NORM) in oil and gas operations are mainly caused by concentrations of radium-226 ({sup 226}Ra) and radium-228 ({sup 228}Ra), daughter products of uranium-238 ({sup 238}U) and thorium-232 ({sup 232}Th), respectively, in barite scale. We examined (1) the geographic distribution of high NORM levels in oil-producing and gas-processing equipment, (2) geologic controls on uranium (U), thorium (Th), and radium (Ra) in sedimentary basins and reservoirs, (3) mineralogy of NORM scale, (4) chemical variability and potential to form barite scale in Texas formation waters, (5) Ra activity in Texas formation waters, and (6) geochemical controls on Ra isotopes in formation water and barite scale to explore natural controls on radioactivity. Our approach combined extensive compilations of published data, collection and analyses of new water samples and scale material, and geochemical modeling of scale Precipitation and Ra incorporation in barite.

  5. High Order Adjoint Derivatives using ESDIRK Methods for Oil Reservoir Production Optimization

    DEFF Research Database (Denmark)

    Capolei, Andrea; Stenby, Erling Halfdan; Jørgensen, John Bagterp

    2012-01-01

    and continuous adjoints . The high order integration scheme allows larger time steps and therefore faster solution times. We compare gradient computation by the continuous adjoint method to the discrete adjoint method and the finite-difference method. The methods are implemented for a two phase flow reservoir...

  6. WETTABILITY AND PREDICTION OF OIL RECOVERY FROM RESERVOIRS DEVELOPED WITH MODERN DRILLING AND COMPLETION FLUIDS

    Energy Technology Data Exchange (ETDEWEB)

    Jill S. Buckley; Norman R. Morrow

    2004-05-01

    We report on progress in three areas. In part one, the wetting effects of synthetic base oils are reported. Part two reports progress in understanding the effects of surfactants of known chemical structures, and part three integrates the results from surface and core tests that show the wetting effects of commercial surfactant products used in synthetic and traditional oil-based drilling fluids. An important difference between synthetic and traditional oil-based muds (SBM and OBM, respectively) is the elimination of aromatics from the base oil to meet environmental regulations. The base oils used include dearomatized mineral oils, linear alpha-olefins, internal olefins, and esters. We show in part one that all of these materials except the esters can, at sufficiently high concentrations, destabilize asphaltenes. The effects of asphaltenes on wetting are in part related to their stability. Although asphaltenes have some tendency to adsorb on solid surfaces from a good solvent, that tendency can be much increased near the onset of asphaltene instability. Tests in Berea sandstone cores demonstrate wetting alteration toward less water-wet conditions that occurs when a crude oil is displaced by paraffinic and olefinic SBM base oils, whereas exposure to the ester products has little effect on wetting properties of the cores. Microscopic observations with atomic forces microscopy (AFM) and macroscopic contact angle measurements have been used in part 2 to explore the effects on wetting of mica surfaces using oil-soluble polyethoxylated amine surfactants with varying hydrocarbon chain lengths and extent of ethoxylation. In the absence of water, only weak adsorption occurs. Much stronger, pH-dependent adsorption was observed when water was present. Varying hydrocarbon chain length had little or no effect on adsorption, whereas varying extent of ethoxylation had a much more significant impact, reducing contact angles at nearly all conditions tested. Preequilibration of

  7. Application of integrated reservoir management and reservoir characterization to optimize infill drilling. Quarterly technical progress report, March 13--June 12, 1997

    Energy Technology Data Exchange (ETDEWEB)

    NONE

    1997-12-31

    The eighteen 10-acre infill wells which were drilled as part of the field demonstration portion of the project are all currently in service with no operational problems. These wells consist of fourteen producing wells and four injection wells. The producing wells are currently producing a total of approximately 650 bopd, down from a peak rate of 900 bopd. Unit production is currently averaging approximately 3,000 bopd, 12,000 bwpd and 18,000 bwipd. The paper describes progress in core analysis, reservoir surveillance, well stimulation, validation of reservoir characterization (includes thin section analyses, depositional environments, and paleontologic analysis), material balance decline curve analysis, and validation of reservoir simulation (includes geostatistical and deterministic).

  8. Research of Pangu Liang Jurassic reservoir water flooding enhance oil recovery technology%盘古梁侏罗系油藏提高水驱采收率技术研究

    Institute of Scientific and Technical Information of China (English)

    王凯; 陈建宏; 宋鹏程; 张彬; 杨学武; 张鹏; 李化斌; 吴国文

    2012-01-01

    In this paper, pangu Liang Jurassic reservoir water exist on the plane and the profile of water flooding the uneven state of deterioration of water problem, analyze the impact of reservoir oil recovery injection water flooding deposition rhythm, gravity, reservoir heterogeneity, bottom and edge water development, such as controlling factors of fracturing, injection and production to work out fine adjust and improve the injection and production wells Nets, "three small one low" primer efficiency measures, such as water injection cycle to carry out a balanced plane of the technical means of water flooding and to improve the profile of water flooding blocking the transfer of drive, fill hole profile, temporary blocking acidification and selective technical means such as by injection, thus enhance reservoir recovery injection water flooding, effectively slowing aquifer rise, lower oil field decline, to ensure that the beam Jurassic pangu Jurassic reservoir stable and efficient development.%针对盘古梁侏罗系油藏注水上存在的平面水驱不均和剖面吸水状况变差的问题,分析影响油藏注水水驱采收率的沉积韵律、重力作用、储层非均质性、边底水发育、压裂改造等控制因素,研究出精细注采调整、完善注采井网、“三小一低”措施引效、开展周期注水等均衡平面水驱的技术手段,以及改善剖面水驱的化堵调驱、补孔调剖、暂堵酸化和选择性增注等技术手段,从而提高油藏注水水驱采收率,有效减缓含水上升、降低油田递减,确保盘古梁侏罗系油藏稳定高效开发。

  9. 盘古梁侏罗系油藏提高水驱采收率技术研究%Research of Panguliang Jurassic reservoir water flooding enhance oil recovery technology

    Institute of Scientific and Technical Information of China (English)

    王凯; 陈建宏; 张彬; 杨学武; 张鹏; 李化斌; 吴国文

    2012-01-01

    In this paper, Panguliang Jurassic reservoir water exist on the pilane and the profile of water flooding the uneven state of deterioration of water problem, analyze the impact of reservoir oil recovery injection water flooding deposition rhythm, gravity, reservoir hetero- geneity , bottom and edge water development, such as controlling factors ,of fracturing, injec- tion and production to work out fine adjust and improve the injection and production wells Nets, "three small one low" primer efficiency measures, such as water injection cycle to car- ry out a balanced plane of the technical means of water flooding and to improve the profile of water flooding blocking the transfer of drive, fill hole profile, temporary blocking acidifica- tion and selective technical means such as by injection, thus enhance reservoir recovery in- jection water flooding, effectively slowing aquifer rise, lower oil field decline, to ensure that the beam Jurassic pangu Jurassic reservoir stable and efficient development.%针对盘古梁侏罗系油藏注水上存在的平面水驱不均和剖面吸水状况变差的问题,分析影响油藏注水水驱采收率的沉积韵律、重力作用、储层非均质性、边底水发育、压裂改造等控制因素,研究出精细注采调整、完善注采井网、“三小一低”措施引效、开展周期注水等均衡平面水驱的技术手段,以及改善剖面水驱的化堵调驱、补孔调剖、暂堵酸化和选择性增注等技术手段,从而提高油藏注水水驱采收率,有效减缓含水上升、降低油田递减,确保盘古梁侏罗系油藏稳定高效开发。

  10. SAGD pilot project, wells MFB-772 (producer) / MFB-773 (injector), U1,3 MFB-53 reservoir, Bare Field. Orinoco oil belt. Venezuela

    Energy Technology Data Exchange (ETDEWEB)

    Mago, R.; Franco, L.; Armas, F.; Vasquez, R.; Rodriguez, J.; Gil, E. [PDVSA EandP (Venezuela)

    2011-07-01

    In heavy oil and extra heavy oil fields, steam assisted gravity drainage is a thermal recovery method used to reduce oil viscosity and thus increase oil recovery. For SAGD to be successfully applied in deep reservoirs, drilling and completion of the producer and injector wells are critical. Petroleos de Venezuela SA (PDVSA) is currently assessing the feasibility of SAGD in the Orinoco oil belt in Venezuela and this paper aims at presenting the methodology used to ensure optimal drilling and completion of the project. This method was divided in several stages: planning, drilling and completion of the producer, injector and then of the observer wells and cold information capture. It was found that the use of magnetic guidance tools, injection pipe pre-insulated and pressure and temperature sensors helps optimize the drilling and completion process. A methodology was presented to standardize operational procedures in the drilling and completion of SAGD projects in the Orinoco oil belt.

  11. GEOCHEMICAL CHARACTERISTICS OF OIL RESERVOIRS FLOODED BY WATER AND POLYMER%水驱和聚合物驱油藏地球化学特征

    Institute of Scientific and Technical Information of China (English)

    张居和; 冯子辉; 方伟; 张琨

    2012-01-01

    油藏地球化学研究是水驱综合挖潜、聚驱精细调整开采剩余油的基础,采集萨尔图油田北一断西区聚合物驱前后2口小井距对比检查井的葡一组油砂样品51件,通过岩心分析获得油藏剩余油黏度、流度、含油饱和度、驱油效率等实验数据.实验研究结果表明,水驱后和聚合物驱后油藏剩余油黏度、流度、含油饱和度、驱油效率分布都呈现一定的非均质性特征,聚合物驱后较水驱后油藏剩余油变稠,剩余油开采潜力明显降低,驱油效率显著提高,驱油效率和含油饱和度的非均质性减弱;聚合物驱技术能够提高各种物性油藏的驱油效率,水驱技术能够提高高中低渗透油层的驱油效率,但在特高渗透油层则“无效循环”且随渗透率增大呈下降趋势;提高水驱油藏驱油效率的方法是降低剩余油黏度或提高水驱溶液的黏度即加入黏稠化学剂;提高聚合物驱油藏驱油效率的方法是降低剩余油黏度、提高聚合物驱溶液黏度或改善油层物性.%Geochemical researches of an oil reservoir are the basis of exploiting the remained oil by comprehensively tapping the potentials in water flooding and fine adjustment to polymer flooding. 51 oil-sand samples are collected in Pul Formation of two close-spacing comparing & inspecting wells in West Beil Fault Block of Saertu Oilfield before and after polymer flooding. Experimental data were gained by coring analysis, such as the remained oil viscosity, mobility, oil saturation, oil displaced efficiency and so on. The experimental study results show that the distributions of the above parameters after water and polymer floodings are characterized by a certain heterogeneity. The remained oil becomes more thicker after polymer flooding than water flooding, and furthermore the exploitation potentials of the remained oil are obviously reduced, the oil displaced efficiency is remarkably increased and heterogeneities of

  12. Increased oil production and reserves utilizing secondary/tertiary recovery techniques on small reservoirs in the Paradox basin, Utah. Annual report

    Energy Technology Data Exchange (ETDEWEB)

    Chidsey, T.C. Jr.

    1997-02-01

    The Paradox basin of Utah, Colorado, and Arizona contains nearly 100 small oil fields producing from carbonate buildups or mounds within the Pennsylvanian (Desmoinesian) Paradox Formation. These fields typically have one to four wells with primary production ranging from 700,000 to 2,000,000 barrels of oil per field at a 15 to 20% recovery rate. At least 200 million barrels of oil is at risk of being unrecovered in these small fields because of inefficient recovery practices and undrained heterogeneous reservoirs. Five fields (Anasazi, mule, Blue Hogan, heron North, and Runway) within the Navajo Nation of southeastern utah are being evaluated for waterflood or carbon-dioxide-miscible flood projects based upon geological characterization and reservoir modeling. The results can be applied to other fields in the Paradox basin and the Rocky Mountain region, the Michigan and Illinois basins, and the Midcontinent. The reservoir engineering component of the work completed to date included analysis of production data and well tests, comprehensive laboratory programs, and preliminary mechanistic reservoir simulation studies. A comprehensive fluid property characterization program was completed. Mechanistic reservoir production performance simulation studies were also completed.

  13. WETTABILITY AND PREDICTION OF OIL RECOVERY FROM RESERVOIRS DEVELOPED WITH MODERN DRILLING AND COMPLETION FLUIDS

    Energy Technology Data Exchange (ETDEWEB)

    Jill S. Buckley; Norman r. Morrow

    2002-06-01

    This first semiannual report covers efforts to select the materials that will be used in this project. Discussions of crude oils, rocks, smooth mineral surfaces, and drilling mud additives are included in this report.

  14. 套保稠油油藏出砂冷采后提高采收率技术%EOR technology for Taobao heavy oil reservoir afler cold production with sand

    Institute of Scientific and Technical Information of China (English)

    谷武; 林雨凤; 李旭东; 邓涛; 刘杨

    2012-01-01

    通过分析区块开发形式和存在的问题,进行了出砂冷采后多种开发方式的标准筛选以及此技术在该油藏的适应性研究,结合火驱物理模拟实验,明确了该区块进行火驱的可行性;利用数值模拟技术,优选了火驱合理的井网方式和注气参数.2007年开始,通过开展现场试验,见到了较好的效果,为提高区块采收率提供了技术支持.%The development schemes after cold production with sand have been screened and their applicability has been studied for the Taobao heavy oil reservoir based on analysis of the development situation and existing problems. It has been determined through physical simulation tests that in - situ combustion is feasible for the reservoir. Rational well pattern and air injection parameters have been optimized through numerical simulations. Since 2007, field tests have achieved satisfactory result, and provided technical support for improving reservoir recovery factor.

  15. Post Waterflood CO2 Miscible Flood in Light Oil, Fluvial-Dominated Deltaic Reservoir (Pre-Work and Project Proposal), Class I

    Energy Technology Data Exchange (ETDEWEB)

    Bou-Mikael, Sami

    2002-02-05

    This project outlines a proposal to improve the recovery of light oil from waterflooded fluvial dominated deltaic (FDD) reservoir through a miscible carbon dioxide (CO2) flood. The site is the Port Neches Field in Orange County, Texas. The field is well explored and well exploited. The project area is 270 acres within the Port Neches Field.

  16. Analysis of Information of Oil-bearing Reservoir Using Seismic Attributes Technique--A Case Study of HD4 Oilfield, Tarim Basin

    Institute of Scientific and Technical Information of China (English)

    CHEN Bo; LING Yun; LIU Qin-fu; WANG Xiao-ping

    2005-01-01

    The theoretical and practical analysis of reservoir thickness and oil-bearing information of thin reservoirs is performed by using seismic attributes and forward modelling. The results show that thin reservoir can be recognized using seismic attributes technique when its thickness is less than 1/4 of wavelength. Through analyzing the influence of tuning effect, the relationship between thin layer thickness and tuning amplitude is well revealed. A precise structure interpretation is conducted using relative amplitude preserved high-resolution seismic data. By taking the geologic condition and well data into account, the distribution of oil and gas of HD4 oilfield is analyzed and predicted. Based on seismic attributes. The result is helpful to promote the exploration and development in this oilfield.

  17. Legal aspects and technical alternatives for the treatment of reservoir brines at the Activo Luna oilfield, Mexico.

    Science.gov (United States)

    Birkle, Peter; Cid Vázquez, Adolfo L; Fong Aguilar, J L

    2005-01-01

    Deep formation water, extracted as an undesired byproduct from on-shore production wells at the Activo Luna oilfield and processed in adjacent oil fields, are highly enriched in salt minerals, especially in sodium chloride (NaCl) (262 000 mg/L), but also in metals and nonmetals, such as strontium (Sr) (2068 mg/L), bromine (Br) (2034 mg/L), boron (B) (396 mg/ L), iodine (I) (43.4 mg/L), selenium (Se) (3.74 mg/L), and arsenic (As) (0.55 mg/L). Direct reinjection of the brine underground is not possible because of elevated pressure conditions within the petroleum reservoir. The disposal into near shore areas of the Gulf of Mexico without treatment must be rejected because of a) elevated concentrations of some toxic elements, such as B, silver (Ag), thallium (Tl), Se and cadmium (Cd), which exceed permissible limits of environmental legislation for surface discharge (Official Mexican norms NOM-001-ECOL-1998 and CE-CCA-001/89), and b) differences in density that could cause the descent of hypersaline fluid to the ocean floor, potentially affecting the diversity and survival of the benthic ecosystem. Conventional treatment techniques, such as microfiltration or reverse osmosis, are not suitable for the Activo Luna brines because of their extreme mineralization, which will cause pressure conditions exceeding 200 bars across the membrane. As an alternative process, the evaporation of the entire brine volume of approximately 200 m3/day by solar ponds or industrial crystallization plants is suggested. The residual precipitated residuals are composed mainly of chlorine (Cl) (9460 tons/year), sodium (Na) (4230 tons/ year), calcium (Ca) (1028 tons/year), potassium (K) (207 tons/year), and magnesium (Mg) (65.8 tons/year). As an alternative to its disposal on a dumpsite, some special minerals (especially NaCl, Mg, Sr, and Br) could be recovered for its economic value.

  18. Investigation of oil recovery improvement by coupling an interfacial tension agent and a mobility control agent in light oil reservoirs. Annual report, October 1992--September 1993

    Energy Technology Data Exchange (ETDEWEB)

    Pitts, M.J.

    1994-06-01

    Investigation of Oil Recovery Improvement by Coupling and Interfacial Tension Agent and a Mobility Control Agent in Light Oil Reservoirs will study two major areas concerning co-injecting an interfacial tension reduction agent(s) and a mobility control agent. The first area defines the interactions of alkaline agent, surfactants, and polymers on a fluid-fluid and fluid-rock basis. The second area concerns the economic improvement of the combined technology. This report examines the interactions of different alkaline agents, surfactants, and polymer combinations on a fluid-fluid basis. Alkali and surfactant combine to reduce the interfacial tension between a low acid number, 42 API gravity crude oil and the aqueous solution to values lower than either agent alone. Surfactant structure can vary from linear chain sulfonates to alkyl aryl sulfonates to produce low interfacial tension values when combined with alkali. However as a class, the alkyl aryl sulfonates were the most effective surfactants. Surfactant olefinic character appears to be critical in developing low interfacial tensions. For the 42 API gravity crude oil, surfactants with molecular weights ranging from 370 to 450 amu are more effective in lowering interfacial tension. Ultra low interfacial tensions were achieved with all of the alkaline agents evaluated when combined with appropriate surfactants. Different interfacial tension reduction characteristics with the various alkali types indicates alkali interacts synergistically with the surfactants to develop interfacial tension reduction. The solution pH is not a determining factor in lowering interfacial tension. Surfactant is the dominant agent for interfacial tension reduction.

  19. A Systems Approach to Bio-Oil Stabilization - Final Technical Report

    Energy Technology Data Exchange (ETDEWEB)

    Brown, Robert C; Meyer, Terrence; Fox, Rodney; Submramaniam, Shankar; Shanks, Brent; Smith, Ryan G

    2011-12-23

    The objective of this project is to develop practical, cost effective methods for stabilizing biomass-derived fast pyrolysis oil for at least six months of storage under ambient conditions. The U.S. Department of Energy has targeted three strategies for stabilizing bio-oils: (1) reducing the oxygen content of the organic compounds comprising pyrolysis oil; (2) removal of carboxylic acid groups such that the total acid number (TAN) of the pyrolysis oil is dramatically reduced; and (3) reducing the charcoal content, which contains alkali metals known to catalyze reactions that increase the viscosity of bio-oil. Alkali and alkaline earth metals (AAEM), are known to catalyze decomposition reactions of biomass carbohydrates to produce light oxygenates that destabilize the resulting bio-oil. Methods envisioned to prevent the AAEM from reaction with the biomass carbohydrates include washing the AAEM out of the biomass with water or dilute acid or infusing an acid catalyst to passivate the AAEM. Infusion of acids into the feedstock to convert all of the AAEM to salts which are stable at pyrolysis temperatures proved to be a much more economically feasible process. Our results from pyrolyzing acid infused biomass showed increases in the yield of anhydrosugars by greater than 300% while greatly reducing the yield of light oxygenates that are known to destabilize bio-oil. Particulate matter can interfere with combustion or catalytic processing of either syngas or bio-oil. It also is thought to catalyze the polymerization of bio-oil, which increases the viscosity of bio-oil over time. High temperature bag houses, ceramic candle filters, and moving bed granular filters have been variously suggested for syngas cleaning at elevated temperatures. High temperature filtration of bio-oil vapors has also been suggested by the National Renewable Energy Laboratory although there remain technical challenges to this approach. The fast pyrolysis of biomass yields three main organic

  20. Application of MODFLOW for oil reservoir simulation during the Deepwater Horizon Crisis

    Science.gov (United States)

    Hsieh, Paul A.

    2011-01-01

    When the Macondo well was shut in on July 15, 2010, the shut-in pressure recovered to a level that indicated the possibility of oil leakage out of the well casing into the surrounding formation. Such a leak could initiate a hydraulic fracture that might eventually breach the seafloor, resulting in renewed and uncontrolled oil flow into the Gulf of Mexico. To help evaluate whether or not to reopen the well, a MODFLOW model was constructed within 24 h after shut in to analyze the shut-in pressure. The model showed that the shut-in pressure can be explained by a reasonable scenario in which the well did not leak after shut in. The rapid response provided a scientific analysis for the decision to keep the well shut, thus ending the oil spill resulting from the Deepwater Horizon blow out.

  1. Application of MODFLOW for oil reservoir simulation during the Deepwater Horizon crisis.

    Science.gov (United States)

    Hsieh, Paul A

    2011-01-01

    When the Macondo well was shut in on July 15, 2010, the shut-in pressure recovered to a level that indicated the possibility of oil leakage out of the well casing into the surrounding formation. Such a leak could initiate a hydraulic fracture that might eventually breach the seafloor, resulting in renewed and uncontrolled oil flow into the Gulf of Mexico. To help evaluate whether or not to reopen the well, a MODFLOW model was constructed within 24 h after shut in to analyze the shut-in pressure. The model showed that the shut-in pressure can be explained by a reasonable scenario in which the well did not leak after shut in. The rapid response provided a scientific analysis for the decision to keep the well shut, thus ending the oil spill resulting from the Deepwater Horizon blow out.

  2. An example of using oil-production induced microseismicity in characterizing a naturally fractured reservoir

    Energy Technology Data Exchange (ETDEWEB)

    Rutledge, J.T.; Phillips, W.S. [Nambe Geophysical, Inc., Santa Fe, NM (United States); Schuessler, B.K.; Anderson, D.W. [Los Alamos National Lab., NM (United States)

    1996-06-01

    Microseismic monitoring was conducted using downhole geophone tools deployed in the Seventy-Six oil field, Clinton County, Kentucky. Over a 7-month monitoring period, 3237 microearthquakes were detected during primary oil production; no injection operations were conducted. Gross changes in production rate correlate with microearthquake event rate with event rate lagging production-rate changes by about 2 weeks. Hypocenters and first-motion data have revealed low-angle, thrust fracture zones above and below the currently drained depth interval. Production history, well logs and drill tests indicate the seismically-active fractures are previously drained intervals that have subsequently recovered to hydrostatic pressure via brine invasion. The microseismic data have revealed, for the first time, the importance of the low-angle fractures in the storage and production of oil in the study area. The seismic behavior is consistent with poroelastic models that predict slight increases in compressive stress above and below currently drained volumes.

  3. Dominant geological element of migration and accumulation about Silurian oil reservoirs in central Tarim

    Institute of Scientific and Technical Information of China (English)

    2007-01-01

    Based on the migration track of the Silurian oil pools along the faults in central Tarim by the nitrogen compounds and the maturity parameters of saturated hydrocarbon and aromatic hydrocarbon, the formation of the Silurian oil pools was totally concerned with vertical migration that faults were the dominant migration channels. The comprehensive analysis shows that the dominant geological element, which contributed to the migration and accumulation of the Silurian oil pools in central Tarim,was the strike-slip fault, which developed from Ordovician to Permian. The future work will focus on conducting a more intensive study of the formation, evolution and distribution of the strike-slip faults for making sure of favorable hydrocarbon accumulation and favorable exploration targets.

  4. Optimization of Spore Forming Bacteria Flooding for Enhanced Oil Recovery in North Sea Chalk Reservoir

    DEFF Research Database (Denmark)

    Halim, Amalia Yunita; Nielsen, Sidsel Marie; Eliasson Lantz, Anna;

    2015-01-01

    was used for this purpose. A spore forming bacterium, Bacillus licheniformis 421, was used as it was shown to be a good candidate in the previous study. Bacterial spore can penetrate deeper into the chalk rock, squeezing through the pore throats. Our results show that B. licheniformis 421 when injected...... as a secondary technique can recover 4% more of the original oil in place (OOIP) as compared with the seawater flooding. Furthermore, when applied as tertiary technique it can recover 1.4% OOIP of the residual oil. The effective permeability decreased in the first two sections of the core (0-1.2 cm and 1...

  5. Wettability Improvement with Enzymes: Application to Enhanced Oil Recovery under Conditions of the North Sea Reservoirs

    DEFF Research Database (Denmark)

    Khusainova, Alsu; Shapiro, Alexander; Stenby, Erling Halfdan

    2012-01-01

    , proteases and oxidoreductases, provided by Novozymes, have been investigated. Two commercial mixtures containing enzymes: Apollo-GreenZyme™ and EOR-ZYMAX™ have also been applied. The North Sea dead oil and the synthetic sea water were used as test fluids. Internal surface of a carbonate rock has been...... interfacially active oil compounds. Application of the commercial product Apollo-GreenZyme™ has also resulted in positive wettability changes, but according to the observations the working mechanisms are different. In an attempt to assess validity of the proposed mechanisms, the reference experiments have been...

  6. Dynamic reservoir well interaction

    NARCIS (Netherlands)

    Sturm, W.L.; Belfroid, S.P.C.; Wolfswinkel, O. van; Peters, M.C.A.M.; Verhelst, F.J.P.C.M.

    2004-01-01

    In order to develop smart well control systems for unstable oil wells, realistic modeling of the dynamics of the well is essential. Most dynamic well models use a semi-steady state inflow model to describe the inflow of oil and gas from the reservoir. On the other hand, reservoir models use steady s

  7. Technical and economic study of a mobile system for extraction of eucalyptus essential oil

    Directory of Open Access Journals (Sweden)

    Gisele Aparecida Vivan

    2011-03-01

    Full Text Available The production of essential oils has become increasing in Brazil, especially considering the benefits that certain substances can add to health and range of cosmetics, toiletries and drugs that originate in its processing. Based on these conditions and in the vast area of the Rio Grande do Sul where it is being implanted the culture of eucalyptus, this study seeks ways to boost the economic structure of culture, seeking to generate new business opportunities through the extraction of oil contained in the leaves Eucalyptus, a byproduct of the paper industry, the current main economic interest of culture. Based on these assumptions, it was elaborated a conceptual design of a mobile equipment able to meet the processing demand of the crop, determining a diagram processing flow and fitting the equipment to meet this demand. Subsequently, it was evaluated the technical and economic feasibility of deploying the mobile extraction system for essential oil of eucalyptus in the southern region of Rio Grande do Sul, conducting technical studies for the improvement and efficiency of the conceptual design and economic feasibility analysis to determine variables that determine the success of the project. It was conclude that the conceptual design has beneficial aspects, especially regarding the mobility, flexibility of use, minimization of empty spaces and water use in semi-closed circuit. In the analysis of economic feasibility, the simulated scenarios showed positive values for Net Present Value, Internal Rate of Return above the minimum rate of attractiveness and capital Payback relatively short, even for the scenarios considered critical.

  8. Synthesis of Polymer-Coated Magnetic Nanoparticles from Red Mud Waste for Enhanced Oil Recovery in Offshore Reservoirs

    Science.gov (United States)

    Nguyen, T. P.; Le, U. T. P.; Ngo, K. T.; Pham, K. D.; Dinh, L. X.

    2016-07-01

    Buried red mud waste from groundwater refineries can cause pollution. The aim of this paper is to utilize this mud for the synthesis of Fe3O4 magnetic nanoparticles (MNPs). Then, MNPs are encapsulated by a copolymer of methyl methacrylate and 2-acrylamido-2-methyl-1-propanesulfonate via oleic acid linker. MNPs are prepared by a controlled co-precipitation method in the presence of a dispersant and surface-modified agents to achieve a high hydrophobic or hydrophilic surface. Mini-emulsion polymerization was conducted to construct a core-shell structure with MNPs as core and the copolymer as shell. The core-shell structure of the obtained particles enables them to disperse well in brine and to stabilize at high-temperature environments. The chemical structures and morphology of this nanocomposite were investigated by Fourier transform infrared spectroscopy, transmission electron microscopy, and field emission scanning electron microscopy. The thermal stability of the nanocomposite was evaluated via a thermogravimetric analysis method for the solid state and an annealing experiment for the liquid state. The nanocomposite is about 14 nm, disperses well in brine and is thermally stable in the solid state. The blends of synthesized nanocomposite and carboxylate surfactant effectively reduced the interfacial tension between crude oil and brine, and remained thermally stable after 31 days annealed at 100°C. Therefore, a nanofluid of copolymer/magnetic nanocomposite can be applied as an enhanced oil recovery agent for harsh environments in offshore reservoirs.

  9. Disposal of NORM-contaminated oil field wastes in salt caverns -- Legality, technical feasibility, economics, and risk

    Energy Technology Data Exchange (ETDEWEB)

    Veil, J.A.; Smith, K.P.; Tomasko, D.; Elcock, D.; Blunt, D.; Williams, G.P.

    1998-07-01

    Some types of oil and gas production and processing wastes contain naturally occurring radioactive materials (NORM). If NORM is present at concentrations above regulatory levels in oil field waste, the waste requires special disposal practices. The existing disposal options for wastes containing NORM are limited and costly. This paper evaluates the legality, technical feasibility, economics, and human health risk of disposing of NORM-contaminated oil field wastes in salt caverns. Cavern disposal of NORM waste is technically feasible and poses a very low human health risk. From a legal perspective, there are no fatal flaws that would prevent a state regulatory agency from approaching cavern disposal of NORM. On the basis of the costs charged by caverns currently used for disposal of nonhazardous oil field waste (NOW), NORM waste disposal caverns could be cost competitive with existing NORM waste disposal methods when regulatory agencies approve the practice.

  10. Wettability Improvement with Enzymes: Application to Enhanced Oil Recovery under Conditions of the North Sea Reservoirs

    DEFF Research Database (Denmark)

    Khusainova, Alsu; Shapiro, Alexander; Stenby, Erling Halfdan

    2012-01-01

    , proteases and oxidoreductases, provided by Novozymes, have been investigated. Two commercial mixtures containing enzymes: Apollo-GreenZyme™ and EOR-ZYMAX™ have also been applied. The North Sea dead oil and the synthetic sea water were used as test fluids. Internal surface of a carbonate rock has been...

  11. Application of geo-microbial prospecting method for finding oil and gas reservoirs

    Science.gov (United States)

    Rasheed, M. A.; Hasan, Syed Zaheer; Rao, P. L. Srinivasa; Boruah, Annapurna; Sudarshan, V.; Kumar, B.; Harinarayana, T.

    2015-03-01

    Microbial prospecting of hydrocarbons is based on the detection of anomalous population of hydrocarbon oxidizing bacteria in the surface soils, indicates the presence of subsurface oil and gas accumulation. The technique is based on the seepage of light hydrocarbon gases such as C1-C4 from the oil and gas pools to the shallow surface that provide the suitable conditions for the development of highly specialized bacterial population. These bacteria utilize hydrocarbon gases as their only food source and are found enriched in the near surface soils above the hydrocarbon bearing structures. The methodology involves the collection of soil samples from the survey area, packing, preservation and storage of samples in pre-sterilized sample bags under aseptic and cold conditions till analysis and isolation and enumeration of hydrocarbon utilizing bacteria such as methane, ethane, propane, and butane oxidizers. The contour maps for the population density of hydrocarbon oxidizing bacteria are drawn and the data can be integrated with geological, geochemical, geophysical methods to evaluate the hydrocarbon prospect of an area and to prioritize the drilling locations thereby reducing the drilling risks and achieve higher success in petroleum exploration. Microbial Prospecting for Oil and Gas (MPOG) method success rate has been reported to be 90%. The paper presents details of microbial prospecting for oil and gas studies, excellent methodology, future development trends, scope, results of study area, case studies and advantages.

  12. Immiscible and Miscible Gas-Oil Gravity Drainage in Naturally Fractured Reservoirs

    NARCIS (Netherlands)

    Ameri, A.

    2014-01-01

    In the phase of declining oilfields and at a time when recovering hydrocarbons has becoming more difficult, effective techniques are the key to extract more oil from mature fields. The difficulty of developing effective techniques is often the real obstacle when dealing with heterogeneous formations

  13. Drilling fluids engineering to drill extra-heavy oil reservoir on the Orinoco Oil Belt, eastern Venezuela

    Energy Technology Data Exchange (ETDEWEB)

    Pino, R.; Gonazalez, W. [Proamsa, Maturin, Monagas (Venezuela)

    2008-07-01

    Petrocedeno is an exploration and development company operating in Venezuela. As part of a multidisciplinary group, Proamsa has been working with Petrocedeno to drill horizontal wells while minimizing issues related to the handling of drilling fluids. Proamsa is the only 100 per cent Venezuelan Company involved in drilling extra-heavy oil wells. The drilling plan for Petrocedeno was divided into two campaigns. More than 400 horizontal wells were drilled during the first campaign from 1999 to 2003 which represented over 2,500,000 drilled feet into the Oficina Formation (pay zone of the field). From 2006, during the second drilling campaign, and another 154 horizontal wells having been drilled until 2006 utilizing the xantam gum viscoelastic fluid. This paper discussed the field geology of the Orinoco oil belt. Well design was also explained and discussed and drilling fluid design and new fluid formations were presented. The benefits of xantam gum viscoelastic fluid were also discussed. It was concluded that recycling of drilling fluid from well to well minimized volume and reduced costs. In addition, centrifugation of drilling fluids either on intermediate or horizontals sections while the rig was skidding was always a very good practice avoiding mixing additional volumes. It was also demonstrated that the initial idea to provide a drilling fluid service company with a 100 per cent national value was a success, as demonstrated by the high performance shown by Proamsa during the second drilling campaign with external technologic support. 6 refs., 4 tabs., 4 figs.

  14. Diagenesis and Restructuring Mechanism of Oil and Gas Reservoir in the Marine Carbonate Formation, Northeastern Sichuan: A Case Study of the Puguang Gas Reservoir

    Institute of Scientific and Technical Information of China (English)

    DU Chunguo; WANG Jianjun; ZOU Huayao; ZHU Yangming; WANG Cunwu

    2009-01-01

    Based on the technology of balanced cross-section and physical simulation experiments associated with natural gas geochemical characteristic analyses, core and thin section observations, it has been proven that the Puguang gas reservoir has experienced two periods of diagenesis and restructuring since the Late lndo-Chinese epoch. One is the fluid transfer controlled by the tectonic movement and the other is geochemical reconstruction controlled by thermochemical sulfate reduction (TSR). The middle Yanshan epoch was the main period that the Puguang gas reservoir experienced the geochemical reaction of TSR. TSR can recreate the fluid in the gas reservoir, which makes the gas drying index higher and carbon isotope heavier because C_(2+) (ethane and heavy hydrocarbon) and ~(12)C (carbon 12 isotope) is first consumed relative to CH_4 and ~(13)C (carbon 13 isotope). However, the reciprocity between fluid regarding TSR (hydrocarbon, sulfureted hydrogen (H_2S), and water) and reservoir rock results in reservoir rock erosion and anhydrite alteration, which increases porosity in reservoir, thereby improving the petrophysical properties. Superimposed by later tectonic movement, the fluid in Puguang reservoir has twice experienced adjustment, one in the late Yanshan epoch to the early Himalayan epoch and the other time in late Himalayan epoch, after which Puguang gas reservoir is finally developed.

  15. Reconstruction of sedimentary environments of J2-4 reservoir rocks of the Lovin oil field by facial analysis and 3D simulation

    Science.gov (United States)

    Iagudin, R.; Minibaev, N.

    2012-04-01

    The reconstruction of accumulations' conditions of sand bodies and determination of paleogeographical conditions is the basis for 3D modeling of lithologically screened oil and gas reservoirs. The reconstruction of accumulations' conditions is implemented by lithologic-and-facies analysis. The facial types are determined during the analysis of deposits of oil reservoir and then mapped within the reservoir's space. The facies type is an integral characteristic. It is determined on the basis of a large number of research methods such as the processing and analysis of core samples, seismic and well log data. Mapping of reservoirs' facies types allow estimating variability of important for exploration of oil deposits parameters such as reservoir properties, productivity, distribution of effective thickness, etc. The facies types can be mapped as an individual geological unit and used in 3D geological modeling. Subject of facial analysis was sediments of J2-4 reservoir of Lovin oil field (Western Lovin structure) which were accumulated in the Jurassic period. Based on lithologic-and-facies analysis of core material from 6 wells (25 samples), including studies on the grain size measurements, analysis of sediment's structure and core description, the metering of magnetic susceptibility of sediments, facies types of the J2-4 reservoir were identified. The lithotype A is characterized by sand and silt structure, small nodules in the halo of pyrite oxidation, indicated the presence of magnetite. This lithotype belongs to conditions of river-bed facies. The lithotype B have a silty structure, interlayer of coal and traces of bioturbation. This lithotype corresponds to the conditions of sand bars of the floodplain. The lithotype C is characterized by silty-clay structure, single siderite nodules and the remnants of the fauna. This is referring to bog part of the floodplain. After analyzing the well log data of 25 wells of Lovin oil field by Muromtsev methodology distribution

  16. Tailor-made surfactants for optimized chemical EOR. Meeting oil reservoir conditions by applied knowledge of structure-performance relationship in extended surfactants

    Energy Technology Data Exchange (ETDEWEB)

    Trahan, G.; Sorensen, W. [Sasol North America Inc., Westlake, LA (United States); Jakobs-Sauter, B. [Sasol Germany GmbH (Germany)

    2013-08-01

    Formulating the surfactant package for chemical EOR is a time consuming and expensive process - the formulation needs to fit the specific reservoir conditions (like oil type, temperature, salinity, etc.) to give optimum performance and the number of formulation variables is virtually endless. This paper studies the impact of surfactant structure on EOR formulation ability and performance and how to adjust the structure of the surfactant molecule to meet a specific reservoir's needs. Data from salinity phase boundary studies of alcohol propoxy sulfates illustrate how changes in alcohol structure as well as in propylene oxide level can shift optimum salinity and temperature to the desired range in a given model oil. From these data the impact of individual structural units was evaluated. Application of the HLD model (Hydrophilic-Lipophilic Deviation) shows how to extrapolate from the known data set to actual reservoir conditions. This is illustrated by studies on crude oil samples. Additional tests study how effective the selected surfactants perform. The HLD concept proves to be a valuable tool to select and tailor surfactants to individual reservoir needs, thus simplifying the surfactant screening process for EOR formulations by pre-selection of suitable structures and ultimately reducing cost and effort on the way to the most effective chemical EOR package. (orig.)

  17. CO2 Huff-n-Puff process in a light oil shallow shelf carbonate reservoir. Annual report, January 1, 1995--December 31, 1995

    Energy Technology Data Exchange (ETDEWEB)

    Wehner, S.C.; Boomer, R.J.; Cole, R.; Preiditus, J.; Vogt, J.

    1996-09-01

    The application of cyclic CO{sub 2}, often referred to as the CO{sub 2} Huff-n-Puff process, may find its niche in the maturing waterfloods of the Permian Basin. Coupling the CO{sub 2} H-n-P process to miscible flooding applications could provide the needed revenue to sufficiently mitigate near-term negative cash flow concerns in the capital intensive miscible projects. Texaco Exploration & Production Inc. and the U.S. Department of Energy have teamed up in an attempt to develop the CO{sub 2} Huff-n-Puff process in the Grayburg/San Andres formation; a light oil, shallow shelf carbonate reservoir within the Permian Basin. This cost-shared effort is intended to demonstrate the viability of this underutilized technology in a specific class of domestic reservoir. A significant amount of oil reserves are located in carbonate reservoirs. Specifically, the carbonates deposited in shallow shelf (SSC) environments make up the largest percentage of known reservoirs within the Permian Basin of North America. Many of these known resources have been under waterflooding operations for decades and are at risk of abandonment if crude oil recoveries cannot be economically enhanced. The selected site for this demonstration project is the Central Vacuum Unit waterflood in Lea County, New Mexico.

  18. Air injection into light and medium heavy oil reservoirs: combustion tube studies on West of Shetlands Clair oil and light Australian oil

    Energy Technology Data Exchange (ETDEWEB)

    Greaves, M.; Young, T.J.; El-Usta, S.; Rathbone, R.R.; Xia, T.X.

    2000-07-01

    Four combustion tube tests were performed at a high initial water saturation using Bath University's High Pressure Combustion Tube Facility. Two tests were conducted on Clair medium heavy oil (19.8 {sup o} API) at 75 and 100 bar pressure, with initial oil saturations of 48% and 60%, at 80{sup o} C initial bed temperature. Maximum combustion temperatures exceeded 600{sup o}C during the early period, settling down to around 400{sup o}C. The combusted zone extended over about 30% of the sandpack length. Oil recovery was mainly affected by the large steam flood generated ahead of the combustion front, due to in situ vapourization of the original water in place, reducing the oil residual down to 21%. The thermal cracking reactions taking place ahead of combustion front converted part of the residual oil to lighter components, which were displaced with the gas flow, at the same time producing about 10% coke (fuel) for the combustion process. Two tests were carried out on a light Australian oil (38.8 {sup o}API), starting at low initial oil residuals of S{sub o} 41 and 45%, at an operating pressure of 70 bar and initial bed temperature of 63{sup o}C. The combustion temperature was about 250{sup o}C in both tests. The axial temperature profile in the sandpack was similar to that normally associated with a moving combustion front, but at a relatively low temperature. Also, there was no steam plateau condition, which was very observable in the Clair oil tests. High combustion front velocities were achieved in all four tests, varying from 0.15 to 0.31 m h{sup -1}. Fuel consumption, air requirement and oxygen utilization were generally favourable as regards improved oil recovery. (author)

  19. Design and screening of synergistic blends of SiO2 nanoparticles and surfactants for enhanced oil recovery in high-temperature reservoirs

    Science.gov (United States)

    Thi Le, Nhu Y.; Khanh Pham, Duy; Le, Kim Hung; Nguyen, Phuong Tung

    2011-09-01

    SiO2 nanoparticles (NPs) were synthesized by the sol-gel method in an ultrasound reactor and monodispersed NPs with an average particle size of 10-12 nm were obtained. The synergy occurring in blending NPs and anionic surfactant solutions was identified by ultra-low interfacial tension (IFT) reduction measured by a spinning drop tensiometer (Temco500). The oil displacement efficiency of the synergistic blends and surfactant solutions at Dragon South-East (DSE) reservoir temperature was evaluated using contact angle measurement (Dataphysics OCA 20). It was found that SiO2/surfactant synergistic blends displace oil as well as their original surfactant solutions at the same 1000 ppm total concentration. Abundant slag appearing in the SiO2/surfactant medium during oil displacement could be attributed to an adsorption of surfactants onto the NPs. The results indicate that at a concentration of 1000 ppm in total, the original surfactant SS16-47A and its blend with SiO2 NPs in the ratio of 8:2 exhibited an IFT reduction as high as fourfold of the IFT recorded for the DSE oil-brine interface and very high speed of oil displacement. Therefore, it could potentially be applicable to enhanced oil recovery (EOR) in high-temperature reservoirs with high hardness-injection-brine, like the one at DSE. This opens up a new direction for developing effective EOR compositions, which require less surfactant and are environmentally safer.

  20. Study to determine the feasibility of obtaining true samples of oil and gas reservoirs. Final report

    Energy Technology Data Exchange (ETDEWEB)

    Ward, C.E.; Sinclair, A.R.

    1977-10-01

    The study concludes that a feasible solution is possible which would provide up to about 90 percent information accuracy under many operating conditions, well within the economic range for most oil and gas operations. The study also concludes that there is potential feasibility for the development of systems to approach 100 percent information accuracy under many operating situations. However, the cost of such a system is far beyond those considered practical within the economics of the competitive oil and gas industry. The justification of such a system has been likened to that of a ''moon shot'' approach and would take several years of development before true feasibility and probability of success could be assessed.

  1. Seismic Borehole Monitoring of CO2 Injection in an Oil Reservoir

    Science.gov (United States)

    Gritto, R.; Daley, T. M.; Myer, L. R.

    2002-12-01

    A series of time-lapse seismic cross well and single well experiments were conducted in a diatomite reservoir to monitor the injection of CO2 into a hydrofracture zone, based on P- and S-wave data. A high-frequency piezo-electric P-wave source and an orbital-vibrator S-wave source were used to generate waves that were recorded by hydrophones as well as three-component geophones. The injection well was located about 12 m from the source well. During the pre-injection phase water was injected into the hydrofrac-zone. The set of seismic experiments was repeated after a