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Sample records for waterflooding

  1. Do heavy and medium oil waterfloods differ?

    Energy Technology Data Exchange (ETDEWEB)

    Renouf, G. [Saskatchewan Research Council, Saskatoon, SK (Canada)

    2007-07-01

    Waterflooding is a common and important method of enhanced oil recovery. However, little is known about how waterflooding heavy oils differs from waterflooding lighter oils. There is a substantial body of work on designing, monitoring, and managing waterfloods. However, the problems specific to producing heavy oil by waterflooding are rarely addressed. This paper presented the results of a statistical study of 44 heavy oil waterfloods and 39 medium oil waterfloods in western Canadian waterfloods. The purpose of the study was to identify the parameters which impact heavy oil waterflood success. Each waterflood was assigned a numerical value according to the success of each waterflood operation and examined the importance of various reservoir and operating parameters to that success. Waterfloods were classified as either heavy or medium. Separate multivariate analysis models were developed for each set. It was concluded that the most important reservoir parameters to the success of medium oil waterfloods were permeability and heterogeneity. This validated the conventional knowledge of waterflooding, but were not significant to the success of heavy oil waterfloods. 30 refs., 1 tab., 4 figs.

  2. Increasing oil recovery from heavy oil waterfloods

    Energy Technology Data Exchange (ETDEWEB)

    Brice, B.W. [Society of Petroleum Engineers, Canadian Section, Calgary, AB (Canada)]|[BP Exploration, Calgary, AB (Canada)

    2008-10-15

    In an effort to optimize waterflood strategies in Alaska, the authors examined the results of up to 50 years of waterflooding on 166 western Canadian waterfloods recovering oil of less than 30 degrees API. The study determined the best operating practices for heavy oil waterflooding by investigating the difference between waterflooding of heavy oil and lighter oil counterparts. Operators of light oil waterflooding are advised to begin waterflooding early and maintain the voidage replacement ratio (VRR) at 1. However, this study showed that it is beneficial to delay the start of waterflooding until a certain fraction of the original oil in place was recovered. Varying the VRR was also shown to correlate with increased ultimate recovery. This statistical study of 166 western Canadian waterfloods also examined the effect of injection strategy and the effect of primary production before waterflooding. Some pre-waterflood production and under injection time is advantageous for ultimate recovery by waterfloods. Specific recommendations were presented for waterfloods in reservoirs with both high and low API gravity ranges. Each range showed a narrow sweet spot window where improved recovery occurred. 27 refs., 13 figs.

  3. Smart Waterflooding in Carbonate Reservoirs

    DEFF Research Database (Denmark)

    Zahid, Adeel

    During the last decade, smart waterflooding has been developed into an emerging EOR technology both for carbonate and sandstone reservoirs that does not require toxic or expensive chemicals. Although it is widely accepted that different salinity brines may increase the oil recovery for carbonate...... reservoirs, understanding of the mechanism of this increase is still developing. To understand this smart waterflooding process, an extensive research has been carried out covering a broad range of disciplines within surface chemistry, thermodynamics of crude oil and brine, as well as their behavior...

  4. A study of surfactant-assisted waterflooding

    Energy Technology Data Exchange (ETDEWEB)

    Scamehorn, J F; Harwell, J H

    1990-09-01

    In surfactant-assisted waterflooding, a surfactant slug is injected into a reservoir, followed by a brine spacer, followed by second surfactant slug. The charge on the surfactant in the first slug has opposite sign to that in the second slug. When the two slugs mix in the reservoir, a precipitate or coacervate is formed which plugs the permeable region of the reservoir. Subsequently injected water or brine is forced through the low permeability region of the reservoir, increasing sweep efficiency of the waterflood, compared to a waterflood not using surfactants. In this part of the work, two major tasks are performed. First, core floods are performed with oil present to demonstrate the improvement in incremental oil production, as well as permeability modification. Second, a reservoir simulation model will be proposed to further delineate the optimum strategy for implementation of the surfactant-assisted waterflooding, as well as indicate the reservoir types for which it would be most effective. Surfactants utilized were sodium dodecyl sulfate and dodecyl pyridinium chloride. 44 refs., 17 figs., 3 tabs.

  5. Financial methods for waterflooding injectate design

    Energy Technology Data Exchange (ETDEWEB)

    Heneman, Helmuth J.; Brady, Patrick V.

    2017-08-08

    A method of selecting an injectate for recovering liquid hydrocarbons from a reservoir includes designing a plurality of injectates, calculating a net present value of each injectate, and selecting a candidate injectate based on the net present value. For example, the candidate injectate may be selected to maximize the net present value of a waterflooding operation.

  6. Waterflooding optimization in uncertain geological scenarios

    DEFF Research Database (Denmark)

    Capolei, Andrea; Suwartadi, Eka; Foss, Bjarne;

    2013-01-01

    In conventional waterflooding of an oil field, feedback based optimal control technologies may enable higher oil recovery than with a conventional reactive strategy in which producers are closed based on water breakthrough. To compensate for the inherent geological uncertainties in an oil field, ...

  7. Modeling of Dissolution Effects on Waterflooding

    DEFF Research Database (Denmark)

    Alexeev, Artem; Shapiro, Alexander; Thomsen, Kaj

    2015-01-01

    Physico-chemical interactions between the fluid and reservoir rock due to the presence of active components in the injected brine produce changes within the reservoir and can significantly impact the fluid flow. We have developed a 1D numerical model for waterflooding accounting for dissolution...... and precipitation of the components. Extending previous studies, we consider an arbitrary chemical non-equilibrium reaction-induced dissolution. We account for different individual volumes that a component has when precipitated or dissolved. This volume non-additivity also affects the pressure and the flow rate...... reaction rates) may exhibit rapid increase of porosity and permeability near the inlet probably indicating a formation of high permeable channels (wormholes). Water saturation in the zone of dissolution increases due to an increase in the bulk volume accessible for the injected fluid. Volumetric non...

  8. Polymer Augmented Waterflood in the Rapdan Upper Shaunavon Unit

    Energy Technology Data Exchange (ETDEWEB)

    Campbell, T.A.; Bachman, R.C.

    1985-01-01

    A Polymer Augmented Waterflood Pilot is being implemented to test the tertiary recovery process in the Rapdan Upper Shaunavon Unit. Injection is to commence by late 1985. The Rapdan Unit has been under a peripheral waterflood since 1962. The performance of the waterflood has been characterized by early water breakthrough due in large part to an oil/water viscosity ratio of 20. This paper describes the studies undertaken to determine the feasibility and to design a polymerflood to improve oil recovery in the Unit. Laboratory work was done to select the most suitable polymer and to determine polymer adsorption, effective viscosity and incremental oil recovery. Field testing was conducted to determine polymer injectivity, adsorption and degradation. A reservoir simulator was used to optimize polymer concentration, slug size, well spacing and pattern type and to predict production and injection rates.

  9. Advanced waterflooding in chalk reservoirs: Understanding of underlying mechanisms

    DEFF Research Database (Denmark)

    Zahid, Adeel; Sandersen, Sara Bülow; Stenby, Erling Halfdan

    2011-01-01

    Over the last decade, a number of studies have shown SO42−, Ca2+ and Mg2+ to be potential determining ions, which may be added to the injected brine for improving oil recovery during waterflooding in chalk reservoirs. However the understanding of the mechanism leading to an increase in oil recove...... of a microemulsion phase could be the possible reasons for the observed increase in oil recovery with sulfate ions at high temperature in chalk reservoirs besides the mechanism of the rock wettability alteration, which has been reported in most previous studies.......Over the last decade, a number of studies have shown SO42−, Ca2+ and Mg2+ to be potential determining ions, which may be added to the injected brine for improving oil recovery during waterflooding in chalk reservoirs. However the understanding of the mechanism leading to an increase in oil recovery...

  10. PREFERRED WATERFLOOD MANAGEMENT PRACTICES FOR THE SPRABERRY TREND AREA

    Energy Technology Data Exchange (ETDEWEB)

    C. M. Sizemore; David S. Schechter

    2003-08-13

    This report describes the work performed during the second year of the project, ''Preferred Waterflood Management Practices for the Spraberry Trend Area''. The objective of this project is to significantly increase field-wide production in the Spraberry Trend in a short time frame through the application of preferred practices for managing and optimizing water injection. Our goal is to dispel negative attitudes and lack of confidence in water injection and to document the methodology and results for public dissemination to motivate waterflood expansion in the Spraberry Trend. To achieve this objective, in this period we concentrated our effort on characterization of Germania Unit using an analog field ET ODaniel unit and old cased hole neutron. Petrophysical Characterization of the Germania Spraberry units requires a unique approach for a number of reasons--limited core data, lack of modern log data and absence of directed studies within the unit. The need for characterization of the Germania unit has emerged as a first step in the review, understanding and enhancement of the production practices applicable within the unit and the trend area in general. In the absence or lack of the afore mentioned resources, an approach that will rely heavily on previous petrophysical work carried out in the neighboring ET O'Daniel unit (6.2 miles away), and normalization of the old log data prior to conventional interpretation techniques will be used. A log-based rock model has been able to guide successfully the prediction of pay and non-pay intervals within the ET O'Daniel unit, and will be useful if found applicable within the Germania unit. A novel multiple regression technique utilizing non-parametric transformations to achieve better correlations in predicting a dependent variable (permeability) from multiple independent variables (rock type, shale volume and porosity) will also be investigated in this study. A log data base includes digitized

  11. A New Comprehensive Approach for Predicting Injectivity Decline during Waterflooding

    DEFF Research Database (Denmark)

    Yuan, Hao; Nielsen, Sidsel Marie; Shapiro, Alexander

    Injectivity decline during sea waterflooding or produced water re-injection is widely observed in North Sea, Gulf of Mexico and Campos Basin fields. The formation damage occurs mainly due to the deposition of suspended solids around injectors and the build-up the external filter cakes in the well...... injectivity decline during water flooding is proposed. The deep bed filtration is described by novel stochastic random walk equations. The injectivity decline model takes into account the reservoir heterogeneity and the distribution of solid particles by sizes. It also accounts for the later formation...

  12. PREFERRED WATERFLOOD MANAGEMENT PRACTICES FOR THE SPRABERRY TREND AREA

    Energy Technology Data Exchange (ETDEWEB)

    David S. Schechter

    2004-08-31

    The naturally fractured Spraberry Trend Area is one of the largest reservoirs in the domestic U.S. and is the largest reservoir in area extent in the world. Production from Spraberry sands is found over a 2,500 sq. mile area and Spraberry reservoirs can be found in an eight county area in west Texas. Over 150 operators produce 65,000 barrels of oil per day (bopd) from the Spraberry Trend Area from more than 9,000 production wells. Recovery is poor, on the order of 7-10% due to the profoundly complicated nature of the reservoir, yet billions of barrels of hydrocarbons remain. We estimate over 15% of remaining reserves in domestic Class III reservoirs are in Spraberry Trend Area reservoirs. This tremendous domestic asset is a prime example of an endangered hydrocarbon resource in need of immediate technological advancements before thousands of wells are permanently abandoned. This report describes the final work of the project, ''Preferred Waterflood Management Practices for the Spraberry Trend Area.'' The objective of this project is to significantly increase field-wide production in the Spraberry Trend in a short time frame through the application of preferred practices for managing and optimizing water injection. Our goal is to dispel negative attitudes and lack of confidence in water injection and to document the methodology and results for public dissemination to motivate waterflood expansion in the Spraberry Trend. This objective has been accomplished through research in three areas: (1) detail historical review and extensive reservoir characterization, (2) production data management, and (3) field demonstration. This provides results of the final year of the three-year project for each of the three areas.

  13. Utilization of carbon dioxide for improving the performance of waterflooding in heavy oil recovery

    Science.gov (United States)

    Nasehi Araghi, Majid

    For several years, heavy oil reserves of Western Canada, which are amongst the largest in the world and total more than 5 billion m 3, have been under waterflooding and oil has been produced at very high water-oil-ratios. Despite its shortcomings, waterflooding has been employed because it is relatively a low cost process and is easier to operate compared to other techniques. In many cases waterflooding has been the only easy and low risk option due to the reservoir conditions which have made it impossible for any enhanced oil recovery techniques to be employed. Heavy oil waterflooding is always associated with low recoveries and poor efficiencies and therefore, there is a need for improving the performance of heavy oil waterflooding. Due to its favourable effects, CO2 injection has been accepted in the industry as an effective method of recovery for light to medium oils. But due to the immiscible nature of CO2 and heavy oil, CO 2 injection has not been looked at as a method of recovery improvement in heavy oil reserves of Western Canada. CO2 is highly soluble in both water and oil and therefore, it might be possible to improve the overall heavy oil waterflooding recoveries of these reserves by the utilization of CO2. This study consists of twelve core flood tests designed to investigate the effects of CO2 utilization on improving the performance of waterflooding in heavy oil recovery. Two injection methods are used; 1) injection of a slug of 10 to 25% pore volume of CO2 followed by a soak period and then waterflooding, and 2) injection of carbonated water which is prepared by dissolving CO2 in 1% wt. NaCl brine. Experiments were performed at temperatures of 30°C, and at pressures of 500 and 1000 psi. Water injection rates of 1 to 50 ft/day were used to recover heavy oils of 1000 to 2000 cp viscosities. The results show that, CO2 can be effectively used to make significant improvements in the overall recovery of heavy oil by waterflooding. Post CO2 waterfloodings

  14. The Status and Prospects of Enhancing Oil Recovery Technology for Waterflooding Oilfields in China

    Institute of Scientific and Technical Information of China (English)

    Shen Pingping; Yuan Shiyi

    1994-01-01

    @@ The water injection method has been used in most of oilfields in China even at the beginning of development, meanwhile the laboratory research on enhancing oil recovery (EOR) for these oilfields simultareously started too. Oilfields developed in 1960's have mostly been at a high watercut stage since 1990.Tasks in face of petroleum reservoir engineers are on the one hand, further improving recovery of waterflooding by integrated adjustments such as infill well drilling, water/oil ratio controlling, injection profile adjusting, etc. On the other hand, EOR techniques for waterflooding oilfields must be studied and applied to improve mostly the potential of underground resources and to increase recoverable reserves.

  15. Induced migration of fines during waterflooding in communicating layer-cake reservoirs

    DEFF Research Database (Denmark)

    Yuan, Hao; Shapiro, Alexander

    2011-01-01

    The effects of fines migration induced by injection of water with a different salinity than the reservoir brine are incorporated into the upscaling model for waterflooding in a layer cake reservoir with good communication between the layers. Mobilization and re-capturing of the reservoir fines ma...

  16. Effects of sonication radiation on oil recovery by ultrasonic waves stimulated water-flooding.

    Science.gov (United States)

    Mohammadian, Erfan; Junin, Radzuan; Rahmani, Omeid; Idris, Ahmad Kamal

    2013-02-01

    Due to partial understanding of mechanisms involved in application of ultrasonic waves as enhanced oil recovery method, series of straight (normal), and ultrasonic stimulated water-flooding experiments were conducted on a long unconsolidated sand pack using ultrasonic transducers. Kerosene, vaseline, and SAE-10 (engine oil) were used as non-wet phase in the system. In addition, a series of fluid flow and temperature rise experiments were conducted using ultrasonic bath in order to enhance the understanding about contributing mechanisms. 3-16% increase in the recovery of water-flooding was observed. Emulsification, viscosity reduction, and cavitation were identified as contributing mechanisms. The findings of this study are expected to increase the insight to involving mechanisms which lead to improving the recovery of oil as a result of application of ultrasound waves.

  17. Sensitivity analysis of dimensionless parameters for physical simulation of water-flooding reservoir

    Institute of Scientific and Technical Information of China (English)

    BAI Yuhu; LI Jiachun; ZHOU Jifu

    2005-01-01

    A numerical approach to optimize dimensionless parameters of water-flooding porous media flows is proposed based on the analysis of the sensitivity factor defined as the variation ration of a target function with respect to the variation of dimensionless parameters. A complete set of scaling criteria for water-flooding reservoir of five-spot well pattern case is derived from the 3-D governing equations, involving the gravitational force,the capillary force and the compressibility of water, oil and rock. By using this approach,we have estimated the influences of each dimensionless parameter on experimental results, and thus sorting out the dominant ones with larger sensitivity factors ranging from 10-4 to 100.

  18. 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.

  19. B-SPLINE-BASED SVM MODEL AND ITS APPLICATIONS TO OIL WATER-FLOODED STATUS IDENTIFICATION

    Institute of Scientific and Technical Information of China (English)

    Shang Fuhua; Zhao Tiejun; Yi Xiongying

    2007-01-01

    A method of B-spline transform for signal feature extraction is developed. With the B-spline,the log-signal space is mapped into the vector space. An efficient algorithm based on Support Vector Machine (SVM) to automatically identify the water-flooded status of oil-saturated stratum is described.The experiments show that this algorithm can improve the performances for the identification and the generalization in the case of a limited set of samples.

  20. Assessment of potential increased oil production by polymer-waterflood in northern and southern mid-continent oil fields. Progress report for the quarter ending December 31, 1978

    Energy Technology Data Exchange (ETDEWEB)

    None

    1978-01-01

    Six tasks are reported on: geological and engineering study of the DOE-Kewanee polymer-augmented waterflood, review of polymer injection program in this field, evaluation of results of polymer-augmented waterflood in this field, review of geological and engineering characteristics of oil fields now in waterflood as candidates for polymer augmentation, review of fields currently under primary production, and determination of ranges of future increased oil production from the polymer-water process in the project area.

  1. 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.

  2. 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.

  3. Waterflooding performance using Dykstra-Parsons as compared with numerical model performance

    Energy Technology Data Exchange (ETDEWEB)

    Mobarak, S.

    1975-01-01

    Multilayered models have been used by a number of investigators to represent heterogeneous reservoirs. The purpose of this note is to present waterflood performance for multilayered systems using the standard Dykstra-Parsons method as method as compared with that predicted by the modified form using equations given and those obtained by using a numerical model. The predicted oil recovery, using Johnson charts or the standard Dykstra-Parsons recovery modulus chart is always conservative, if not overly pessimistic. The modified Dykstra-Parsons method, as explained in the text, shows good agreement with the numerical model.

  4. Effect of Pore-Scale Heterogeneity and Capillary-Viscous Fingering on Commingled Waterflood Oil Recovery in Stratified Porous Media

    Directory of Open Access Journals (Sweden)

    Emad W. Al-Shalabi

    2016-01-01

    Full Text Available Oil recovery prediction and field pilot implements require basic understanding and estimation of displacement efficiency. Corefloods and glass micromodels are two of the commonly used experimental methods to achieve this. In this paper, waterflood recovery is investigated using layered etched glass micromodel and Berea sandstone core plugs with large permeability contrasts. This study focuses mainly on the effect of permeability (heterogeneity in stratified porous media with no cross-flow. Three experimental setups were designed to represent uniformly stratified oil reservoir with vertical discontinuity in permeability. Waterflood recovery to residual oil saturation (Sor is measured through glass micromodel (to aid visual observation, linear coreflood, and forced drainage-imbibition processes by ultracentrifuge. Six oil samples of low-to-medium viscosity and porous media of widely different permeability (darcy and millidarcy ranges were chosen for the study. The results showed that waterflood displacement efficiencies are consistent in both permeability ranges, namely, glass micromodel and Berea sandstone core plugs. Interestingly, the experimental results show that the low permeability zones resulted in higher ultimate oil recovery compared to high permeability zones. At Sor microheterogeneity and fingering are attributed for this phenomenon. In light of the findings, conformance control is discussed for better sweep efficiency. This paper may be of help to field operators to gain more insight into microheterogeneity and fingering phenomena and their impact on waterflood recovery estimation.

  5. A new approach of proration-injection allocation for water-flooding mature oilfields

    Directory of Open Access Journals (Sweden)

    Shuyong Hu

    2015-03-01

    Full Text Available This paper presents a new method of injection-production allocation estimation for water-flooding mature oilfields. The suggested approach is based on logistic growth rate functions and several type-curve matching methods. Using the relationship between these equations, oil production and water injection rate as well as injection-production ratio can be easily forecasted. The calculation procedure developed and outlined in this paper requires very few production data and is easily implemented. Furthermore, an oilfield case has been analyzed. The synthetic and field cases validate the calculation procedure, so it can be accurately used in forecasting production data, and it is important to optimize the whole injection-production system.

  6. Integrated Approach Towards the Application of Horizontal Wells to Improve Waterflooding Performance

    Energy Technology Data Exchange (ETDEWEB)

    Kelkar, Mohan; Liner, Chris; Kerr, Dennis

    1999-10-15

    This final report describes the progress during the six year of the project on ''Integrated Approach Towards the Application of Horizontal Wells to Improve Waterflooding Performance.'' This report is funded under the Department of Energy's (DOE's) Class I program which is targeted towards improving the reservoir performance of mature oil fields located in fluvially-dominated deltaic deposits. The project involves using an integrated approach to characterize the reservoir followed by drilling of horizontal injection wells to improve production performance. The project was divided into two budget periods. In the first budget period, many modern technologies were used to develop a detailed reservoir management plan; whereas, in the second budget period, conventional data was used to develop a reservoir management plan. The idea was to determine the cost effectiveness of various technologies in improving the performance of mature oil fields.

  7. Study about Interpretation Models and Algorithm of Water-Flooded Formation Based on Resistivity

    Institute of Scientific and Technical Information of China (English)

    WANGYinghui; TANDehui; WANGQiongfang; CAIHongjie

    2005-01-01

    Many oil fields are developed by water injection in the world, it's difficult to interpret by welllogging information. EPT and C/O identify residual oil saturation or moveable oil, but they are only fit for oil-reservoir with porosity over 20%, and not for borehole. Additionally, Archie model is not completely fit for dynamic but the static oil-reservoir. Therefore, it's more difficult for WF (Water-flooded) oil-zone (dynamic oil-reservoir) with LPP (Low porosity and low permeability) to be interpreted. Resistivity logging series are the dominating tools to WF formation, so it becomes significantly important to research new interpretation models and algorithm based on resistivity well-logging for WF oil-zone with LPP. A set of new interpretation models for WFZ (Water flooded zone) are established according to the “U” type curve from experimentation, as well as according to mathematics analysis. The notable Archie model is only one case of these new models under special conditions. It is most important that these new models are all fit from exploration stage to development stage in oil field. At last, algorithm process and application result of these models are described.

  8. Integrated approach towards the application of horizontal wells to improve waterflooding performance. 1995 annual report

    Energy Technology Data Exchange (ETDEWEB)

    Kelkar, M.; Liner, C.; Kerr, D.

    1996-06-01

    This annual report describes the progress during the third year of the project on Integrated Approach Towards the Application of Horizontal Wells to Improve Waterflooding Performance. This project is funded under the Department of Energy`s Class I program which is targeted towards improving the reservoir performance of mature oil fields located in fluvially dominated deltaic geological environments. The project involves using an integrated approach to characterize the reservoir followed by proposing an appropriate reservoir management strategy to improve the field performance. In the first stage of the project, the type of data we integrated include cross borehole seismic surveys, geological interpretation based on the logs and the cores, and the engineering information. In contrast, during the second stage of the project, we intend to use only conventional data to construct the reservoir description. This report covers the results of the implementation from the first stage of the project. It also discusses the work accomplished so far for the second stage of the project. The preliminary results look promising from the field implementation. The production from the Self Unit (location of Stage I) has increased by 35 bbls/day with additional increase anticipated with further implementation. Based on our understanding of the first stage, we hope to examine a greater area of the Glenn Pool field for additional increase in production. We have collected available core and log data and have finished the initial geological description. Although not a direct part of this project, we also have initiated a 3-D seismic survey of the area which should help us in improving the reservoir description.

  9. Study and application on the evaluation method of porous formation for long-term waterflooding sand reservoir

    Institute of Scientific and Technical Information of China (English)

    Wang Changjiang; Jiang Hanqiao; Chen Minfeng; Geng Zhanli; Liu Pengfei

    2009-01-01

    Nine targets which stand both for the static characteristic of produced formations and the dynamic parameter of wells including the average permeability, variation coefficient of permeability, moving capability, remaining recoverable reserves, coefficient of flooding, daily oil production, increasing rate of water cut, cumulative liquid production per unit meter and efficiency index of oil production are selected as the evaluation indexes, a novel model to evaluate the porous formations in long-term waterflooding sand reservoir was established by using the support vector machine and clustering analysis. Data of 57 wefts from Shentuo 21 block Shengli oilfield was analyzed by using the model. Four kinds of forma-tion groups were gained. According to the analysis result, different adjustment solutions were put forward to develop the relevant formations. The Monthly oil production increased 7.6 % and the water cut decreased 8.9 % after the adjusted solutions. Good results indicate that the learning from this method gained will be valuable adding to other long-term wa-terflooding sand reservoirs in Shengli oilfield and other similar reservoirs worldwide.

  10. 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.

  11. Assessment of potential increased oil production by polymer-waterflood in northern and southern mid-continent oil fields. Progress report for the quarter ending September 30, 1978

    Energy Technology Data Exchange (ETDEWEB)

    1978-10-15

    Activities in programs to conduct polymer-waterflood studies are reported. During the period a study was conducted of the Burbank-Bartlesville sand reservoir, located in the north half of the Stanley Stringer Field, Osage County, Oklahoma. Progress in the overall program is summarized in a chart. (JRD)

  12. Theoretical eduction and numerical simulation researches on the relationship between resistivity and water saturation of waterflood oil zone

    Institute of Scientific and Technical Information of China (English)

    2009-01-01

    In the process of water displacing oil,the relationship between resistivity and water saturation is the fundament of the quantitative research on the waterflooded grade and the remaining oil saturation with well logging data. A large number of core analysis data and production data are cumulated in the process of oil field exploitation,which offers the basis for the above research. This paper educed two methods from the Archie equation and material balance theory to calculate the quantitative relationships between Rz and Sw,and between Rt and Sw. The relationships set up by the two methods are similar to those set up by the real core measurements. The results can be used to analyze influencing factors and determine saturation quantitatively.

  13. Caustic waterflooding demonstration project: Ranger Zone, Long Beach Unit, Wilmington Field, California. Third annual report, June 1978-May 1979

    Energy Technology Data Exchange (ETDEWEB)

    Mayer, E.H.

    1979-12-01

    A caustic-enhanced waterflooding pilot test is being conducted in the Ranger Reservoir of the Long Beach Unit, Wilmington Field, California. Evaluation of entrapment and entrainment caustic flooding in Ranger Zone cores was continued. The caustic-only (entrapment) core floods failed to demonstrate improved behavior. Based on the unfavorable results of all tests of the entrapment mechanism, further laboratory work and flooding in the pilot with caustic alone have been eliminated from the project's plans. Some of the year's caustic-salt (entrainment) core floods in contrast showed both substantial recovery and WOR improvement. The poorer overall entrainment core flood results obtained in the year may be due to the core material, a smaller preflush volume used or the crude oil employed. Core flood testing where sodium silicate is substituted for some of the sodium hydroxide, was continued. The primary set of caustic water-oil dehydration tests was completed. The test softening of produced waters was completed and the results evaluated; produced water softening was found to be an economically feasible alternative to the use of fresh water. The preflush injection facilities became operational in January 1979 with the pilot's preflush officially begun April 15, 1979. The alkaline injection facility was expanded in scope to permit use of both sodium silicate and sodium hydroxide; its completion in late 1979 is anticipated with the alkaline-salt injection scheduled to begin at that time. The base case reservoir simulator prediction of the pilot under continued waterflooding was completed. This prediction provided the base line from which incremental alkaline flood production will be determined, as the test has now been declared a qualified tertiary enhanced recovery project by DOE's Economic Regulatory Administration. Major well repair/redrill work continued to be necessary exceeding earlier increased cost estimates.

  14. Geoscience/engineering characterization of the interwell environment in carbonate reservoirs based on outcrop analogs, Permian Basin, West Texas and New Mexico--waterflood performance analysis for the South Cowden Grayburg Reservoir, Ector County, Texas. Final report

    Energy Technology Data Exchange (ETDEWEB)

    Jennings, J.W. Jr.

    1997-05-01

    A reservoir engineering study was conducted of waterflood performance in the South Cowden field, an Upper Permian Grayburg reservoir on the Central Basin Platform in West Texas. The study was undertaken to understand the historically poor waterflood performance, evaluate three techniques for incorporating petrophysical measurements and geological interpretation into heterogeneous reservoir models, and identify issues in heterogeneity modeling and fluid-flow scaleup that require further research. The approach included analysis of relative permeability data, analysis of injection and production data, heterogeneity modeling, and waterflood simulation. The poor South Cowden waterflood recovery is due, in part, to completion of wells in only the top half of the formation. Recompletion of wells through the entire formation is estimated to improve recovery in ten years by 6 percent of the original oil in place in some areas of the field. A direct three-dimensional stochastic approach to heterogeneity modeling produced the best fit to waterflood performance and injectivity, but a more conventional model based on smooth mapping of layer-averaged properties was almost as good. The results reaffirm the importance of large-scale heterogeneities in waterflood modeling but demonstrate only a slight advantage for stochastic modeling at this scale. All the flow simulations required a reduction to the measured whole-core k{sub v}/k{sub h} to explain waterflood behavior, suggesting the presence of barriers to vertical flow not explicitly accounted for in any of the heterogeneity models. They also required modifications to the measured steady-state relative permeabilities, suggesting the importance of small-scale heterogeneities and scaleup. Vertical flow barriers, small-scale heterogeneity modeling, and relative permeability scaleup require additional research for waterflood performance prediction in reservoirs like South Cowden.

  15. Design and Implementation of a CO2 Flood Utilizing Advanced Reservoir Characterization and Horizontal Injection Wells In a Shallow Shelf Carbonate Approaching Waterflood Depletion, Class II

    Energy Technology Data Exchange (ETDEWEB)

    Wier, Don R. Chimanhusky, John S.; Czirr, Kirk L.; Hallenbeck, Larry; Gerard, Matthew G.; Dollens, Kim B.; Owen, Rex; Gaddis, Maurice; Moshell, M.K.

    2002-11-18

    The purpose of this project was to economically design an optimum carbon dioxide (CO2) flood for a mature waterflood nearing its economic abandonment. The original project utilized advanced reservoir characterization and CO2 horizontal injection wells as the primary methods to redevelop the South Cowden Unit (SCU). The development plans; project implementation and reservoir management techniques were to be transferred to the public domain to assist in preventing premature abandonment of similar fields.

  16. Zeta potential in oil-water-carbonate systems and its impact on oil recovery during controlled salinity water-flooding

    Science.gov (United States)

    Jackson, Matthew D.; Al-Mahrouqi, Dawoud; Vinogradov, Jan

    2016-11-01

    Laboratory experiments and field trials have shown that oil recovery from carbonate reservoirs can be increased by modifying the brine composition injected during recovery in a process termed controlled salinity water-flooding (CSW). However, CSW remains poorly understood and there is no method to predict the optimum CSW composition. This work demonstrates for the first time that improved oil recovery (IOR) during CSW is strongly correlated to changes in zeta potential at both the mineral-water and oil-water interfaces. We report experiments in which IOR during CSW occurs only when the change in brine composition induces a repulsive electrostatic force between the oil-brine and mineral-brine interfaces. The polarity of the zeta potential at both interfaces must be determined when designing the optimum CSW composition. A new experimental method is presented that allows this. Results also show for the first time that the zeta potential at the oil-water interface may be positive at conditions relevant to carbonate reservoirs. A key challenge for any model of CSW is to explain why IOR is not always observed. Here we suggest that failures using the conventional (dilution) approach to CSW may have been caused by a positively charged oil-water interface that had not been identified.

  17. Simulating secondary waterflooding in heterogeneous rocks with variable wettability using an image-based, multiscale pore network model

    Science.gov (United States)

    Bultreys, Tom; Van Hoorebeke, Luc; Cnudde, Veerle

    2016-09-01

    The two-phase flow properties of natural rocks depend strongly on their pore structure and wettability, both of which are often heterogeneous throughout the rock. To better understand and predict these properties, image-based models are being developed. Resulting simulations are however problematic in several important classes of rocks with broad pore-size distributions. We present a new multiscale pore network model to simulate secondary waterflooding in these rocks, which may undergo wettability alteration after primary drainage. This novel approach permits to include the effect of microporosity on the imbibition sequence without the need to describe each individual micropore. Instead, we show that fluid transport through unresolved pores can be taken into account in an upscaled fashion, by the inclusion of symbolic links between macropores, resulting in strongly decreased computational demands. Rules to describe the behavior of these links in the quasistatic invasion sequence are derived from percolation theory. The model is validated by comparison to a fully detailed network representation, which takes each separate micropore into account. Strongly and weakly water-and oil-wet simulations show good results, as do mixed-wettability scenarios with different pore-scale wettability distributions. We also show simulations on a network extracted from a micro-CT scan of Estaillades limestone, which yields good agreement with water-wet and mixed-wet experimental results.

  18. Using laboratory flow experiments and reactive chemical transport modeling for designing waterflooding of the Agua Fria Reservoir, Poza Rica-Altamira Field, Mexico

    Energy Technology Data Exchange (ETDEWEB)

    Birkle, P.; Pruess, K.; Xu, T.; Figueroa, R.A. Hernandez; Lopez, M. Diaz; Lopez, E. Contreras

    2008-10-01

    Waterflooding for enhanced oil recovery requires that injected waters must be chemically compatible with connate reservoir waters, in order to avoid mineral dissolution-and-precipitation cycles that could seriously degrade formation permeability and injectivity. Formation plugging is a concern especially in reservoirs with a large content of carbonates, such as calcite and dolomite, as such minerals typically react rapidly with an aqueous phase, and have strongly temperature-dependent solubility. Clay swelling can also pose problems. During a preliminary waterflooding pilot project, the Poza Rica-Altamira oil field, bordering the Gulf coast in the eastern part of Mexico, experienced injectivity loss after five months of reinjection of formation waters into well AF-847 in 1999. Acidizing with HCl restored injectivity. We report on laboratory experiments and reactive chemistry modeling studies that were undertaken in preparation for long-term waterflooding at Agua Frma. Using analogous core plugs obtained from the same reservoir interval, laboratory coreflood experiments were conducted to examine sensitivity of mineral dissolution and precipitation effects to water composition. Native reservoir water, chemically altered waters, and distilled water were used, and temporal changes in core permeability, mineral abundances and aqueous concentrations of solutes were monitored. The experiments were simulated with the multi-phase, nonisothermal reactive transport code TOUGHREACT, and reasonable to good agreement was obtained for changes in solute concentrations. Clay swelling caused an additional impact on permeability behavior during coreflood experiments, whereas the modeled permeability depends exclusively on chemical processes. TOUGHREACT was then used for reservoir-scale simulation of injecting ambient-temperature water (30 C, 86 F) into a reservoir with initial temperature of 80 C (176 F). Untreated native reservoir water was found to cause serious porosity and

  19. The Utilization of the Microflora Indigenous to and Present in Oil-Bearing Formations to Selectively Plug the More Porous Zones Thereby Increasing Oil Recovery During Waterflooding

    Energy Technology Data Exchange (ETDEWEB)

    Brown, Lewis R.; Stephens, James O.; Vadie, Alex A.

    1999-11-03

    The objective of this work is to demonstrate the use of indigenous microbes as a method of profile control in waterfloods. It is expected that as the microbial population is induced to increase, that the expanded biomass will selectively block the more permeable zones of the reservoir thereby forcing injection water to flow through the less permeable zones which will result in improved sweep efficiency. This increase in microbial population will be accomplished by injecting a nutrient solution into four injectors. Four other injectors will act as control wells. During Phase I, two wells will be cored through the zone of interest. The core will be subjected to special core analyses in order to arrive at the optimum nutrient formulation. During Phase II, nutrient injection will begin, the results monitored, and adjustments to the nutrient composition made, if necessary. Phase II also will include the drilling of three wells for post-mortem core analysis. Phase III will focus on technology transfer of the results. It should be pointed out that one expected outcome of this new technology will be a prolongation of economical waterflooding operations, i.e. economical oil recovery should continue for much longer periods in the producing wells subjected to this selective plugging technique.

  20. 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.

  1. 陕北LFP油田注水开发效果分析%Waterflooding effect analysis of the LFP oilfield in the northern part of Shaanxi

    Institute of Scientific and Technical Information of China (English)

    洪荆晶; 邓媛; 王海军; 吴汉宁

    2011-01-01

    The LFP oilfield in the Ordos basin is rich in oil and gas,under the premise of low porosity and low permeability reservoir,waterflooding technique has adopted to improve the extraction percentage.We analyze waterflooding technique applications and effects in the main layers of this field,meanwhile,make contrastive analysis between exploration achievements and exploitation materials to Chang1 layer,thus to put forward corresponding suggestions of these layers to improve the extraction percentage in this oil field.This article is an exploration for comprehensive analysis by combinating exploration achievements and exploitation materials.%鄂尔多斯盆地LFP区块中生代油藏油气资源较丰富,在低孔、低渗的前提下为提高采收率采用了注水开发技术。本文对该区各主要层段的注水开发应用状态及效果进行了分析,同时从勘探成果与开发资料进行对比分析的角度针对各层的特点提出了相应的调整建议。本文是用勘探与开发资料进行综合分析的一个探索。

  2. Well logging evaluation of water-flooded layers and distribution rule of remaining oil in marine sandstone reservoirs of the M oilfield in the Pearl River Mouth basin

    Science.gov (United States)

    Li, Xiongyan; Qin, Ruibao; Gao, Yunfeng; Fan, Hongjun

    2017-03-01

    In the marine sandstone reservoirs of the M oilfield the water cut is up to 98%, while the recovery factor is only 35%. Additionally, the distribution of the remaining oil is very scattered. In order to effectively assess the potential of the remaining oil, the logging evaluation of the water-flooded layers and the distribution rule of the remaining oil are studied. Based on the log response characteristics, the water-flooded layers can be qualitatively identified. On the basis of the mercury injection experimental data of the evaluation wells, the calculation model of the initial oil saturation is built. Based on conventional logging data, the evaluation model of oil saturation is established. The difference between the initial oil saturation and the residual oil saturation can be used to quantitatively evaluate the water-flooded layers. The evaluation result of the water-flooded layers is combined with the ratio of the water-flooded wells in the marine sandstone reservoirs. As a result, the degree of water flooding in the marine sandstone reservoirs can be assessed. On the basis of structural characteristics and sedimentary environments, the horizontal and vertical water-flooding rules of the different types of reservoirs are elaborated upon, and the distribution rule of the remaining oil is disclosed. The remaining oil is mainly distributed in the high parts of the structure. The remaining oil exists in the top of the reservoirs with good physical properties while the thickness of the remaining oil ranges from 2–5 m. However, the thickness of the remaining oil of the reservoirs with poor physical properties ranges from 5–8 m. The high production of some of the drilled horizontal wells shows that the above distribution rule of the remaining oil is accurate. In the marine sandstone reservoirs of the M oilfield, the research on the well logging evaluation of the water-flooded layers and the distribution rule of the remaining oil has great practical significance

  3. Alkaline Waterflooding Demonstration Project, Ranger Zone, Long Beach Unit, Wilmington Field, California. Fourth annual report, June 1979-May 1980. Volume 3. Appendices II-XVII

    Energy Technology Data Exchange (ETDEWEB)

    Carmichael, J.D.

    1981-03-01

    Volume 3 contains Appendices II through XVII: mixing instructions for sodium orthosilicate; oil displacement studies using THUMS C-331 crude oil and extracted reservoir core material from well B-110; clay mineral analysis of B-827-A cores; sieve analysis of 4 Fo sand samples from B-110-IA and 4 Fo sand samples from B-827-A; core record; delayed secondary caustic consumption tests; long-term alkaline consumption in reservoir sands; demulsification study for THUMS Long Beach Company, Island White; operating plans and instructions for DOE injection demonstration project, alkaline injection; caustic pilot-produced water test graphs; well test irregularities (6/1/79-5/31/80); alkaline flood pump changes (6/1/79-5/31/80); monthly DOE pilot chemical waterflood injection reports (preflush injection, alkaline-salt injection, and alkaline injection without salt); and caustic safety procedures-alkaline chemicals.

  4. Pilot demonstration of enhanced oil recovery by micellar polymer waterflooding: phase A. Quarterly report for the 1st quarter 1977. [Wilmington oil field, California

    Energy Technology Data Exchange (ETDEWEB)

    Wade, J.E.; Staub, H.L.

    1977-04-15

    A micellar-polymer tertiary waterflood project is underway in the HXa sand, Fault Block VB, Wilmington Oil Field. All tasks in Phase A, with the exception of Task No. 5, have been successfully finalized. Because Task No. 5, sulfonation of a Wilmington crude feedstock, was an integral part of the subjects to be resolved under Phase A, Decision Point No. 1 must be delayed several months. Marathon was unable to schedule sulfonation of Wilmington feedstocks but is now conducting bench sulfonation of Wilmington feedstocks and has called upon Witco and Stepan to prepare Wilmington sulfonates in their pilot plants. Flood tests and polymer adsorbtion-degradation tests were performed on old core material from the Upper Terminal sand need to be repeated on fresh core samples from the well to be drilled for the mini-injectivity test. (DLC)

  5. 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

  6. 濮城油田水淹层饱和度计算参数研究%On Water-flooded Layer Saturation Calculating Parameter in Pucheng Oilfield

    Institute of Scientific and Technical Information of China (English)

    申梅英; 谭海芳

    2013-01-01

    为计算濮城油田水淹层的剩余油饱和度,对其主要水淹层段各项测井资料进行了分析研究.在利用自然伽马测井资料确定自然电位扩散吸附系数,应用RFT压力资料计算过滤电位的基础上,利用常规测井资料建立了濮城油田水淹层混合地层水电阻率计算模型,确定了合理的参数.实验分析表明,在濮城油田水淹层矿化度较高的情况下,计算水淹层剩余油饱和度所需的胶结指数m、饱和度指数n参数基本稳定.水驱油对储层的物性有小幅度改善,继续使用阿尔奇公式计算饱和度是可行的.依据该方法对岩心资料计算出的含水饱和度与岩心分析数据十分接近,说明该方法选取的参数符合地层实际情况.%To accurately calculate the residual-oil saturation of Pucheng oilfield, we research and analyze the log data of its main water-flooded zones. GR well log data is used to calculate SP diffusion coefficient, and filtration potential is determined by RFT log data. We establish the calculating models of mixed water resistivity using conventional logging data, and determine the reasonable model parameters. Experimental analyzes indicate that in the high salinity water-flooded layer of Pucheng oilfield, the cementation factor m and saturation exponent n are basically stable which is essential in calculating residual-oil saturation. Displacement of oil by water could improve reservoir physical properties in a small extent. It is feasible to calculate saturation with Archie equation as before. The result using this method to calculate saturation of core data is close to the core analysis data. It is proved that the chosen parameters in this method are fit to the Pucheng oilfield reservoir practical situation.

  7. Comparison of Microbial Community Compositions of Injection and Production Well Samples in a Long-Term Water-Flooded Petroleum Reservoir

    Science.gov (United States)

    Ren, Hong-Yan; Zhang, Xiao-Jun; Song, Zhi-yong; Rupert, Wieger; Gao, Guang-Jun; Guo, Sheng-xue; Zhao, Li-Ping

    2011-01-01

    Water flooding plays an important role in recovering oil from depleted petroleum reservoirs. Exactly how the microbial communities of production wells are affected by microorganisms introduced with injected water has previously not been adequately studied. Using denaturing gradient gel electrophoresis (DGGE) approach and 16S rRNA gene clone library analysis, the comparison of microbial communities is carried out between one injection water and two production waters collected from a working block of the water-flooded Gudao petroleum reservoir located in the Yellow River Delta. DGGE fingerprints showed that the similarities of the bacterial communities between the injection water and production waters were lower than between the two production waters. It was also observed that the archaeal composition among these three samples showed no significant difference. Analysis of the 16S rRNA gene clone libraries showed that the dominant groups within the injection water were Betaproteobacteria, Gammaproteobacteria and Methanomicrobia, while the dominant groups in the production waters were Gammaproteobacteria and Methanobacteria. Only 2 out of 54 bacterial operational taxonomic units (OTUs) and 5 out of 17 archaeal OTUs in the injection water were detected in the production waters, indicating that most of the microorganisms introduced by the injection water may not survive to be detected in the production waters. Additionally, there were 55.6% and 82.6% unique OTUs in the two production waters respectively, suggesting that each production well has its specific microbial composition, despite both wells being flooded with the same injection water. PMID:21858049

  8. Comparison of microbial community compositions of injection and production well samples in a long-term water-flooded petroleum reservoir.

    Science.gov (United States)

    Ren, Hong-Yan; Zhang, Xiao-Jun; Song, Zhi-yong; Rupert, Wieger; Gao, Guang-Jun; Guo, Sheng-xue; Zhao, Li-Ping

    2011-01-01

    Water flooding plays an important role in recovering oil from depleted petroleum reservoirs. Exactly how the microbial communities of production wells are affected by microorganisms introduced with injected water has previously not been adequately studied. Using denaturing gradient gel electrophoresis (DGGE) approach and 16S rRNA gene clone library analysis, the comparison of microbial communities is carried out between one injection water and two production waters collected from a working block of the water-flooded Gudao petroleum reservoir located in the Yellow River Delta. DGGE fingerprints showed that the similarities of the bacterial communities between the injection water and production waters were lower than between the two production waters. It was also observed that the archaeal composition among these three samples showed no significant difference. Analysis of the 16S rRNA gene clone libraries showed that the dominant groups within the injection water were Betaproteobacteria, Gammaproteobacteria and Methanomicrobia, while the dominant groups in the production waters were Gammaproteobacteria and Methanobacteria. Only 2 out of 54 bacterial operational taxonomic units (OTUs) and 5 out of 17 archaeal OTUs in the injection water were detected in the production waters, indicating that most of the microorganisms introduced by the injection water may not survive to be detected in the production waters. Additionally, there were 55.6% and 82.6% unique OTUs in the two production waters respectively, suggesting that each production well has its specific microbial composition, despite both wells being flooded with the same injection water.

  9. Integrated approach towards the application of horizontal wells to improve waterflooding performance. Annual progress report, January 1, 1996--December 31, 1996

    Energy Technology Data Exchange (ETDEWEB)

    Kelkar, M.; Liner, C.; Kerr, D.

    1997-01-01

    This annual report describes the progress during the fourth year of the project on {open_quotes}Integrated Approach Towards the Application of Horizontal Wells to Improve Waterflooding Performance{close_quotes}. The project involves using an integrated approach to characterize the reservoir followed by proposing an appropriate reservoir management strategy to improve the field performance. In the first stage of the project, the type of data we integrated include cross borehole seismic surveys, geological interpretation based on the logs and the cores, and the engineering information. In contrast, during the second stage of the project, we intend to use only conventional data to construct the reservoir description. This report covers the results of the implementation from the first stage of the project. It also discusses the work accomplished so far for the second stage of the project. The production from the Self Unit (location of Stage 1) has sustained an increase of 30 bbls/day over a year with an additional increase anticipated with further implementation. We have collected available core, log and production data from Section 16 in the Berryhill Glenn Unit and have finished the geological description. Based on the geological description and the associated petrophysical properties, we have developed a new indexing procedure for identifying the areas with the most potential. We are also investigating an adjoining tract formerly operated by Chevron where successful miceller-polymer flood was conducted. This will help us in evaluating the reasons for the success of the flood. Armed with this information, we will conduct a detailed geostatistical and flow simulation study and recommend the best reservoir management plan to improve the recovery of the field.

  10. The utilization of the microflora indigenous to and present in oil-bearing formations to selectively plug the more porous zones thereby increasing oil recovery during waterflooding. Annual report for the period, January 1, 1994--December 31, 1994

    Energy Technology Data Exchange (ETDEWEB)

    Brown, L.; Vadie, A.

    1995-08-01

    This project is a field demonstration of the ability of insitu indigenous microorganisms in the North Blowhorn Creek Oil Field to reduce the flow of injection water in the more permeable zones thereby diverting flow to other areas of the reservoir and thus increase the efficiency of the waterflooding operation. This effect is to be accomplished by adding inorganic nutrients in the form of Potassium nitrate and orthophosphate, to the injection water. In Phase I, which has been completed, the following results were obtained. Two new wells were drilled in the field and live cores were recovered. Analyses of the cores proved that viable microorganisms were present and since no sulfate-reducing bacteria (SRB) were found, the area in which the wells were drilled, probably had not been impacted by injection water, since SRB were prevalent in fluids from most wells in the field. Laboratory waterflooding tests using live cores demonstrated that the rate of flow Of simulated production water through the core increased with time when used alone while the rate of flow decreased when nitrate and phosphate salts were added to the simulated production water. Since there is only a small amount of pressure on the influent, the simulated production water was not forced to sweep other areas of the core. The field demonstration (Phase II) involves adding nutrients to four injector wells and monitoring the surrounding producers. The exact kind and amounts of nutrients to be employed and the schedule for their injection were formulated on the basis of information obtained in the laboratory waterflooding tests conducted using the live cores from the field. Results obtained in these tests will not only be compared to historical data for the wells but also to four injectors and their corresponding producers (control) which were chosen for their similarity to the four test patterns.

  11. Design and implementation of a CO{sub 2} flood utilizing advanced reservoir characterization and horizontal injection wells in a shallow shelf carbonate approaching waterflood depletion. Quarterly report, April 1, 1995--June 30, 1995

    Energy Technology Data Exchange (ETDEWEB)

    Wier, D.R.

    1995-09-01

    The first objective is to utilize reservoir characterization and advanced technologies to optimize the design of a CO{sub 2} project for the South Cowden Unit (SCU) located in Ector County, Texas. The SCU is a mature, relatively small, shallow shelf carbonate unit nearing waterflood depletion. The second objective is to demonstrate the performance and economic viability of the project in the field. The work reported here is on the reservoir characterization and project design objective. This objective is scheduled to be completed in early 1996 at which time work on the field demonstration phase is scheduled to begin.

  12. The utilization of the microflora indigenous to and present in oil-bearing formations to selectively plug the more porous zones thereby increasing oil recovery during waterflooding. Annual report, January 1, 1996--December 30, 1996

    Energy Technology Data Exchange (ETDEWEB)

    Brown, L.R.; Vadie, A.A.

    1997-08-01

    This project is a field demonstration of the ability of in-situ indigenous microorganisms in the North Blowhorn Creek Oil Field to reduce the flow of injection water in the more permeable zones thereby diverting flow to other areas of the reservoir and thus increase the efficiency of the waterflooding operation. This effect is to be accomplished by adding microbial nutrients to the injection water. Work on the project is divided into three phases, Planning and Analysis (9 months), Implementation (45 months), and Technology Transfer (12 months). This report covers the third year of work on the project. During Phase I, two wells were drilled in an area of the field where approximately twenty feet of Carter sand were found and appeared to contain oil bypassed by the existing waterflood. Cores from one well were obtained and used in laboratory core flood experiments. The schedule and amounts of nutrients to be employed in the field were formulated on the basis of the results from laboratory core flood experiments.

  13. DESIGN AND IMPLEMENTATION OF A CO2 FLOOD UTILIZING ADVANCED RESERVOIR CHARACTERIZATION AND HORIZONTAL INJECTION WELLS IN A SHALLOW SHELF CARBONATE APPROACHING WATERFLOOD DEPLETION

    Energy Technology Data Exchange (ETDEWEB)

    K.J. Harpole; Ed G. Durrett; Susan Snow; J.S. Bles; Carlon Robertson; C.D. Caldwell; D.J. Harms; R.L. King; B.A. Baldwin; D. Wegener; M. Navarrette

    2002-09-01

    The purpose of this project was to economically design an optimum carbon dioxide (CO{sub 2}) flood for a mature waterflood nearing its economic abandonment. The original project utilized advanced reservoir characterization and CO{sub 2} horizontal injection wells as the primary methods to redevelop the South Cowden Unit (SCU). The development plans; project implementation and reservoir management techniques were to be transferred to the public domain to assist in preventing premature abandonment of similar fields. The Unit was a mature waterflood with water cut exceeding 95%. Oil must be mobilized through the use of a miscible or near-miscible fluid to recover significant additional reserves. Also, because the unit was relatively small, it did not have the benefit of economies of scale inherent in normal larger scale projects. Thus, new and innovative methods were required to reduce investment and operating costs. Two primary methods used to accomplish improved economics were use of reservoir characterization to restrict the flood to the higher quality rock in the unit and use of horizontal injection wells to cut investment and operating costs. The project consisted of two budget phases. Budget Phase I started in June 1994 and ended late June 1996. In this phase Reservoir Analysis, Characterization Tasks and Advanced Technology Definition Tasks were completed. Completion enabled the project to be designed, evaluated, and an Authority for Expenditure (AFE) for project implementation submitted to working interest owners for approval. Budget Phase II consisted of the implementation and execution of the project in the field. Phase II was completed in July 2001. Performance monitoring, during Phase II, by mid 1998 identified the majority of producing wells which under performed their anticipated withdrawal rates. Newly drilled and re-activated wells had lower offtake rates than originally forecasted. As a result of poor offtake, higher reservoir pressure was a concern

  14. 坪北油田特低渗透油藏超前注水探索与实践%Exploration and Practice of Advanced Waterflooding in Ultra-Low-Permeability Reservoirs of Pingbei Oilfield

    Institute of Scientific and Technical Information of China (English)

    张丽媛; 朱党辉; 祝俊山

    2012-01-01

    As an important technique for enhancing recovery ratio of low-permeability oilfield,advanced waterflooding has been widely applied to many oilfields in China and has achieved a good development effect.To increase proven deposits recovery and development effect in low-permeability oilfield,this paper,with the help of development experiences abroad and at home as well as from neighbor oilfields,explores reasonable technical parameters for advanced waterflooding favorable to geological features of Pingbei Oilfield and builds displacement pressure system to decrease damage on the stratum caused by start-up pressure gradient and medium deformation.In practice,it suggests using advanced waterflooding to keep desirable strata pressure,lessen the damage on reservoir permeability,lower water content and decline rate in oil production and improve ultimate recovery.%超前注水作为特低渗透油田提高采收率的一种重要的技术方法,在我国很多油田得到广泛的应用,并且都获得了良好的开发效果。为了提高特低渗透油田探明储量的采收率和开发效果,根据坪北油田的地质特点,借鉴国内外油田及邻近油田的开发经验,探索适合油田超前注水的合理技术参数,建立有效的驱替压力系统,在一定程度上减小启动压力梯度和介质变形对地层的伤害。利用超前注水保持合理的地层压力,降低对储层渗透率的伤害,降低油井投产后的含水率和递减率,提高最终采收率。

  15. Characterization and Alteration of Wettability States of Alaskan Reserviors to Improve Oil Recovery Efficiency (including the within-scope expansion based on Cyclic Water Injection - a pulsed waterflood for Enhanced Oil Recovery)

    Energy Technology Data Exchange (ETDEWEB)

    Abhijit Dandekar; Shirish Patil; Santanu Khataniar

    2008-12-31

    Numerous early reports on experimental works relating to the role of wettability in various aspects of oil recovery have been published. Early examples of laboratory waterfloods show oil recovery increasing with increasing water-wetness. This result is consistent with the intuitive notion that strong wetting preference of the rock for water and associated strong capillary-imbibition forces gives the most efficient oil displacement. This report examines the effect of wettability on waterflooding and gasflooding processes respectively. Waterflood oil recoveries were examined for the dual cases of uniform and non-uniform wetting conditions. Based on the results of the literature review on effect of wettability and oil recovery, coreflooding experiments were designed to examine the effect of changing water chemistry (salinity) on residual oil saturation. Numerous corefloods were conducted on reservoir rock material from representative formations on the Alaska North Slope (ANS). The corefloods consisted of injecting water (reservoir water and ultra low-salinity ANS lake water) of different salinities in secondary as well as tertiary mode. Additionally, complete reservoir condition corefloods were also conducted using live oil. In all the tests, wettability indices, residual oil saturation, and oil recovery were measured. All results consistently lead to one conclusion; that is, a decrease in injection water salinity causes a reduction in residual oil saturation and a slight increase in water-wetness, both of which are comparable with literature observations. These observations have an intuitive appeal in that water easily imbibes into the core and displaces oil. Therefore, low-salinity waterfloods have the potential for improved oil recovery in the secondary recovery process, and ultra low-salinity ANS lake water is an attractive source of injection water or a source for diluting the high-salinity reservoir water. As part of the within-scope expansion of this project

  16. Comprehensive study on enhancing oil recovery in water-flooded gas well of Shenxi shallow gas reservoir%沈西浅层水淹气井提高采收率的综合研究

    Institute of Scientific and Technical Information of China (English)

    李军; 王凯

    2016-01-01

    沈西浅层气田处于开采后期,气藏地质条件复杂,水驱气藏产能降低,水淹气井采收率降低。根据水淹气井不同特点,分析产水状态及水淹主要因素,优选排水采气工艺技术措施,运用综合研究提高气藏采收率。%According to different characteristics of water-flooded gas well in Shenxi shallow gas reservoir, this paper analyses the status of water producing and the main factors of water flooding. Finally, the optimized drainage gas recovery measures are concluded and comprehensive study for enhancing gas reservoir recovery is used in this paper.

  17. 严重非均质油藏注水开发流体动力地质作用%Hydrodynamic geology effect during the waterflooding of seriously heterogeneous reservoirs

    Institute of Scientific and Technical Information of China (English)

    李中超; 陈洪德; 余成林; 杜利; 乔勇; 刘伟伟; 孙利

    2013-01-01

      针对东濮凹陷胡状集油田胡12块严重非均质油藏,采用室内实验对注水前后实际岩心样品进行对比分析,研究了注水开发过程中的流体动力地质作用.结果表明,酸性介质条件的化学动力作用加速了碎屑组分中的长石类矿物尤其是斜长石的溶蚀,同时生成了新的高岭石晶体并分布于细小孔喉,但对碳酸盐类矿物的影响较小.注水冲刷等物理动力地质作用造成了储集层泥质矿物总量的降低和粉砂—极细砂级石英颗粒的缺失,且主要发生在物性较好且优势渗流通道较发育的层段.在储集层孔喉变化方面,注水开发既使相对较大孔喉增加,改善了储集层的渗滤条件,也使孔喉分选程度降低,加剧了储集层微观非均质性.从储集层孔隙度、渗透率等宏观参数变化看,注水开发致使储集层总体平均有效孔隙度降低4.63%,而总体平均有效渗透率上升8.93%,原始物性不同的储集层注水后物性变化呈现出明显的“马太效应”.图7表3参15%Hu12 Block of the Huzhuangji Oilfield is a typical strongly heterogeneous reservoir. The hydrodynamic geology effect was studied by comparing experimental results of cores before and after waterflooding. The experimental results show that the chemical force of acidic medium accelerates the dissolution of plagioclase, generating new kaolinite crystals in small pore throats at the same time. The chemical force has less impact on carbonate minerals. The physical force of the injected water caused the reduction of the total content of argillaceous minerals and the loss of quartz grains of silt to very fine sizes, which occurred in layers with good physical properties and developed channeling paths. In terms of changes in pore-throats, waterflooding resulted in the increase of the large pore-throats and improvement of percolation conditions, also gives rise to the reduction of pore throat sorting and

  18. The utilization of the microflora indigenous to and present in oil-bearing formations to selectively plug the more porous zones thereby increasing oil recovery during waterflooding. Technical progress report, January 1, 1997--December 31, 1997

    Energy Technology Data Exchange (ETDEWEB)

    Stephens, J.O.

    1998-12-01

    This project is a field demonstration of the ability of in-situ indigenous microorganisms in the North Blowhorn Creek Oil Field to reduce the flow of injection water in the more permeable zones of the reservoir, thereby diverting flow to other areas thus increasing the efficiency of the waterflood. The project is divided into three phases: Planning and Analysis (9 months), Implementation (45 months), and Technology Transfer (12 months). This report covers the fourth year of work on the project. Twenty-two months after the injection of nutrients into the reservoir began, three wells were drilled and cores taken therefrom were analyzed. Oil production volumes and water:oil ratios (WOR) of produced fluids have shown clearly that the MEOR treatment being demonstrated in this project is improving oil recovery. Of the 15 producer wells in the test patterns, seven have responded positively to the injection of microbial nutrients into the reservoir, while all eight of the producer wells only in control patterns have continued their natural decline in oil production, although one well did have some improvement in oil production due to increased water injection into a nearby injector well. In light of these positive findings and with DOE`s approval, the scope of the field demonstration was expanded in July 1997 to include six new injector wells. Of interest has been the performance of two wells in what was formerly a control pattern. Since the injector in this pattern (formerly Control Pattern 2) began receiving nutrients, two of the wells in the pattern have shown improved oil production for the last three months. While it would be premature to definitely characterize these two wells as yielding a positive response, these early results are certainly encouraging.

  19. 孤岛油田水淹层地层水电阻率计算方法研究%Computation Method of Formation Water Resistivity for Water-flooded Zones in Gudao Oilfield

    Institute of Scientific and Technical Information of China (English)

    刘中奇; 崔琳; 董婷; 熊维

    2012-01-01

    In order to find residual oil of Gudao Oilfield Ng group in Shengli oil/gas zone, formation water resistivity, especially, flooded formation water resistivity needs to be accurately calculated. It is difficult to accurately calculate mud filtrate resistivity. Proposed is a new method to determine mud filtrate resistivity--known water layer calibration method. Based on the spontaneous potential logging principle, wellbore mud filtrate resistivity is calibrated with known water resistivity. With the calibrated mud filtrate resistivity, spontaneous potential can be applied to obtain the formation water resistivity of the target layers. The new method can accurately calculate the formation water resistivity even in water-flooded zones.%为寻找胜利油气区孤岛油田Ng组剩余油富集区,需要准确求取地层水电阻率,特别是水淹层地层水电阻率,难点在于泥浆滤液电阻率的准确求取.提出一种新的泥浆滤液电阻率确定方法——已知水层标定法.基于自然电位测并原理,用已知水层的电阻率标定井筒泥浆滤液的电阻率,用标定后的泥浆滤液电阻率应用自然电位测井求取目的层的地层水电阻率.该方法能够比较准确地计算地层水的电阻率,对水淹层地层水电阻率的计算也非常有效.

  20. Analysis and Solution for the Harm of Electromagnetic Interference in Waterflood Pump's Power Distribution System%注水泵配电系统中的电磁干扰危害分析与处理

    Institute of Scientific and Technical Information of China (English)

    张自亮; 张雅; 张浩

    2012-01-01

    Aiming at the harm of electromagnetic interference (EMI) in the 6 kV waterflood pump's power distribution system of Mobei oil-field, the reason of the generation of EMI was analyzed. Based on the analysis of wiring diagram and principle control diagram and the observation of field failure, the fault brought by EMI was affirmed;the reasonable solution was stated) the EMI harm was successfully eliminated) the safety production of Mobei oil-field was assured. The solution and analysis of this practical project case provide important reference for how to restrain the harm of EMI in power system.%针对漠北油田6 kV注水泵配电系统中的电磁干扰危害,分析了产生电磁干扰的原因,通过对系统一次接线图及二次控制原理图的分析和现场故障的考察,确认了故障是由电磁干扰造成的,提出了合理的解决方案,成功地消除了电磁干扰危害,确保了漠北油田的安全生产.通过对这一实际工程案例的分析和处理,为电力系统中如何抑制电磁干扰带来的危害提供了重要的参考价值.

  1. 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.

  2. Waterflooding injectate design systems and methods

    Energy Technology Data Exchange (ETDEWEB)

    Brady, Patrick V.; Krumhansl, James L.

    2016-12-13

    A method of recovering a liquid hydrocarbon using an injectate includes recovering the liquid hydrocarbon through primary extraction. Physico-chemical data representative of electrostatic interactions between the liquid hydrocarbon and the reservoir rock are measured. At least one additive of the injectate is selected based on the physico-chemical data. The method includes recovering the liquid hydrocarbon from the reservoir rock through secondary extraction using the injectate.

  3. Enhanced Oil Recovery by Horizontal Waterflooding

    Energy Technology Data Exchange (ETDEWEB)

    Scott Robinowitz; Dwight Dauben; June Schmeling

    2005-09-05

    Solar energy has become a major alternative for supplying a substantial fraction of the nation's future energy needs. The U.S. Department of Energy (DOE) supports activities ranging from the demonstration of existing technology to research on future possibilities. At Lawrence Berkeley Laboratory (LBL), projects are in progress that span a wide range of activities, with the emphasis on research to extend the scientific basis for solar energy applications, and on preliminary development of new approaches to solar energy conversion. To assess various solar applications, it is important to quantify the solar resource. Special instruments have been developed and are now in use to measure both direct solar radiation and circum-solar radiation, i.e., the radiation from near the sun resulting from the scattering of sunlight by small particles in the atmosphere. These measurements serve to predict the performance of solar designs that use focusing collectors employing mirrors or lenses to concentrate the sunlight. Efforts have continued at a low level to assist DOE in demonstrating existing solar technology by providing the San Francisco Operations Office (SAN) with technical support for its management of commercial-building solar demonstration projects. Also, a hot water and space-heating system has been installed on an LBL building as part of the DOE facilities Solar Demonstration Program. LBL continues to provide support for the DOE Appropriate Energy Technology grants program. Evaluations are made of the program's effectiveness by, for example, estimating the resulting potential energy savings. LBL also documents innovative features and improvements in economic feasibility as compared to existing conventional systems or applications. In the near future, we expect that LBL research will have a substantial impact in the areas of solar heating and cooling. Conventional and new types of high-performance absorption air conditioners are being developed that are air-cooled and suitable for use with flat plate or higher-temperature collectors. Operation of the controls test facility and computer modeling of collector loop and building load dynamics are yielding quantitative evaluations of the performance of different control strategies for active solar-heating systems. Research is continuing on ''passive'' approaches to solar heating and cooling, where careful considerations of architectural design, construction materials, and the environment are used to moderate a building's interior climate. Computer models of passive concepts are being developed and incorporated into building energy analysis computer programs which are in the public domain. The resulting passive analysis capabilities are used in systems studies leading to design tools and in the design of commercial buildings on a case study basis. The investigation of specific passive cooling methods is an ongoing project; for example, a process is being studied in which heat-storage material would be cooled by radiation to the night sky, and would then provide ''coolness'' to the building. Laboratory personnel involved in the solar cooling, controls, and passive projects are also providing technical support to the Active Heating and Cooling Division and the Passive and Hybrid Division of DOE in developing program plans, evaluating proposals, and making technical reviews of projects at other institutions and in industry. Low-grade heat is a widespread energy resource that could make a significant contribution to energy needs if economical methods can be developed for converting it to useful work. Investigations continued this year on the feasibility of using the ''shape-memory'' alloy, Nitinol, as a basis for constructing heat engines that could operate from energy sources, such as solar-heated water, industrial waste heat, geothermal brines, and ocean thermal gradients. Several projects are investigating longer-term possibilities for utilizing solar energy. One project involves the development of a new type of solar thermal receiver that would be placed at the focus of a central receiver system or a parabolic dish. The conversion of the concentrated sunlight to thermal energy would be accomplished by the absorption of the light by a dispersion of very small particles suspended in a gas. Another project is exploring biological systems. In particular, we are investigating the possibility of developing a photovoltaic cell, based on a catalyst (bacteriorhodopsin) which converts light to electrical ion flow across the cell membrane of a particular bacteria.

  4. 地热水驱%Geothermal-Hot-Water Waterflood

    Institute of Scientific and Technical Information of China (English)

    侯君

    2003-01-01

    地热水驱是一项成熟的采油技术.它直接利用地层中的热水,无需燃烧燃料来加热地层水和注入的冷水,从而大大提高了最终采收率.这种技术在高黏含蜡浅油层以及含盐浓度相对较低的较深含水层得到广泛应用.Sumatra盆地的许多油田都具有上述地质特征,而且Sumatra的地温梯度高,因而钻进地热源井很经济.

  5. Modeling of Salinity Effects on Waterflooding of Petroleum Reservoirs

    DEFF Research Database (Denmark)

    Alexeev, Artem

    of the experimental studies concerning the smart water effects recognize importance of the chemistry of reservoir rocks that manifests itself in dissolution and precipitation of rock minerals and adsorption of specific ions on the rock surface. The brine-rock interactions may affect the wetting state of the rock...... brine and the formation water that is initially in equilibrium with the reservoir rock. We consider a displacement process in one dimension with dissolution affecting both the porosity/permeability of the rock and the density of the brine. Extending previous studies, we account for the different...... of residual oil and its flow in porous media. The oil trapped in the swept zones after conventional flooding is present in a form of disconnected oil drops, or oil ganglia. While the macroscopic theory of multiphase flow assumes that fluid phases flow in their own pore networks and do not influence each other...

  6. Evaluation of oxygen corrosion in waterflood and disposal water systems

    Energy Technology Data Exchange (ETDEWEB)

    Conger, H.C.

    1967-01-01

    The case histories presented illustrate how specially polished pipe nipples have been used and examined in the field to evaluate the seriousness of an oxygen corrosion problem. The case histories also illustrate how these test pipe nipples have been used to evaluate actual, not relative, effectiveness of a chemical treatment program to control oxygen corrosion. Data are presented and discussed showing the relationship between corrosion rates of test pipe nipples and actual in-service equipment. The case histories show how corrosion rates based on pipe test nipple data were used to project equipment life under no chemical treatment vs. chemical treatment. A comparative study of corrosion rates between the use of pipe nipples and coupons as a means of measuring oxygen corrosion is discussed. A further comparative study is made between coupon corrosion rates based on weight loss and pit depth penetration.

  7. Crossflow and water banks in viscous dominant regimes of waterflooding

    DEFF Research Database (Denmark)

    Yuan, Hao; Zhang, Xuan; Shapiro, Alexander

    2014-01-01

    Understanding the crossflow in multilayered reservoirs is of great importance for designing mobility control methods for enhanced oil recovery. The authors reveal saturation profiles in stratified reservoirs to study the interlayer communication in the viscous dominant regime. The displacement...

  8. Recovery of Waterflood Residual Oil Using Alkali, Surfactant and Polymer Slugs in Radial Cores Récupération d'huile résiduelle par injection d'eau améliorée de produits alcalins, de tensio-actifs et de polymères dans des carottes radiales

    Directory of Open Access Journals (Sweden)

    Nasr-El-Din H. A.

    2006-11-01

    Full Text Available An experimental study has been conducted to examine mobilization and recovery of waterflood residual oil in radial cores. Alkali, surfactant, and polymer slugs of various compositions, sizes and sequences were tested. Core flood experiments were conducted with unfired radial Berea sandstone disks at a flow rate of 8 cm3/h. David Lloydminster crude oil (total acid number of 0. 45 mg KOH/g oil was used. The results of the present work showed that the composition and sequence of the injected chemical slug play an important role in mobilization and recovery of residual oil. For slugs lacking either mobility control, or low interfacial tension, no oil bank was formed and tertiary oil recovery was less than 20% Sor. A significant oil bank and tertiary oil recovery up to 70 % Sor were obtained with slugs having mobility control and low interfacial tension. However, maximum oil cut, incre-mental oil recovery and surfactant propagation were found to be functions of the alkali content in the slug. The incremental oil recovery, oil cut and slug injectivity greatly improved as the alkali concentration (sodium carbonate in the combined slug was increased. A slight delay in surfactant breakthrough and a significantly slower rate of surfactant propagation were observed at higher sodium carbonate concentrations. Une étude expérimentale ayant pour but d'examiner la mobilisation et la récupération assistée d'huile résiduelle, à la suite d'un déplacement par l'eau en milieu poreux, a été conduite. Des bouchons de produit alcalin, de surfactant et de polymère, ayant des compositions, grosseurs et séquences d'injection variées, furent essayés. Les déplacements en milieu poreux furent conduits en utilisant des carottes de grès berea (non traités à haute température et un débit de 8,0 cm3/h. Pour ce faire, on utilisa de l'huile de David Lloydminster (ayant un nombre acide de 0,45 mg KOH/g d'huile. Les résultats de ce travail ont démontré que la

  9. Experimental Design: Application to the Development of a Treatment to Inhibit the Deposition of Barium Sulfate Liable to Be Formed in Enhanced Oil Recovery by Waterflooding Planification d'expériences : application à la mise au point d'un traitement inhibiteur du depôt de sulfate de baryum susceptible de se former en récupération assistée du pétrole par injection d'eau

    Directory of Open Access Journals (Sweden)

    Roque C.

    2006-11-01

    Full Text Available For technical and economic reasons, waterflooding is the most widely-used method in enhanced oil recovery [1]. In many situations, unfortunately, the formation water is incompatible with the injection water. The deposits and corrosion induced by the various reactions of this incompatibility cause irreversible damage, which is especially dangerous for the reservoir rock and the downhole and surface production facilities. This study is concerned exclusively with barium sulfate deposits liable to occur in surface production facilities by the mixing of injection water loaded with sulfate (1300 mg. 1 to the power of (-1 with a formation water with a high barium concentration (1200 mg. 1 to the power of (-1 [2]. Pour des raisons techniques et économiques, l'injection d'eau dans les réservoirs est la méthode la plus employée dans la récupération du pétrole. Malheureusement, dans bien des cas, l'eau en place dans le gisement est incompatible avec l'eau injectée. Les dépôts et les corrosions causés par les diverses réactions physico-chimiques de cette incompatibilité provoquent des dégradations irréversibles particulièrement dangereuses pour les installations de production de fond comme de surface et quelquefois pour la roche réservoir elle-même. Dans le cadre des travaux de recherche relatifs à l'inhibition des dépôts de sulfate sur le champ algérien de Tin Fouyé Tabankort, cette étude a eu pour objectif de sélectionner et d'adapter aux conditions spécifiques de la production un traitement de prévention des dépôts par injection d'un agent inhibiteur. Elle concerne exclusivement les dépôts de sulfate de baryum pouvant apparaître dans les installations de production par mélange d'eau d'injection très chargée en ion sulfate (1300 mg. 1 puissance(-1 avec une eau de gisement très concentrée en élément baryum (1200 mg. 1 puissance(-1. Une méthode expérimentale au laboratoire, faisant appel à des mesures de type

  10. Waterflooding optimization for PETROBRAS fields; Otimizacao do gerenciamento de agua nos campos da PETROBRAS

    Energy Technology Data Exchange (ETDEWEB)

    Souza, Antonio L.S.; Furtado, Claudio J.A.; Mendes, Roberta A.; Rosa, Adalberto J. [PETROBRAS, Rio de Janeiro, RJ (Brazil)

    2004-07-01

    Petroleum companies have been manipulating increasing volumes of produced and injected water in offshore fields in the last few years. In Brazil, PETROBRAS manipulates over 3 million barrels of water, including injection, production and re-injection. Rate maintenance and produced water management are the main challenges for the next years. Rate maintenance is most related to operational efficiency and loss of injectivity. One of the best ways to avoid injectivity decline is to inject above fracture propagation pressure. However, speed and direction of fracture propagation are important parameters to be known in order to avoid sweep efficiency impacts. This work presents a methodology to calculate sweep efficiency effects due to fracture propagation pressure. Some aspects of the water management process are discussed, such as losses in recovery due to water injectivity decline and costs associated with water quality, but a larger effort is given to calculate and simulate changes in sweep efficiency due to fracture propagation in injectors. Simulations show that the impact in oil recovery due to fracture propagation pressure can be huge. Several different well patterns and arrangements are studied, showing that the impact depends on rate, well location and water quality. The results indicate that injection above fracture propagation pressure is a good alternative to prevent injectivity decline, but must be applied with good knowledge of the geo-mechanic reservoir characteristics. (author)

  11. Post Waterflood C02 Miscible Flood in Light Oil Fluvial-Dominated Deltaic Reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Tim Tipton

    1998-05-13

    The only remaining active well, Kuhn #14, in the Port Neches CO2 project went off production in October 1997. Production from this project is reached economic limit and the project termination began in the last quarter of 1997.

  12. 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.

  13. Experimental application of ultrasound waves to improved oil recovery during waterflooding

    OpenAIRE

    Emad Alhomadhi; Mohammad Amro; Mohammad Almobarky

    2014-01-01

    In oil reservoirs about 40% of the original oil in place is produced and the rest remains as residual oil after primary and secondary oil recovery due to geological and physical factors. Additional oil can be mobilized by applying some improved oil recovery methods. However, there is no universal IOR method to be implemented in any reservoir. Efforts are made to develop IOR methods with lower risk. One of these methods is the application of sound/ultrasound waves in the reservoirs to overcome...

  14. 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.

  15. Finger Thickening during Extra-Heavy Oil Waterflooding: Simulation and Interpretation Using Pore-Scale Modelling

    Science.gov (United States)

    Bondino, Igor; Hamon, Gerald

    2017-01-01

    Although thermal methods have been popular and successfully applied in heavy oil recovery, they are often found to be uneconomic or impractical. Therefore, alternative production protocols are being actively pursued and interesting options include water injection and polymer flooding. Indeed, such techniques have been successfully tested in recent laboratory investigations, where X-ray scans performed on homogeneous rock slabs during water flooding experiments have shown evidence of an interesting new phenomenon–post-breakthrough, highly dendritic water fingers have been observed to thicken and coalesce, forming braided water channels that improve sweep efficiency. However, these experimental studies involve displacement mechanisms that are still poorly understood, and so the optimization of this process for eventual field application is still somewhat problematic. Ideally, a combination of two-phase flow experiments and simulations should be put in place to help understand this process more fully. To this end, a fully dynamic network model is described and used to investigate finger thickening during water flooding of extra-heavy oils. The displacement physics has been implemented at the pore scale and this is followed by a successful benchmarking exercise of the numerical simulations against the groundbreaking micromodel experiments reported by Lenormand and co-workers in the 1980s. A range of slab-scale simulations has also been carried out and compared with the corresponding experimental observations. We show that the model is able to replicate finger architectures similar to those observed in the experiments and go on to reproduce and interpret, for the first time to our knowledge, finger thickening following water breakthrough. We note that this phenomenon has been observed here in homogeneous (i.e. un-fractured) media: the presence of fractures could be expected to exacerbate such fingering still further. Finally, we examine the impact of several system parameters, including core length, wettability and injection rate, on the extent and efficiency of the finger swelling phenomenon. PMID:28122011

  16. 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.

  17. Experimental application of ultrasound waves to improved oil recovery during waterflooding

    Directory of Open Access Journals (Sweden)

    Emad Alhomadhi

    2014-01-01

    Results show that the rate of oil displacement increases due to various identified mechanisms, and the interaction of the generated waves with the fluids in porous media causes changes in relative permeability and in water breakthrough. Wave stimulation at residual oil saturation was more effective than the case of original oil in place. Therefore, this method is advised to be used in depleted reservoirs. Moreover, wave stimulation on core sample with a compressive strength of <150 psi (unconsolidated is not recommended due to sand production.

  18. Enhancement of the sweep efficiency of waterflooding operations by the in-situ microbial population of petroleum reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Brown, L.R.; Vadie, A.A.; Stephens, J.O.; Azadpour, A.

    1995-12-31

    Live cores were obtained from five reservoirs using special precautions to prevent contamination by exogenous microorganisms and minimize exposure to oxygen. The depths from which the cores were obtained ranged from 2,705 ft to 6,568 ft. Core plugs were cut radially from live cores, encased in heat-shrink plastic tubes, placed in core holders, and fitted with inlets and outlets. Nutrient additions stimulated the in-situ microbial population to increase, dissolve stratal material, produce gases, and release oil. Reduction in flow through the core plugs was observed in some cases, while in other cases flow was increased, probably due to the dissolution of carbonates in the formation. A field demonstration of the ability of the in-situ microbial population to increase oil recovery by blocking the more permeable zones of the reservoir is currently underway. This demonstration is being conducted in the North Blowhorn Creek Unit situated in Lamar County, Alabama. Live cores were obtained from a newly drilled well in the field and tested as described above. The field project involves four test patterns each including one injector, four to five producers, and a comparable control injector with its four to five producers. Nutrient injection in the field began November 1994.

  19. Reservoir simulation and up-scaling of a waterflooding process using geostatistical simulated Dan-field data. Final report

    Energy Technology Data Exchange (ETDEWEB)

    NONE

    1996-12-01

    The geostatistical model represents a section of the Dan field in the Danish part of the North See. The Dan-field is a low permeability medium porosity oil reservoir. The section is placed on the southern flank of the Dan field. Using Annealing cosimulation technique (ACS) permeability and porosity distribution was derived from core samples of 15 wells (as hard data) and seismic impedances as secondary (soft) data. In this report 2 different 3D-sections of the geostatistical model are upscaled according to the principles of Stiles. A horizontal model consisting of the 3 top layers in the geostatistical model and a 3-D vertical segment was chosen. A single porosity BlackOil reservoir model is used as simulation model (i.e. gas soluted in the oil phase but no oil soluted in the gas phase). The following fluid- well- and initial state reservoir-data are used as input for the simulation of the geostatistical models: Oil formation volume factor; Oil compressibility; Oil viscosity. For the upscaled models the well data are adjusted to account for the upscaled grid size. Furthermore the relative permeabilities, the absolute permeabilities and the porosity are changed, according to the Stiles upscaling procedure. (EG)

  20. Integrated approach towards the application of horizontal wells to improve waterflooding performance. Quarterly report, April 1, 1997--June 30, 1997

    Energy Technology Data Exchange (ETDEWEB)

    Kelkar, M.; Liner, C.; Kerr, D.

    1997-10-01

    The overall purpose of the proposed project is to improve secondary recovery performance of a marginal oil field through the use of an appropriate reservoir management plan. The selection of plan will be based on the detailed reservoir description using an integrated approach. We expect that 2 to 5% of the original oil in place will be recovered using this method. This should extend the life of the reservoir by at least 10 years.

  1. How does the connectivity of open-framework conglomerates within multi-scale hierarchical fluvial architecture affect oil sweep efficiency in waterflooding?

    CERN Document Server

    Gershenzon, Naum I; Ritzi, Robert W; Dominic, David F; Keefer, Don; Shaffer, Eric; Storsved, Brynne

    2015-01-01

    We studied the effects on oil sweep efficiency of the proportion, hierarchical organization, and connectivity of high-permeability open-framework conglomerate (OFC) cross-sets within the multi-scale stratal architecture found in fluvial deposits. Utilizing numerical simulations and the RVA/Paraview open-source visualization package, we analyzed oil production rate, water breakthrough time, and spatial and temporal distribution of residual oil saturation. The effective permeability of the reservoir exhibits large-scale anisotropy created by the organization of OFC cross-sets within unit bars, and the organization of unit bars within compound bars. As a result oil sweep efficiency critically depends on the direction of the pressure gradient. When pressure gradient is oriented normal to paleoflow direction, the total oil production and the water breakthrough time are larger, and remaining oil saturation is smaller. This result is found regardless of the proportion or connectivity of the OFC cross-sets, within th...

  2. 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.

  3. 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.

  4. Alkaline Waterflooding Demonstration Project, Ranger Zone, Long Beach Unit, Wilmington Field, California. Fourth annual report, June 1979-May 1980. Volume 2. Appendix I

    Energy Technology Data Exchange (ETDEWEB)

    Carmichael, J.D.

    1981-03-01

    This appendix to the 1979-1980 annual report contains basic laboratory test reports, detailed instructions, plans and procedures, and various calculated data derived from operating observations. These are considered to be of sufficient interest to warrant their publication, but because of their bulk, to be of too much detail for inclusion in the body of the report. The table of contents specifies each group of data or description as a section which is believed to be complete in itself. The order of inclusion of the various sections has been dictated by the sequence of their reference in the body of the 1979-1980 annual report.

  5. Alkaline Waterflooding Demonstration Project, Ranger Zone, Long Beach Unit, Wilmington Field, California. Fourth annual report, June 1979-May 1980. Volume 1. Body of report

    Energy Technology Data Exchange (ETDEWEB)

    Carmichael, J.D.

    1981-03-01

    Comparative core flood testing of preserved Ranger Zone core rock samples was completed; the past year's results were discouraging. In contrast, Ranger sand pack alkaline flood tests gave encouraging results. New insights were gained on in-situ alkaline consumption. Dehydration of sodium orthosilicate water-produced water-crude oil systems does not appear to create any operational problems. The alkaline injection facilities were completed and placed in operation on March 27, 1980. The preflush injection, which was composed of 11.5 million barrels of softened fresh water with an average 0.96% of salt, was completed at that time. The total preflush amounted to approximately 10 pore volume percent. The 0.4% sodium orthosilicate-1.0% salt-soft fresh water injection started at the end of the preflush. A loss of injectivity began at the same time as alkaline injection, which is attributed to divalent ions in the salt brine. Salt was removed temporarily from the system on May 30, 1980. No injection wells were redrilled during the year. Other than plug back of one injector and one producer because of bad liners and repair of one injection well with an inner liner, well work was routine and minor in nature. Dual injection strings were transferred from one well to another. One of the injection wells whose injectivity was damaged by the alkaline-salt injection was successfully stimulated. The pilot was self certified under the tertiary incentive program and cost recoupments obtained. Preparations are underway for making the alkaline flood simulator performance prediction for the pilot. Laboratory testing is actively underway in an attempt to quickly find a remedy for the floc formation that occurs on mixing the salt brine and dilute alkaline solution. Volume 1 describes the activities for this period. Volumes 2 and 3 contain appendices.

  6. 水淹水导轴承的原因分析与处理%Cause Analysis and Treatment on Water-flooding of Water Guide Bearing

    Institute of Scientific and Technical Information of China (English)

    汤景红; 何丹心

    2012-01-01

    对某水电站水淹水导轴承原因进行分析并提出解决处理方案和应采取的防范措施,对机组顶盖排水泵进行改造.自改造投产以来,再没发生过水淹水导轴承的事故,为机组的安全稳定运行提供有力保障.

  7. Microbial Communities in Long-Term, Water-Flooded Petroleum Reservoirs with Different in situ Temperatures in the Huabei Oilfield, China

    Science.gov (United States)

    Tang, Yue-Qin; Li, Yan; Zhao, Jie-Yu; Chi, Chang-Qiao; Huang, Li-Xin; Dong, Han-Ping; Wu, Xiao-Lei

    2012-01-01

    The distribution of microbial communities in the Menggulin (MGL) and Ba19 blocks in the Huabei Oilfield, China, were studied based on 16S rRNA gene analysis. The dominant microbes showed obvious block-specific characteristics, and the two blocks had substantially different bacterial and archaeal communities. In the moderate-temperature MGL block, the bacteria were mainly Epsilonproteobacteria and Alphaproteobacteria, and the archaea were methanogens belonging to Methanolinea, Methanothermobacter, Methanosaeta, and Methanocella. However, in the high-temperature Ba19 block, the predominant bacteria were Gammaproteobacteria, and the predominant archaea were Methanothermobacter and Methanosaeta. In spite of shared taxa in the blocks, differences among wells in the same block were obvious, especially for bacterial communities in the MGL block. Compared to the bacterial communities, the archaeal communities were much more conserved within blocks and were not affected by the variation in the bacterial communities. PMID:22432032

  8. Microbial communities in long-term, water-flooded petroleum reservoirs with different in situ temperatures in the Huabei Oilfield, China.

    Directory of Open Access Journals (Sweden)

    Yue-Qin Tang

    Full Text Available The distribution of microbial communities in the Menggulin (MGL and Ba19 blocks in the Huabei Oilfield, China, were studied based on 16S rRNA gene analysis. The dominant microbes showed obvious block-specific characteristics, and the two blocks had substantially different bacterial and archaeal communities. In the moderate-temperature MGL block, the bacteria were mainly Epsilonproteobacteria and Alphaproteobacteria, and the archaea were methanogens belonging to Methanolinea, Methanothermobacter, Methanosaeta, and Methanocella. However, in the high-temperature Ba19 block, the predominant bacteria were Gammaproteobacteria, and the predominant archaea were Methanothermobacter and Methanosaeta. In spite of shared taxa in the blocks, differences among wells in the same block were obvious, especially for bacterial communities in the MGL block. Compared to the bacterial communities, the archaeal communities were much more conserved within blocks and were not affected by the variation in the bacterial communities.

  9. Compositions and Abundances of Sulfate-Reducing and Sulfur-Oxidizing Microorganisms in Water-Flooded Petroleum Reservoirs with Different Temperatures in China.

    Science.gov (United States)

    Tian, Huimei; Gao, Peike; Chen, Zhaohui; Li, Yanshu; Li, Yan; Wang, Yansen; Zhou, Jiefang; Li, Guoqiang; Ma, Ting

    2017-01-01

    Sulfate-reducing bacteria (SRB) have been studied extensively in the petroleum industry due to their role in corrosion, but very little is known about sulfur-oxidizing bacteria (SOB), which drive the oxidization of sulfur-compounds produced by the activity of SRB in petroleum reservoirs. Here, we surveyed the community structure, diversity and abundance of SRB and SOB simultaneously based on 16S rRNA, dsrB and soxB gene sequencing, and quantitative PCR analyses, respectively in petroleum reservoirs with different physicochemical properties. Similar to SRB, SOB were found widely inhabiting the analyzed reservoirs with high diversity and different structures. The dominant SRB belonged to the classes Deltaproteobacteria and Clostridia, and included the Desulfotignum, Desulfotomaculum, Desulfovibrio, Desulfobulbus, and Desulfomicrobium genera. The most frequently detected potential SOB were Sulfurimonas, Thiobacillus, Thioclava, Thiohalomonas and Dechloromonas, and belonged to Betaproteobacteria, Alphaproteobacteria, and Epsilonproteobacteria. Among them, Desulfovibrio, Desulfomicrobium, Thioclava, and Sulfurimonas were highly abundant in the low-temperature reservoirs, while Desulfotomaculum, Desulfotignum, Thiobacillus, and Dechloromonas were more often present in high-temperature reservoirs. The relative abundances of SRB and SOB varied and were present at higher proportions in the relatively high-temperature reservoirs. Canonical correspondence analysis also revealed that the SRB and SOB communities in reservoirs displayed high niche specificity and were closely related to reservoir temperature, pH of the formation brine, and sulfate concentration. In conclusion, this study extends our knowledge about the distribution of SRB and SOB communities in petroleum reservoirs.

  10. Compositions and Abundances of Sulfate-Reducing and Sulfur-Oxidizing Microorganisms in Water-Flooded Petroleum Reservoirs with Different Temperatures in China

    OpenAIRE

    Tian, Huimei; Gao, Peike; Chen, Zhaohui; Li, Yanshu; Li, Yan; Wang, Yansen; Zhou, Jiefang; Li, Guoqiang; Ma, Ting

    2017-01-01

    Sulfate-reducing bacteria (SRB) have been studied extensively in the petroleum industry due to their role in corrosion, but very little is known about sulfur-oxidizing bacteria (SOB), which drive the oxidization of sulfur-compounds produced by the activity of SRB in petroleum reservoirs. Here, we surveyed the community structure, diversity and abundance of SRB and SOB simultaneously based on 16S rRNA, dsrB and soxB gene sequencing, and quantitative PCR analyses, respectively in petroleum rese...

  11. Design and implementation of a CO{sub 2} flood utilizing advanced reservoir characterization and horizontal injection wells in a shallow shelf carbonate approaching waterflood depletion. Annual report, June 3, 1994--October 31, 1995

    Energy Technology Data Exchange (ETDEWEB)

    Hallenbeck, L.D.; Harpole, K.J.; Gerard, M.G.

    1996-05-01

    The work reported here covers Budget Phase I of the project. The principal tasks in Budget Phase I are the Reservoir Analysis and Characterization Task and the Advanced Technology Definition Task. Completion of these tasks have enabled an optimum carbon dioxide (CO{sub 2}) flood project to be designed and evaluated from an economic and risk analysis standpoint. Field implementation of the project has been recommended to the working interest owner of the South Cowden Unit (SCU) and approval has been obtained. The current project has focused on reducing initial investment cost by utilizing horizontal injection wells and concentrating the project in the best productivity area of the field. An innovative CO{sub 2} purchase agreement (no take or pay requirements, CO{sub 2} purchase price tied to West Texas Intermediate crude oil price) and gas recycle agreements (expensing cost as opposed to large capital investments for compression) were negotiated to further improve project economics. A detailed reservoir characterization study was completed by an integrated team of geoscientists and engineers. The study consisted of detailed core description, integration of log response to core descriptions, mapping of the major flow units, evaluation of porosity and permeability relationships, geostatistical analysis of permeability trends, and direct integration of reservoir performance with the geological interpretation. The study methodology fostered iterative bidirectional feedback between the reservoir characterization team and the reservoir engineering/simulation team to allow simultaneous refinement and convergence of the geological interpretation with the reservoir model. The fundamental conclusion from the study is that South Cowden exhibits favorable enhanced oil recovery characteristics, particularly reservoir quality and continuity.

  12. FORMATION SCALING MECHANISM AND THE RELATED FORMATION DAMAGE OF WATERFLOODING OIL FIELDS%注水开发油田油层结垢机理及油层伤害

    Institute of Scientific and Technical Information of China (English)

    贾红育; 曲志浩

    2001-01-01

    By means of simulation experiments in sandstonemicromodels,scaling mechanism and formation damage due to scaling of BaSO4 and CaCO3 are studied respectively. The results show:1)Formation scaling is formed in the repeated heterogeneous-phase nucleation and crystal growth. The crystal can grow both in pores and at throats. 2)The characteristics of scaling are different for different scales. BaSO4 scaling develops intermittently in the alternate process of water mixing and scaling, the morphology of the scale crystals develops poorly and the crystals are fine.While CaCO3 scaling develops continuously,the morpholgy of the scale crystals develops perfectly and the crystals are large. 3)The formation damage due to scaling is a complex problem,even if effects of temperature and multiphase flow are excluded,it is still affected by the amount of scale and formation permeability. In general,the larger the amount of scale is or the lower the permeability is,the severer the formation damage is.As the permeability of formation decreases,the difference of formation damage decreases due to different amount of scale. As the amount of scale increase,the difference of formation damage decreases in formations with different permeability.%通过砂岩微观孔隙模型模拟实验,分别对BaSO4和CaCO3结垢机理及结垢油层伤害规律进行了研究。研究结果表明:①油层结垢是在多次的异相成核—晶体生长过程形成的,晶体生长在孔隙中和喉道处均可发生;②不同类型结垢,其结垢特点不同。BaSO4结垢呈现出水混合—结垢交替间断进行及垢晶体晶形发育差、晶粒细小之特点,而BaSO3结垢呈现出连续进行及垢晶体晶形发育好、晶粒粗大之特点;③结垢油层伤害是一复杂问题,即使不考虑温度及多相渗流的影响,其仍受到结垢量和油层渗透性的双重影响。一般结垢量越大,油层渗透性越差,结垢对油层的伤害越严重。随油层渗透性变差,结垢量不同引起的结垢油层伤害程度的差异减小;随结垢量增大,渗透性不同,油层结垢伤害程度的差异减小。

  13. Development Practice of Improving Water-Flooding Recovery in Deep Low Permeability Reservoir%深层低渗透油藏大幅提高水驱采收率开发实践

    Institute of Scientific and Technical Information of China (English)

    江燕

    2015-01-01

    In Qianjiang formation of Jianghan basin ,Qian43 oil formation of Wangchang Oilfield is a low -permeabili-ty reservoir which has the largest oil-bearing area and geological reserves with characteristics of deep burial ,thin oil bed and poor properties .By constantly deepening geological knowledge ,relying on the progress of technologies such as massive fracturing ,a complete deep pumping ,high-pressure water injection as well as horizontal wells ,and im-plementing fine separate -layer adjustment and fine separate -layer water -flooding ,substantially increasing oil production and stable yield has been achieved under the condition of sharply decreasing yield .Calibration recovery ra-tio has raised 10 .65 percent points ,reaching 44 .05% by the end of 2014 .The realization of high-efficient develop-ment of low -permeability reservoir provides the reference for enhancing oil recovery of reservoirs of the same type .%王场油田潜43油组是江汉盆地潜江组含油面积与地质储量最大的一个低渗透油藏 ,埋藏深、油层薄、物性差.通过不断深化地质认识 ,依托大型压裂、深抽配套、高压注水、水平井等工艺技术进步 ,实施细分层调整与精细注水开发 ,油藏在产量大幅递减后又重新实现了大幅上产与稳产 ,标定采收率提高了10 .65 个百分点,2014年底达到44 .05% ,实现了低渗透油藏的高效开发,为同类型油藏提高采收率提供了借鉴.

  14. Study on the Properties of Water-Flooded Pay in the Different Periods of Oilfield Development%水驱方式下不同开发阶段水淹层岩石物理特征研究

    Institute of Scientific and Technical Information of China (English)

    张敏; 刘卫东

    2009-01-01

    针对我国大多数陆相非均质老油田注水开发的特点及其在高含水期测井解释所遇到的诸多问题,通过模拟开发过程的岩石物理实验,研究了水驱过程中油藏性质变化对岩石地球物理特征的影响及作用机理,在岩石物理实验基础上研究了水驱方式下不同开发阶段水淹层的测井响应特征,并提出了相应的识别评价方法.研究结果表明:①水驱油方式下的I-Sw关系不再是一条直线,而呈现出与饱和度大小相关的两段式,当含水饱和度达到一定值(Swp)以后,电阻率对饱和度变化的反映不敏感.②在不同的浓度范围内,地层水矿化度对岩石表面双电层厚度及平衡离子活动性的影响不同,导致胶结指数m和饱和度指数n的值以及Waxman-Smits模型中的B参数在不同的矿化度范围内表现出不同的特征.③注入介质在高渗透条带中线性突破形成的电阻率宏观各向异性使储层在仍具有相当产能的情况下电阻率显著降低.④动电现象是特定油藏环境下的一种特殊岩石物理现象,开发过程导致的压力异常是其产生的本质原因,流动电位的大小与压差、多相流动特征及地层水矿化度有关,流动电位的存在使自然电位曲线表现异常.

  15. 杨19油藏东部初期注水开发效果分析%Analyses on the Effect of Early-Stage Water-flood Development in the East of Yang 19 Oil Reservoir

    Institute of Scientific and Technical Information of China (English)

    郭永康; 王辉; 郭春竹; 孔鹏

    2012-01-01

    The east area of Yan 9 reservoir in Yang19 block in Sui Jing oilfield is the lithology-tectonic oil reservoir based on the structure,with characteristics of shallow bury,thick layer of sand,single rock,and the limited water at the edge of bottom.At the early stage,natural energy was used in the development,but the energy of formation dropped rapidly.In order to realize the stable and high production of oilfield,and enhance the final oil recovery of oilfields,water-flooding development for oil reservoir has been carried out since Sept.2009.With the process being explored continuously and the precise water injection production being adjusted constantly,the better effect has been achieved now.Meanwhile,some experiences are summarized in the adjustment,which provides theoretical basis for western oil reservoir development.%绥靖油田杨19区块延9油藏东部具有埋藏浅,砂层厚,岩性单一,边底水有限的特征,是以构造为主的岩性—构造油藏。前期利用自然能量开发,地层能量下降迅速,为了实现油田稳产、高产,提高油田最终采收率,自2009年9月起对油藏进行注水开发,开发过程不断探索、不断精细注采调整,目前已取得良好效果,并在调整过程总结了一些经验,对西部油藏开发提供了理论上的依据。

  16. 积液水淹气井多井气举工艺设计及应用%Design and Application of Multi-well Gas Lift in Water-flooded Gas Well

    Institute of Scientific and Technical Information of China (English)

    王雷

    2016-01-01

    With the increase of production time,exacerbated by the difficulty of drainage gas recov-ery.Flooded wells gradually increased.On the same site only a single well watered gas well.The gas lift truck has no sufficient air supply to work.But the single well gas lift leads to over pres-sure of the gas lift truck,in the gas gathering station with sufficient air supply through alcohol in-jection pipeline gas lift.Through the theoretical calculation of many wells in the alcohol injection pipeline flow and friction,the gas lift car exhaust end gas shunt.On the one hand,the gas lift truck exhaust pressure is to control,and on the other hand,and to ensure that a single well to meet the needs of the diversion.Using the design method to carry out the field test for 4 wells,the exhaust pressure can be well controlled,and does not lead to gas lift truck overpressure,can effec-tively cite the well liquid,to achieve the purpose of gas lift construction.The research results have important guiding significance for improving the stable production of gas wells and the late devel-opment of Daniudi Gas Fields.%随着生产时间延长,气井排水采气难度加剧,积液水淹井逐渐增多.对于同井场只有1口单井的水淹气井,气举车没有充足的气源供给而不能作业.在集气站有充足的气源供给,可以通过注醇管线进行气举,但单井气举导致气举车超压.通过理论计算多口气井注醇管线流量及摩阻,对气举车排气端气体进行分流,一方面控制气举车排气压力,另一方面保证单井分流气量达到携液要求.利用该方法对4口井开展现场试验,能够很好地控制排气压力,不会导致气举车超压,能够有效举出井内积液,达到气举施工的目的.研究成果对大牛地气田提高气井稳产及气田中后期开发有着重要的指导意义.

  17. 新疆稠油水淹层测井解释方法研究%Well Logging Interpretation Method for Thick Oil Water-Flooded Zones in Xinjiang

    Institute of Scientific and Technical Information of China (English)

    杜礼轩; 田建军; 王文文; 万泽君; 侯磊

    2010-01-01

    新疆稠油油层水淹后的岩性、物性及流体性质均发生了变化,本次研究总结了新疆稠油水淹层的定性、定量解释方法,分析研究了C/O测井资料在该区域的运用,建立了稠油水淹层特征参数的解释模型,并验证了模型的适用性和解释符合率,优化水淹层测井系列,提高储层参数的解释精度,总结出一套砂砾岩稠油油藏水淹层解释方法,建立了研究区水淹储层的参数计算模型及水淹层判别标准.

  18. Research of well Logging Interpretation for Waterflooded Viscous Crude Zone%稠油水淹测井解释方法研究——以欢喜岭油田齐40块为例

    Institute of Scientific and Technical Information of China (English)

    翟营莉

    2008-01-01

    本文以齐40块稠油油藏为研究对象,通过对区块地质资料、测井资料、测试资料、采油动态资料分析研究,总结出稠油水淹在不同测井曲线上的响应特征,分析了利用激发极化电位、地层测试、碳氧比测井技术特征,有效进行水淹层识别及解释,为稠油油藏开发中、后期的解释评价提供有效方法和手段.

  19. Application of Alkaline Waterflooding to a High Acidity Crude Oil Application de l'injection d'eau alcaline au cas d'un pétrole brut à forte acidité

    Directory of Open Access Journals (Sweden)

    Abdel-Waly A.

    2006-11-01

    Full Text Available The main objective of this work was to study the enhanced recovery of a high acidity crude oil (South Geisum crude by alkaline solutions. Different properties of South Geisum crude oil, namely acidity, interfacial tension, and contact angle, were investigated. Displacement tests were carried out to study the effect of alkaline slug concentration, slug size, oil alkali type, and temperature viscosity on recovery. South Geisum crude oil is a highly acidic crude (4. 38 mg KOH/g. It was found that the interfacial tension between crude oil and formation water decreases with increasing alkaline concentration until it reaches a minimum, after which it increases again with a further increase in alkaline concentration. Interfacial tension between crude oil and displacement water also decreases with increasing alkaline concentration. Contact angle measurements indicated oil-wetting conditions that increase by the addition of alkaline solutions. Displacement floods showed that, at the early stages of displacement, oil recovery increases with increasing alkaline concentration until it reaches a maximum at 4 % by weight NaOH concentration. Also, at such early stages, an excessive increase in alkaline concentration results in lower oil recovery. On the other hand, after the injection of many pore volumes of water, oil recovery is almost the same regardless of the alkaline concentration. It was found also that oil recovery increases with increasing alkaline slug size until it reaches a maximum at 15 % PV, after which increasing slug size results in decreasing oil recovery (this result has not as yet been reported in the literature. Sodium hydroxide slugs produce more oil recovery than sodium carbonate slugs. Oil recovery increases with increasing temperature (from 25 to 55°C and decreasing oil viscosity. Cet article traite de la récupération, au moyen de solutions alcalines, d'un pétrole brut à forte acidité (brut de Geisum-Sud. Différentes propriétés du pétrole brut de Geisum-Sud ont été étudiées, telles que l'acidité, la tension interfaciale et l'angle de contact. On a effectué des essais de déplacement pour étudier l'effet sur la récupération, de la concentration, de la taille et de la viscosité du bouchon alcalin ainsi que du type d'alcali utilisé et de la température. Le pétrole brut de Geisum-Sud a un indice d'acidité élevé (4,38 mg KOH/g. On a constaté que la tension interfaciale entre le pétrole brut et l'eau et gisement diminuait lorsque la concentration alcaline augmentait pour atteindre un minimum puis qu'elle augmentait à nouveau avec l'accroissement de la concentration alcaline. La tension interfaciale entre le pétrole brut et l'eau d'injection diminue également avec l'augmentation de la concentration d'alcali. Les mesures d'angle de contact indiquent des conditions de mouillabilité à l'huile qui augmentent avec l'addition de solutions alcalines. Les expériences de déplacements montrent qu'au début du déplacement, la récupération du pétrole augmente avec l'accroissement de la concentration alcaline, pour atteindre un maximum à une concentration de NaOH de 4% en poids. Par ailleurs, au début du déplacement, une augmentation excessive de la concentration alcaline entraîne une moindre récupération d'huile. Par contre, après l'injection de nombreux volumes de pores d'eau, la récupération est presque la même, quelle que soit la concentration alcaline injectée. On a également trouvé que l'on récupère plus d'huile lorsque la taille des bouchons de soude augmente, jusqu'à atteindre un maximum pour une taille de 15% du volume des pores; ensuite, l'accroissement de la taille des bouchons entraîne une diminution de la récupération (ce résultat n'a pas encore paru dans la littérature. Les bouchons de soude produisent une meilleure récupération que les bouchons de carbonate de soude. Enfin, la récupération d'huile augmente avec l'accroissement de la température (de 25 à 55°C ou la diminution de viscosité de l'huile brute.

  20. Fine Formation During Brine-Crude Oil-Calcite Interaction in Smart Water Enhanced Oil Recovery for Caspian Carbonates

    DEFF Research Database (Denmark)

    Chakravarty, Krishna Hara; Fosbøl, Philip Loldrup; Thomsen, Kaj

    2015-01-01

    Modified sea water has been shown to affect the oil recovery fraction considerably during secondary and tertiary waterfloods. Available soluble potential ions (i.e. Ca2+, Mg2+ & SO42-) in the interacting waterflood (ITW) are suggested to play a key role in increasing the displacement efficiency...

  1. COMPREHENSIVE LOG INTERPRETATION AND EVALUATION OF WATER-FLOOD FORMATION AT THE MIDDLE SEVENTH DISTRICT IN GUDONG OIL FIELD%孤东油田七区中水淹层测井资料综合解释及评价

    Institute of Scientific and Technical Information of China (English)

    徐守余

    1999-01-01

    分析了孤东油田七区中测井资料,在此基础上提出了该区水淹层的定性判别模式.利用关键井分析技术建立了多种地质参数的测井解释模型,并利用灰色判别技术制定出有效厚度和夹层厚度的确定标准,利用常规测井资料对水淹层测井资料进行了定性与定量相结合的评价,评价解释结果与生产测试结果吻合较好,取得了良好的地质效果.

  2. Weyburn油田CO2驱动态与过去水驱动态之间关系式的形成%Development of A Correlation Between Performance of CO2 Flooding and the Past Performance of Waterflooding in Weyburn Oil Field

    Institute of Scientific and Technical Information of China (English)

    袁继明; 彭彩珍

    2009-01-01

    Weyburn油田位于加拿大Saskatchewan东南,从2000年9月以来一直是世界上最大的CO2驱项目之一.本文用Weyburn油田过去的水驱动态数据建立经验公式,用于预测CO2驱动态.基于Weyburn油田的注CO2方案,给出了两种不同的关系式.第一种关系式基于垂直井的WAG(水气交替注入)方法,第二种关系式基于水平井注CO2而垂直井注水的情况.第一步,收集和分析1958-2004年的生产数据.用水驱和CO2驱期间的产油量、注水量以及CO2注入量来推导公式.用Kinder Morgan CO2 Scoping模型和油田实际生产数据检验垂直并注水和CO2的经验模型.对比分析表明此简易公式和Kinder Morgan模型之间有12%的误差.对于水平井注CO2,不能用Kinder Morgan模型对此公式进行检验,但此公式与油田实际生产数据非常接近.根据先前水驱动态数据和CO2注入量,新模型可作为有效筛选工具来预测Weyburn油藏任意地区的CO2驱动态.因此,它对石油公司来说,既省时又经济.同时,与Weyburn油田历史和性质相似的有潜力进行CO2驱的油藏也可使用该公式.

  3. 油田水中新型水驱示踪剂氟苯甲酸的气相色谱-质谱分析%Study on Determination of 2-Fluorobenzioc Acid in Oilfield Brain for Waterflood Tracing by Gas Chromatography-Mass Spectrometry

    Institute of Scientific and Technical Information of China (English)

    隋艳颖; 李金英; 张培信

    2004-01-01

    建立了油田水中新型水驱示踪剂2-(2-FBA)的痕量分析方法.该方法将过滤、固相萃取、衍生等样品前处理技术有效地结合在一起,应用气相色谱-质谱(GC/MS)技术对其进行定性和定量测定.结果表明:方法具有较高的灵敏度和可靠的不确定度,油田水取样量为250 mL时,2-FBA最低检测限达4 ng/L.400 ng/L2-FBA的单次测量结果扩展不确定度为50 ng/L,即相对扩展不确定度优于14%.本方法采用4-甲基-氟苯甲酸(4-TMFBA)作为内标物质校正衍生及测量过程.2-FBA的浓度为5~2000 ng/L,标准曲线的相关系数》0.999 8.此方法适用于油田、环境、生物、药物等样品中痕量2-FBA的快速、准确分析.同时也为其它氟代苯甲酸作为油田示踪剂提供了分析方法.

  4. Engineering Behavior and Characteristics of Water-Soluble Polymers: Implication on Soil Remediation and Enhanced Oil Recovery

    National Research Council Canada - National Science Library

    Shuang Cindy Cao; Bate Bate; Jong Wan Hu; Jongwon Jung

    2016-01-01

      Biopolymers have shown a great effect in enhanced oil recovery because of the improvement of water-flood performance by mobility control, as well as having been considered for oil contaminated-soil...

  5. pressure distribution in a layered reservoir with gas-cap and bottom ...

    African Journals Online (AJOL)

    2012-07-02

    Jul 2, 2012 ... Oil production from a layered reservoir with a top gas cap and bottom water acting simultaneously poses serious ... voir fluid is produced (water-flooding or an enhanced recovery scheme), detailed layer information enables.

  6. 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.

  7. Enhanced Oil Recovery with Surfactant Flooding

    DEFF Research Database (Denmark)

    Sandersen, Sara Bülow

    Enhanced oil recovery (EOR) is being increasingly applied in the oil industry and several different technologies have emerged during, the last decades in order to optimize oil recovery after conventional recovery methods have been applied. Surfactant flooding is an EOR technique in which the phase...... both for complex surfactant systems as well as for oil and brine systems. It is widely accepted that an increase in oil recovery can be obtained through flooding, whether it is simple waterflooding, waterflooding where the salinity has been modified by the addition or removal of specific ions (socalled...... “smart” waterflooding) or surfactant flooding. High pressure experiments have been carried out in this work on a surfactant system (surfactant/ oil/ brine) and on oil/ seawater systems (oil/ brine). The high pressure experiments were carried out on a DBR JEFRI PVT cell, where a glass window allows...

  8. Inhibitor treatment program for chlorine dioxide corrosion

    Energy Technology Data Exchange (ETDEWEB)

    Edmondson, J.G.; Holder, E.P.

    1991-11-12

    This patent describes a method of inhibiting corrosion by chlorine dioxide in oil field waterflood systems by adding a sufficient amount of a corrosion inhibiting composition. It comprises a phosphonate, a copolymer consisting of repeating units of acrylic acid/allyl hydroxy propyl sulfonate ether, and a permangante.

  9. [Ammonia volatilization of slow release compound fertilizer in different soils water conditions].

    Science.gov (United States)

    Hu, Xiao-feng; Wang, Zheng-yin; You, Yuan; Li, Jing-chao

    2010-08-01

    By using venting method incubation experiment, we studied the ammonia volatilization and kinetics characteristics of uncoated slowed release compound fertilizer (SRF) under different soil water conditions and the growth and nitrogen utilization efficiency of rice in pot experiment. Results indicated that the ammonia volatilization of SRF under waterflooding reached the peak ahead of 3-4 days compared to the moist treatment. The peak and accumulation of ammonia volatilization in the waterflooding treatments were higher than those under the moist condition. SRF could significantly reduce total ammonia volatilization compared to the common compound fertilizer (CCF), reduced by 50.6% and 22.8% in the moist treatment and reduced by 24.2% and 10.4% in the waterflooding treatment,but the loss of ammonia volatilization of SRF was higher significantly than that of the coated fertilizer (CRF). Ammonia volatilization increased with the increasing of fertilizer application. The dynamics of ammonia volatilization of SRF could be quantitatively described with three equations: the first order kinetics equation, Elovich equation and parabola equation. Compared to moist condition, the biomass of rice plant in SRF, CCF and SRF treatments increased by 67.86%, 78.25% and 48.75%, and nitrogen utilization efficiency increased by 57.73%, 80.70% and 12.06% under waterflooding condition, respectively. Comparing with CCF, nitrogen utilization efficiency in SRF treatment improved by 59.10% and 10.40% under two soil moisture conditions. SRF could reduce ammonia volatilization and improve biomass and nitrogen utilization efficiency.

  10. 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.

  11. Residual-oil-saturation-technology test, Bell Creek Field, Montana. Final report

    Energy Technology Data Exchange (ETDEWEB)

    1981-06-01

    A field test was conducted of the technology available to measure residual oil saturation following waterflood secondary oil recovery processes. The test was conducted in a new well drilled solely for that purpose, located immediately northwest of the Bell Creek Micellar Polymer Pilot. The area where the test was conducted was originally drilled during 1968, produced by primary until late 1970, and was under line drive waterflood secondary recovery until early 1976, when the area was shut in at waterflood depletion. This report presents the results of tests conducted to determine waterflood residual oil saturation in the Muddy Sandstone reservoir. The engineering techniques used to determine the magnitude and distribution of the remaining oil saturation included both pressure and sidewall cores, conventional well logs (Dual Laterolog - Micro Spherically Focused Log, Dual Induction Log - Spherically Focused Log, Borehole Compensated Sonic Log, Formation Compensated Density-Compensated Neutron Log), Carbon-Oxygen Logs, Dielectric Logs, Nuclear Magnetism Log, Thermal Decay Time Logs, and a Partitioning Tracer Test.

  12. Results of the brugge benchmark study for flooding optimization and history matching

    NARCIS (Netherlands)

    Peters, E.; Arts, R.J.; Brouwer, G.K.; Geel, C.R.; Cullick, S.; Lorentzen, R.J.; Chen, Y.; Dunlop, K.N.B.; Vossepoel, F.C.; Xu, R.; Sarma, P.; Alhutali, A.H.; Reynolds, A.C.

    2010-01-01

    In preparation for the SPE Applied Technology Workshop (ATW) held in Brugge in June 2008, a unique benchmark project was organized to test the combined use of waterflooding-optimization and history-matching methods in a closed-loop workflow. The benchmark was organized in the form of an interactive

  13. Fluid injection for salt water disposal and enhanced oil recovery as a potential problem for the WIPP: Proceedings of a June 1995 workshop and analysis

    Energy Technology Data Exchange (ETDEWEB)

    Silva, M.K.

    1996-08-01

    The Waste Isolation Pilot Plant (WIPP) is a facility of the U.S. Department of Energy (DOE), designed and constructed for the permanent disposal of transuranic (TRU) defense waste. The repository is sited in the New Mexico portion of the Delaware Basin, at a depth of 655 meters, in the salt beds of the Salado Formation. The WIPP is surrounded by reserves and production of potash, crude oil and natural gas. In selecting a repository site, concerns about extensive oil field development eliminated the Mescalero Plains site in Chaves County and concerns about future waterflooding in nearby oil fields helped eliminate the Alternate II site in Lea County. Ultimately, the Los Medanos site in Eddy County was selected, relying in part on the conclusion that there were no oil reserves at the site. For oil field operations, the problem of water migrating from the injection zone, through other formations such as the Salado, and onto adjacent property has long been recognized. In 1980, the DOE intended to prohibit secondary recovery by waterflooding in one mile buffer surrounding the WIPP Site. However, the DOE relinquished the right to restrict waterflooding based on a natural resources report which maintained that there was a minimal amount of crude oil likely to exist at the WIPP site, hence waterflooding adjacent to the WIPP would be unlikely. This document presents the workshop presentations and analyses for the fluid injection for salt water disposal and enhanced oil recovery utilizing fluid injection and their potential effects on the WIPP facility.

  14. Application of Isotopic Tracerlog for Water Injection Profile

    Institute of Scientific and Technical Information of China (English)

    Jiang Wenda; Zheng Hua

    1996-01-01

    @@ Most of the oilfields in China are developed.utilizing water-flooding. Oilfield development therefore requires not only production wells,but also associated water injection wells, through which water is injected into separated layers to maintain formation pressure and stable production rate.

  15. An experimental and theoretical study to relate uncommon rock/fluid properties to oil recovery. Final report

    Energy Technology Data Exchange (ETDEWEB)

    Watson, R.

    1995-07-01

    Waterflooding is the most commonly used secondary oil recovery technique. One of the requirements for understanding waterflood performance is a good knowledge of the basic properties of the reservoir rocks. This study is aimed at correlating rock-pore characteristics to oil recovery from various reservoir rock types and incorporating these properties into empirical models for Predicting oil recovery. For that reason, this report deals with the analyses and interpretation of experimental data collected from core floods and correlated against measurements of absolute permeability, porosity. wettability index, mercury porosimetry properties and irreducible water saturation. The results of the radial-core the radial-core and linear-core flow investigations and the other associated experimental analyses are presented and incorporated into empirical models to improve the predictions of oil recovery resulting from waterflooding, for sandstone and limestone reservoirs. For the radial-core case, the standardized regression model selected, based on a subset of the variables, predicted oil recovery by waterflooding with a standard deviation of 7%. For the linear-core case, separate models are developed using common, uncommon and combination of both types of rock properties. It was observed that residual oil saturation and oil recovery are better predicted with the inclusion of both common and uncommon rock/fluid properties into the predictive models.

  16. Gravity Effect on Two-Phase Immiscible Flows in Communicating Layered Reservoirs

    DEFF Research Database (Denmark)

    Zhang, Xuan; Shapiro, Alexander; Stenby, Erling Halfdan

    2012-01-01

    An upscaling method is developed for two-phase immiscible incompressible flows in layered reservoirs with good communication between the layers. It takes the effect of gravity into consideration. Waterflooding of petroleum reservoirs is used as a basic example for application of this method...... for gravity segregation. The effects of gravity are analyzed....

  17. Wettability of quartz surface as observed by NMR transverse relaxation time (T2)

    DEFF Research Database (Denmark)

    Alam, Mohammad Monzurul; Katika, Konstantina; Fabricius, Ida Lykke

    Injection of optimized water composition (smart water) is an advanced water flooding method for Enhanced Oil Recovery (EOR). Low saline waterflooding has been proved successful in sandstone reservoir. However, there is still controversy on the mechanism of smart water flooding. We studied...

  18. An experimental and theoretical study to relate uncommon rock/fluid properties to oil recovery. Final report

    Energy Technology Data Exchange (ETDEWEB)

    Watson, R.

    1995-07-01

    Waterflooding is the most commonly used secondary oil recovery technique. One of the requirements for understanding waterflood performance is a good knowledge of the basic properties of the reservoir rocks. This study is aimed at correlating rock-pore characteristics to oil recovery from various reservoir rock types and incorporating these properties into empirical models for Predicting oil recovery. For that reason, this report deals with the analyses and interpretation of experimental data collected from core floods and correlated against measurements of absolute permeability, porosity. wettability index, mercury porosimetry properties and irreducible water saturation. The results of the radial-core the radial-core and linear-core flow investigations and the other associated experimental analyses are presented and incorporated into empirical models to improve the predictions of oil recovery resulting from waterflooding, for sandstone and limestone reservoirs. For the radial-core case, the standardized regression model selected, based on a subset of the variables, predicted oil recovery by waterflooding with a standard deviation of 7%. For the linear-core case, separate models are developed using common, uncommon and combination of both types of rock properties. It was observed that residual oil saturation and oil recovery are better predicted with the inclusion of both common and uncommon rock/fluid properties into the predictive models.

  19. Depletion studies of two contrasting D-2 reefs

    Energy Technology Data Exchange (ETDEWEB)

    Gillund, G.N.; Patel, C.

    1980-01-01

    The Nisku B and G pools are 2 W. Pembina D-2 pools with contrasting reservoir properties. Average porosity, permeability, and maximum thickness are 5%, 130 md, and 95 m; and 16.4%, 7100 md and 19 m, respectively. The results of the depletion model studies of waterflooding and miscible flooding and some of the problems that occurred during these studies are reviewed.

  20. 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.

  1. Hillerslev outcrop chalk

    Energy Technology Data Exchange (ETDEWEB)

    Lykke, M.M.

    2003-08-01

    Fractures are a great benefit to production of oil, since the matrix permeability in the oil bearing chalk reservoirs in the North Sea is low. Many of the oil fields would be marginally economic to produce without natural or induced fractures to enhance the effective permeability of the reservoirs. However, when oil is produced by use of waterflooding, an important issue is whether water fingering (fracture flow) will occur. Water fingering is due to faster flow of water in the fractures than in the matrix during waterflooding. Capillary suction of water (spontaneous or forced) must exist for waterflooding to be economic. If the matrix sucks water from the fractures, waterflooding can be a very efficient mechanism. If not, the waterflooding may fail, since the water will travel directly from the injector to the producer through the fractures, i.e. the result would be recycled water. In my Ph.D., two-phase fracture flow is investigated. The investigation is based on waterflooding tests on fractured outcrop Hillerslev chalk specimens. It is chosen to use Hillerslev outcrop chalk due to that this chalk is highly fractured and that it can be regarded as a close analogue to the oil producing Tor formation of the Valhall field located in the North Sea. To investigate fracture flow, it is important to obtain knowledge of the fractures in the chalk, i.e. it is necessary to perform a fracture study of the chalk. A field trip was made to the Hillerslev outcrop chalk quarry located in the northern part of Jutland. Here, a (global) fracture description was carried out and twelve chalk block samples were recovered at a chosen location in the Hillerslev quarry. For comparison of earlier work performed in the Hillerslev chalk quarry, this report contains a summary of the fracture description and sampling carried out during EFP-98, EFP-96 and earlier work. Measured values of porosity, permeability and capillary pressure curves of Hillerslev outcrop chalk are included to obtain

  2. 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...

  3. Advanced Reservoir Characterization in the Antelope Shale to Establish the Viability of CO2 Enhanced Oil Recovery in California's Monterey Formation Siliceous Shales, Class III

    Energy Technology Data Exchange (ETDEWEB)

    Perri, Pasquale R.

    2001-04-04

    This report describes the evaluation, design, and implementation of a DOE funded CO2 pilot project in the Lost Hills Field, Kern County, California. The pilot consists of four inverted (injector-centered) 5-spot patterns covering approximately 10 acres, and is located in a portion of the field, which has been under waterflood since early 1992. The target reservoir for the CO2 pilot is the Belridge Diatomite. The pilot location was selected based on geology, reservoir quality and reservoir performance during the waterflood. A CO2 pilot was chosen, rather than full-field implementation, to investigate uncertainties associated with CO2 utilization rate and premature CO2 breakthrough, and overall uncertainty in the unproven CO2 flood process in the San Joaquin Valley.

  4. Integrated reservoir characterization of a heterogeneous channel sandstone : the Duchess Lower Manville X pool

    Energy Technology Data Exchange (ETDEWEB)

    Potocki, D.; Raychaudhuri, I.; Thorburn, L. [PanCanadian Petroleum Ltd. (Canada); Galas, C.; King, H.

    1999-01-01

    The Basal Quartz formation of the Duchess Lower Mannville X pool located in southern Alberta was characterized to determine if the reservoir was a good candidate for waterflooding. Twenty performance predictions were run. The Basal Quartz reservoir sandstones have large unanticipated intrawell and interwell variations in log derived porosity and resistivity. An extensive gas cap was also found in most of the wells. Most wells were producing with a high GOR despite the thick oil zone. It was concluded that conversion of selected wells to injection and horizontal infill wells would increase the oil recovery, but due to geological heterogeneity, the gas cap and a high in situ oil viscosity, the pool could not be considered to be a good candidate for waterflooding. 3 refs., 12 figs.

  5. Field experience with floodwater diversion by complexed biopolymers

    Energy Technology Data Exchange (ETDEWEB)

    Abdo, M.K.; Chung, M.S.; Klaric, T.M.; Phelps, C.H.

    1984-04-01

    Due to preferential flow of the injected water through the most permeable zones, waterflooding of stratified reservoirs is generally inefficient. A process for improving the performance of waterfloods in such reservoirs has been developed; it is based on complexing biopolymers with multivalent cations to form gels for selective blocking of water-thief zones, thereby diverting the trailing floodwater to previously under-invaded reservoir regions to recover by-passed oil. This polymeric modification of stratification and of water injection profile leads to increased volumetric sweep of the reservoir by the floodwater and, in turn, to improved oil production. This paper summarizes Mobil's experience in its first seven field projects in Oklahoma using this process. A total of two hundred and five injection wells were treated with complexed biopolymers, resulting in substantial alteration of water flow patterns and in significant incremental oil recovery.

  6. Optimized recovery through cooperative geology and reservoir engineering

    Energy Technology Data Exchange (ETDEWEB)

    Craig, F.F. Jr.; Willcox, P.J.; Ballard, J.R.; Nation, W.R.

    1976-01-01

    Two examples of the use of this combined geology-reservoir engineering technique are taken from the international arena of operations. The first involves a gas reservoir in the U.K.-North Sea waters and the second an oil reservoir in the Gulf of Suez, Egypt. The improved reservoir description obtained for each of these reservoirs is permitting a better assessment of future performance as influenced by various operating alternatives. Waterflooding is relatively tolerant of reservoir nonuniformities. However, the need for additional reserves leads to increased utilization of improved recovery techniques, beyond waterflooding, for secondary as well as tertiary application. The development of better reservoir descriptions will provide guidance on the need for special sweep improvement techniques and ultimately lead to both maximum oil production and reduced risk in application of improved recovery processes.

  7. Well Logging Symposium News

    Institute of Scientific and Technical Information of China (English)

    Yang Chunsheng

    1996-01-01

    @@ ‘96 International Symposium on Well Logging Techniques for Oilfield Development under Waterflood was held on 17-21 September, 1996 in Beijing. The symdrew than 160 experts and scholars in the well logging circle from Russia,The United States, France, Britain, Indonesia and China. About 80 papers were presented duringthe symposium. Mr. Zhang Yongyi,Vice President of CNPC delivered the opening remarks.

  8. Determination of Three-Phase Relative Permeabilities under Reservoir Conditions by Hot Water and Steamflood Experiments Détermination de perméabilités relatives tri-phasiques en conditions de réservoir, à partir d'expériences de balayages à l'eau chaude et à la vapeur

    OpenAIRE

    Quettier L.; Corre B.

    2006-01-01

    In order to help the physical and numerical interpretation of Emeraude's steam pilot, two-phase waterfloods at four temperatures (between 30 and 240°C) and a steamflood were performed in the laboratory using the same porous medium (compacted silt) and under reservoir conditions. Dynamic isothermal displacements were interpreted with a thermal simulator taking into account capillary end effects. The corresponding oil-water relative permeability curves were obtained by matching observed pressur...

  9. Oil recovery with vinyl sulfonic acid-acrylamide copolymers

    Energy Technology Data Exchange (ETDEWEB)

    Norton, C.J.; Falk, D.O.

    1973-12-18

    An aqueous polymer flood containing sulfomethylated alkali metal vinyl sulfonate-acrylamide copolymers was proposed for use in secondary or tertiary enhanced oil recovery. The sulfonate groups on the copolymers sustain the viscosity of the flood in the presence of brine and lime. Injection of the copolymer solution into a waterflooded Berea core, produced 30.5 percent of the residual oil. It is preferred that the copolymers are partially hydrolyzed.

  10. Reservoir Characterization of the Lower Green River Formation, Southwest Uinta Basin, Utah

    Energy Technology Data Exchange (ETDEWEB)

    Morgan, Craig D.; Chidsey, Jr., Thomas C.; McClure, Kevin P.; Bereskin, S. Robert; Deo, Milind D.

    2002-12-02

    The objectives of the study were to increase both primary and secondary hydrocarbon recovery through improved characterization (at the regional, unit, interwell, well, and microscopic scale) of fluvial-deltaic lacustrine reservoirs, thereby preventing premature abandonment of producing wells. The study will encourage exploration and establishment of additional water-flood units throughout the southwest region of the Uinta Basin, and other areas with production from fluvial-deltaic reservoirs.

  11. CHARACTERIZATION OF MIXED WETTABILITY AT DIFFERENT SCALES AND ITS IMPACT ON OIL RECOVERY EFFICIENCY

    Energy Technology Data Exchange (ETDEWEB)

    Mukul M. Sharma; George J. Hirasaki

    2003-09-01

    The objectives of the this research project were to: (1) Quantify the pore scale mechanisms that determine the wettability state of a reservoir; (2) Study the effect of crude oil, brine and mineral compositions in the establishment of mixed wet states; (3) Clarify the effect of mixed-wettability on oil displacement efficiency in waterfloods; and (4) Develop a new tracer technique to measure wettability, fluid distributions, residual saturations and relative permeabilities.

  12. FOR-1: zapping worn-out wells for left-behind oil

    Energy Technology Data Exchange (ETDEWEB)

    Zimmerman, M.D.

    1980-09-25

    This review of enhanced oil recovery predicts oil extracted from old wells will provide over 50% of the US crude production by 1995. Economic incentives and new regulations are encouraging industry's commercialization of enhanced oil recovery techniques. Fire recovery techniques are diagrammed and described: steam blasting, waterflooding, underground burning, chemical altering, and gas mixing. A major breakthrough is the development of a multi-solid, fluidized-bed combustion system for oil-field steam generators.

  13. DATA MINING AT THE NEBRASKA OIL & GAS COMMISSION

    Energy Technology Data Exchange (ETDEWEB)

    James R. Weber

    2001-05-01

    The purpose of this study of the hearing records is to identify factors that are likely to impact the performance of a waterflood in the Nebraska panhandle. The records consisted of 140 cases. Most of the hearings were held prior to 1980. Many of the records were incomplete, and data believed to be key to estimating waterflood performance such as Dykstra-Parson permeability distribution or relative permeability were absent. New techniques were applied to analyze the sparse, incomplete dataset. When information is available, but not clearly understood, new computational intelligence tools can decipher correlations in the dataset. Fuzzy ranking and neural networks were the tools used to estimate secondary recovery from the Cliff Farms Unit. The hearing records include 30 descriptive entries that could influence the success or failure of a waterflood. Success or failure is defined by the ratio of secondary to primary oil recovery (S/P). Primary recovery is defined as cumulative oil produced at the time of the hearing and secondary recovery is defined as the oil produced since the hearing date. Fuzzy ranking was used to prioritize the relevance of 6 parameters on the outcome of the proposed waterflood. The 6 parameters were universally available in 44 of the case hearings. These 44 cases serve as the database used to correlate the following 6 inputs with the respective S/P. (1) Cumulative Water oil ratio, bbl/bbl; (2) Cumulative Gas oil ratio, mcf/bbl; (3) Unit area, acres; (4) Average Porosity, %; (5) Average Permeability, md; (6) Initial bottom hole pressure, psi. A 6-3-1 architecture describes the neural network used to develop a correlation between the 6 input parameters and their respective S/P. The network trained to a 85% correlation coefficient. The predicted Cliff Farms Unit S/P is 0.315 or secondary recovery is expected to be 102,700 bbl.

  14. Application of chlorine dioxide as an oilfield-facilities-treatment fluid

    Energy Technology Data Exchange (ETDEWEB)

    Romaine, J. [Rio Linda Chemical Co., Inc., Sugar Land, TX (United States); Strawser, T.J. [Exxon Co. USA, Gillette, WY (United States); Knippers, M.L. [Nalco/Exxon Energy Chemicals L.P., Sugar Land, TX (United States)

    1996-02-01

    Both mechanical and chemical treatments are used to clean waterflood-injection distribution systems whose efficiency has been reduced as a result of plugging material, such as iron sulfide (FeS) containing sludge. Most mechanical treatments rely on uniform-line diameter to be effective, while chemical treatments require good contact with the plugging material for efficient removal. This paper describes the design and operation of a new innovative application using chlorine dioxide (ClO{sub 2}) for the removal of FeS sludge from waterflood-injection distribution systems. The use of ClO{sub 2} for continuous treatment of injection brines will also be discussed. Exxon USA`s Hartzog Draw facility in Gillette, WY, was the site for the application described. A total of 4,500 bbl of ClO{sub 2} was pumped in three phases to clean 66 miles of the waterflood-distribution system. Results indicated that ClO{sub 2} was effective in cleaning the well guard screens, the injection lines, and the injection wells. The addition of excess ClO{sub 2} to the frac tanks used to collect the treatment fluids also reduced waste handling and disposal costs.

  15. 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.

  16. Coupling the Alkaline-Surfactant-Polymer Technology and The Gelation Technology to Maximize Oil Production

    Energy Technology Data Exchange (ETDEWEB)

    Malcolm Pitts; Jie Qi; Dan Wilson; Phil Dowling; David Stewart; Bill Jones

    2005-12-01

    Performance and produced polymer evaluation of four alkaline-surfactant-polymer projects concluded that only one of the projects could have benefited from combining the alkaline-surfactant-polymer and gelation technologies. Cambridge, the 1993 Daqing, Mellott Ranch, and the Wardlaw alkaline-surfacant-polymer floods were studied. An initial gel treatment followed by an alkaline-surfactant-polymer flood in the Wardlaw field would have been a benefit due to reduction of fracture flow. Numerical simulation demonstrated that reducing the permeability of a high permeability zone of a reservoir with gel improved both waterflood and alkaline-surfactant-polymer flood oil recovery. A Minnelusa reservoir with both A and B sand production was simulated. A and B sands are separated by a shale layer. A sand and B sand waterflood oil recovery was improved by 196,000 bbls or 3.3% OOIP when a gel was placed in the B sand. Alkaline-surfactant-polymer flood oil recovery improvement over a waterflood was 392,000 bbls or 6.5% OOIP. Placing a gel into the B sand prior to an alkaline-surfactant-polymer flood resulted in 989,000 bbl or 16.4% OOIP more oil than only water injection. A sand and B sand alkaline-surfactant-polymer flood oil recovery was improved by 596,000 bbls or 9.9% OOIP when a gel was placed in the B sand.

  17. Thermal EOR requires special design for gravel packs

    Energy Technology Data Exchange (ETDEWEB)

    Weirich, J.B.; Zaleski, T.E.

    1986-11-17

    Successful gravel-packed completions in thermal recovery wells depend upon proper design and selection of downhole equipment. Equipment designed for normal geothermal environments will generally lack the strength necessary to maintain satisfactory performance throughout the life of the well. Due to increased energy demand, domestic energy shortages, and the increasing cost and risk of exploring for new reserves, enchanced oil recovery (EOR) methods have been developed, pilot tested, and applied in many areas. Methods of which allow operators to take advantage of existing wells and surface equipment are particularly economically attractive. With the unstable price of oil in today's market, few EOR projects will economically justify the re-drilling of wells and replacement of surface facilities to increase production. The most popular EOR method employed for the production of heavy crudes is thermal recovery. Productivity is increased by improving oil mobility and transmissibility in the reservoir. Improvement of ultimate recovery and displacement efficiency is also gained through crude oil expansion and more favorable mobility ratios with injected fluids. Thermal recovery processes involve four major methods: hot waterflooding, cyclic steam injection, steam drive, and in situ combustion. The most basic of these is hot water-flooding which is also the least effective of the thermal recovery processes, because the technique merely involves the injection of hot water and can be adapted to a waterflood project with few surface equipment changes.

  18. 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.

  19. Simulation of petroleum recovery in naturally fractured reservoirs: physical process representation

    Energy Technology Data Exchange (ETDEWEB)

    Paiva, Hernani P.; Miranda Filho, Daniel N. de [Petroleo Brasileiro S.A. (PETROBRAS), Rio de Janeiro, RJ (Brazil); Schiozer, Denis J. [Universidade Estadual de Campinas (UNICAMP), SP (Brazil)

    2012-07-01

    The naturally fractured reservoir recovery normally involves risk especially in intermediate to oil wet systems because of the simulations poor efficiency results under waterflood displacement. Double-porosity models are generally used in fractured reservoir simulation and have been implemented in the major commercial reservoir simulators. The physical processes acting in petroleum recovery are represented in double-porosity models by matrix-fracture transfer functions, therefore commercial simulators have their own implementations, and as a result different kinetics and final recoveries are attained. In this work, a double porosity simulator was built with Kazemi et al. (1976), Sabathier et al. (1998) and Lu et al. (2008) transfer function implementations and their recovery results have been compared using waterflood displacement in oil-wet or intermediate-wet systems. The results of transfer function comparisons have showed recovery improvements in oil-wet or intermediate-wet systems under different physical processes combination, particularly in fully discontinuous porous medium when concurrent imbibition takes place, coherent with Firoozabadi (2000) experimental results. Furthermore, the implemented transfer functions, related to a double-porosity model, have been compared to double-porosity commercial simulator model, as well a discrete fracture model with refined grid, showing differences between them. Waterflood can be an effective recovery method even in fully discontinuous media for oil-wet or intermediate-wet systems where concurrent imbibition takes place with high enough pressure gradients across the matrix blocks. (author)

  20. 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.

  1. Use of chlorine dioxide in a secondary recovery process to inhibit bacterial fouling and corrosion

    Energy Technology Data Exchange (ETDEWEB)

    Knickrehm, M.; Caballero, E.; Romualdo, P.; Sandidge, J.

    1987-01-01

    A major oil company operates a secondary recovery waterflood in Inglewood, California. The waterflood currently processes 250,000 bbls. per day of produced fluid. The major economic and operational problems associated with a secondary recovery waterflood are: 1) corrosion due to oxygen, carbon dioxide, hydrogen sulfide, and bacteria (sulfate reducers and slime biomass), 2) plugging from deposits due to salts, sulfides, and biofilms. These problems lead to deterioration of water handling equipment, injection lines (surface and subsurface), and decreased water quality resulting in the plugging of injection wells. During the last 8 years the operator has used varying mechanical and chemical technology to solve these problems. From 1978 to 1982 traditional chemical programs were in effect. Over this time period there was a continuing decline in water quality, and a substantial increase in chemical and operational costs. It was determined at that time that the major reason for this was due to microbiological activity. With this in mind, the operator proceeded to test the effects of using Aqueous Chlorine Dioxide in one portion of their water handling facilities. Due to the success of the program it was applied field wide. Presently, the primary problems associated with bacteria have been arrested. Solving one corrosion problem can lead to the onset of another. The operator is now in the process of making a concentrated effort to eliminate the other synergistically related corrosive and plugging agents (O/sub 2/, CO/sub 2/, H/sub 2/S). A field history of the problems, findings, and solutions, are discussed along with an overview of our present direction.

  2. Synergistic evaluation of a complex conglomerate reservoir for EOR, Barrancas formation, Argentina

    Energy Technology Data Exchange (ETDEWEB)

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

    1985-02-01

    An engineering/geological study of the Top Red Conglomerate (TRC) section of the Barrancas formation, Mendoza area, Argentina, was conducted (1) to evaluate historical waterflood performance and recovery efficiency and (2) to develop a reservoir description and predictive model for later use in evaluation of reservoir response to EOR process applications. Original oil in place (OOIP) in the TRC reservoir was about 400 million STB (63.6 x 10/sup 6/ stock-tank m/sup 3/). The field had produced about 154 million STB (24.5 x 10/sup 6/ stock-tank m/sup 3/) or 38.5% OOIP through 1980 and is under consideration for application of a caustic flooding EOR process. The TRC shows extremely large variations in permeability, both areally and vertically, 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 is governed primarily by the abundance of detrital clays. Reservoir quality also is reduced somewhat in localized areas by the presence of calcite and zeolite cements and by authigenic clays. An abundance of chemically reactive minerals in the formation poses a significant potential for formation damage and/or adverse reactions with injected EOR chemicals. A geological description of layering and areal variability in the reservoir was developed and used to guide the application of a black oil simulator to two cross-sectional models. Simulation of waterflood performance indicated good vertical sweep efficiency near injection wells, with less efficient sweep farther away owing to gravity segregation and an adverse mobility ratio. A preliminary screening and feasibility study evaluated several EOR processes for recovering the oil left after waterflooding. Caustic flooding appeared to be the most feasible EOR process for application in this reservoir.

  3. 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.

  4. Functionalization of micromodels with kaolinite for investigation of low salinity oil-recovery processes.

    Science.gov (United States)

    Song, Wen; Kovscek, Anthony R

    2015-08-21

    Sandstone formations are ubiquitous in both aquifers and petroleum reservoirs, of which clay is a major constituent. The release of clay particles from pore surfaces as a result of reduced injection fluid salinity can greatly modify the recovery of hydrocarbons from subsurface formations by shifting the wettability properties of the rock. In this paper we demonstrate a microfluidic approach whereby kaolinite is deposited into a two-dimensional microfluidic network (micromodel) to enable direct pore-scale, real-time visualization of fluid-solid interactions with representative pore-geometry and realistic surface interactions between the reservoir fluids and the formation rock. Structural characterization of deposited kaolinite particles agrees well with natural modes of occurrence in Berea sandstones; hence, the clay deposition method developed in this work is validated. Specifically, more than 90% of the deposited clay particles formed pore-lining structures and the remainder formed pore bridging structures. Further, regions of highly concentrated clay deposition likely leading to so-called Dalmatian wetting properties were found throughout the micromodel. Two post-deposition treatments are described whereby clay is adhered to the silicon surface reversibly and irreversibly resulting in microfluidic systems that are amenable to studies on (i) the fundamental mechanisms governing the increased oil recovery during low salinity waterfloods and (ii) the effect of a mixed-wet surface on oil recovery, respectively. The reversibly functionalized platform is used to determine the conditions at which stably adhered clay particles detach. Specifically, injection brine salinity below 6000 ppm of NaCl induced kaolinite particle release from the silicon surface. Furthermore, when applied to an aged system with crude oil, the low salinity waterflood recovered an additional 14% of the original oil in place compared to waterflooding with the formation brine.

  5. Evaluation of enhanced recovery operations in Smackover fields of southwest Alabama. Draft topical report on Subtasks 5 and 6

    Energy Technology Data Exchange (ETDEWEB)

    Hall, D.R.

    1992-06-01

    This report contains detailed geologic and engineering information on enhanced-recovery techniques used in unitized Smackover fields in Alabama. The report also makes recommendations on the applicability of these enhanced-recovery techniques to fields that are not now undergoing enhanced recovery. Eleven Smackover fields in Alabama have been unitized. Three fields were unitized specifically to allow the drilling of a strategically placed well to recover uncontacted oil. Two fields in Alabama are undergoing waterflood projects. Five fields are undergoing gas-injection programs to increase the ultimate recovery of hydrocarbons. Silas and Choctaw Ridge fields were unitized but no enhanced-recovery operations have been implemented.

  6. Third Infill Pilot Test in Daqing

    Institute of Scientific and Technical Information of China (English)

    Jiang Dezhen; Wang Chunbo; Linli; Rong Jiashu

    1997-01-01

    @@ Since the Saertu Oilfield of Daqing oil area was put into development in 1960, it has undergone its first two infill adjustments. It is necessary to study the conditions, feasibility and reasonable well network density for the third infill adjustment to be carried out during the Ninth Five Year Plan period, meanwhile, and to explore ways of tapping potentials of the oilfield for the same period, so as to fully tap potential residual oil in various types ofoil reservoirs, increase the producing reserves of oil reservoirs, raise the recoverable reserves, enhance the waterflood recovery efficiency and slow down the production decline in the later stage of high water content period.

  7. Characterization of Mixed Wettability at Different Scales and its Impact on Oil Recovery Efficiency

    Energy Technology Data Exchange (ETDEWEB)

    Sharma, Mukul M.; Hirasaki, George J.

    2002-01-28

    The objectives of this project was to: (1) quantify the pore scale mechanisms that determine the wettability state of a reservoir, (2) study the effect of crude oil, brine and mineral compositions in the establishment of mixed wet states, (3) clarify the effect of mixed - wettability on oil displacement efficiency in waterfloods, (4) develop a new tracer technique to measure wettability, fluid distributions, residual saturation's and relative permeabilities, and (5) develop methods for properly incorporating wettability in up-scaling from pore to core to reservoir scales.

  8. Characteristics of operation and possible oil recovery from the sixth formation of Arlansk oil field. [USSR

    Energy Technology Data Exchange (ETDEWEB)

    Viktorov, P.F.; Teterev, I.G.

    1970-01-01

    This field is characterized by complex geological variations, high viscosity oil (16 to 39 cp), and extreme heterogeneity. The field has been under a peripheral waterflood for 10 yr, however even at high water-cut (50 to 75%), only 40% of the reserve has been recovered. The high water-cut results from premature water breakthrough in high-permeability zones and from water coning. As cumulative oil recovery increases, water production increases exponentially. Oil recovery can be increased only 3 to 4%, by increasing the removal of fluids from wells. Consideration is being given to use of hot water and high-pressure gas to increase oil recovery.

  9. An Integrated Study of the Grayburg/San Andres Reservoir, Foster and South Cowden Fields, Ector County, Texas, Class II

    Energy Technology Data Exchange (ETDEWEB)

    Trentham, Robert C.; Weinbrandt, Richard; Robinson, William C.; Widner, Kevin

    2001-05-03

    The objectives of the project were to: (1) Thoroughly understand the 60-year history of the field. (2) Develop a reservoir description using geology and 3D seismic. (3) Isolate the upper Grayburg in wells producing from multiple intervals to stop cross flow. (4) Re-align and optimize the upper Grayburg waterflood. (5) Determine well condition, identify re-frac candidates, evaluate the effectiveness of well work and obtain bottom hole pressure data for simulation utilizing pressure transient testing field wide. (6) Quantitatively integrate all the data to guide the field operations, including identification of new well locations utilizing reservoir simulation.

  10. 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.

  11. Measuring and Modeling the Displacement of Connate Water in Chalk Core Plugs during Water Injection

    DEFF Research Database (Denmark)

    Korsbech, Uffe C C; Aage, Helle Karina; Andersen, Bertel Lohmann;

    2006-01-01

    The movement of connate water spiked with gamma emitting 22Na was studied during laboratory water flooding of oil saturated chalk from a North Sea oil reservoir. Using a one dimensional gamma monitoring technique is was observed that connate water is piled-up at the front of the injection water...... and forms a mixed water bank with almost 100% connate water in the front behind which a gradual transition to pure injection water occurs. This result underpins log interpretations from waterflooded chalk reservoirs. An ad hoc model was set up by use of the results, and the process was examined...

  12. Druzhba feasibility study: Barsukov and Tarasov fields, 1995. Workover procedures. Export trade information

    Energy Technology Data Exchange (ETDEWEB)

    NONE

    1996-01-03

    The study, conducted by NEFT, was funded by the U.S. Trade and Development Agency. The report shows the results of a feasibility study conducted for the rehabilitation of oil wells in Baruskov and Tarasov fields. The objectives of the study include a plan for improving well and waterflood performance, and to determine materials and equipment needed. The report also covers capital and operating costs, as well as an evaluation of project economics based on Russian law. This is Volume 3 of the study containing the Workover Procedures for wells in both Barsukov and Tarasov fields.

  13. Druzhba feasibility study: Barsukov and Tarasov fields, 1995. Main report. Export trade information

    Energy Technology Data Exchange (ETDEWEB)

    NONE

    1996-01-03

    The study, conducted by NEFT, was funded by the U.S. Trade and Development Agency. The report shows the results of a feasibility study conducted for the rehabilitation of oil wells in Baruskov and Tarasov fields. The objectives of the study include a plan for improving well and waterflood performance, and to determine materials and equipment needed. The report also covers capital and operating costs, as well as an evaluation of project economics based on Russian law. This is Volume 1 of the study containing the Main Report. It is divided into the following sections: (1) Figures; (2) Tables; (3) Economic Tables; (4) Maps; (5) Environmental Safety.

  14. Dynamic up-scaling of relative permeability in chalk

    Energy Technology Data Exchange (ETDEWEB)

    Frykman, P.; Lindgaard, H.F.

    1997-12-31

    This paper describes how fine-scale geo-statistic reservoir models can be utilised for the up-scaling of two-phase flow properties, including both relative permeability and capillary pressure function. The procedure is applied to a North Sea chalk carbonate reservoir example, which is a high-porosity/low-permeability reservoir type. The study focuses on waterflooding as the main recovery scheme and for the given flow regime in the reservoir. The main purpose of the paper is to demonstrate the use of dynamic multi-step up-scaling methods in the preparation of detailed geological information for full field reservoir simulation studies. (au) EFP-96. 39 refs.

  15. Kaolinite and Silica Dispersions in Low-Salinity Environments: Impact on a Water-in-Crude Oil Emulsion Stability

    Directory of Open Access Journals (Sweden)

    Vladimir Alvarado

    2011-10-01

    Full Text Available This research aims at providing evidence of particle suspension contributions to emulsion stability, which has been cited as a contributing factor in crude oil recovery by low-salinity waterflooding. Kaolinite and silica particle dispersions were characterized as functions of brine salinity. A reference aqueous phase, representing reservoir brine, was used and then diluted with distilled water to obtain brines at 10 and 100 times lower Total Dissolved Solid (TDS. Scanning Electron Microscope (SEM and X-ray Diffraction (XRD were used to examine at the morphology and composition of clays. The zeta potential and particle size distribution were also measured. Emulsions were prepared by mixing a crude oil with brine, with and without dispersed particles to investigate emulsion stability. The clay zeta potential as a function of pH was used to investigate the effect of particle charge on emulsion stability. The stability was determined through bottle tests and optical microscopy. Results show that both kaolinite and silica promote emulsion stability. Also, kaolinite, roughly 1 mm in size, stabilizes emulsions better than larger clay particles. Silica particles of larger size (5 µm yielded more stable emulsions than smaller silica particles do. Test results show that clay particles with zero point of charge (ZPC at low pH become less effective at stabilizing emulsions, while silica stabilizes emulsions better at ZPC. These result shed light on emulsion stabilization in low-salinity waterflooding.

  16. Optimization of supplementary recovery projects for mature fields; Otimizacao de projetos de recuperacao suplementar para campos com alto grau de explotacao

    Energy Technology Data Exchange (ETDEWEB)

    Marsili, Marcelo D.; Castineira, Paula P.; Couto, Paulo; Sa Neto, Abelardo de; Ferreira Filho, Virgilio J.M. Ferreira Filho [Universidade Federal do Rio de Janeiro, RJ (Brazil). Curso de Engenharia de Petroleo

    2008-07-01

    Development of mature oil fields has been a key issue in a world scenario of high crude oil prices, declining reserves and political instability in the main producing regions. This paper proposes a discussion about different secondary recovery projects for a hypothetical mature field subjected to water injection into the reservoir. The reservoir model was built using a numeric black oil simulator, taking into account several heterogeneities associated to real reservoirs, thus being able to predict near-realistic performances. The model was implemented and it was simulated a primary production for 11 years under solution gas drive and weak water influx and gas cap drive mechanisms. During the course of production, reservoir pressure decreased substantially. Five waterflooding projects were suggested as a remedy to restore the reservoir pressure and well productivities. Results were obtained by numerical simulation and compared by the net present value (NPV) economic criteria of project analysis. After the simulation of 36 years of production considering waterflooding, the most attractive project proved to be the five-spot pattern, with a 40% estimated oil recovery and 60 million dollars NPV for a fixed crude oil price of 70 dollars per barrel. (author)

  17. Characterization and estimation of permeability correlation structure from performance data

    Energy Technology Data Exchange (ETDEWEB)

    Ershaghi, I.; Al-Qahtani, M. [Univ. of Southern California, Los Angeles, CA (United States)

    1997-08-01

    In this study, the influence of permeability structure and correlation length on the system effective permeability and recovery factors of 2-D cross-sectional reservoir models, under waterflood, is investigated. Reservoirs with identical statistical representation of permeability attributes are shown to exhibit different system effective permeability and production characteristics which can be expressed by a mean and variance. The mean and variance are shown to be significantly influenced by the correlation length. Detailed quantification of the influence of horizontal and vertical correlation lengths for different permeability distributions is presented. The effect of capillary pressure, P{sub c1} on the production characteristics and saturation profiles at different correlation lengths is also investigated. It is observed that neglecting P{sub c} causes considerable error at large horizontal and short vertical correlation lengths. The effect of using constant as opposed to variable relative permeability attributes is also investigated at different correlation lengths. Next we studied the influence of correlation anisotropy in 2-D reservoir models. For a reservoir under five-spot waterflood pattern, it is shown that the ratios of breakthrough times and recovery factors of the wells in each direction of correlation are greatly influenced by the degree of anisotropy. In fully developed fields, performance data can aid in the recognition of reservoir anisotropy. Finally, a procedure for estimating the spatial correlation length from performance data is presented. Both the production performance data and the system`s effective permeability are required in estimating the correlation length.

  18. Chemical enhanced recovery of heavy oil

    Energy Technology Data Exchange (ETDEWEB)

    Soveran, D.W.; Scoular, R.J.; Kurucz, L.; Renouf, G.; Verkoczy, B. [Saskatchewan Research Council, Regina, SK (Canada)

    2003-09-01

    A unique chemical/emulsion enhanced oil recovery (EOR) process was laboratory tested to determine its suitability for field demonstration purposes in 3 heavy oil reservoirs in the Lloydminster area of Saskatchewan. The promising chemical agents for the process were identified and optimized. The 3 reservoirs selected represented a cross-section of crude oil qualities typical for the region. The ultimate objective was to develop a process to replace waterflooding as the standard for post-primary production. Several modified core screening tests were conducted to formulate a chemical mixture for the lowest viscosity crude oil. This proved to be the best candidate among the 3 reservoirs. The mixture resulted in additional oil recovery of 26 per cent original oil in place, which is better than a typical waterflood. Two conventional core displacement tests confirmed the success of the modified core flood method. A new polymer was then used in combination with the new coreflood method to produce an additional oil recovery of 30 per cent. Laboratory studies indicate that the lowest viscosity crude oil field is a good candidate for the chemical EOR field study. Results show that the method can recover even the most highly viscous crude oil at a cost below C$10 per barrel. The field shows good potential for chemical EOR even though produced water from the reservoir formed heavy precipitate. 3 tabs., 6 figs.

  19. Reservoir-on-a-chip (ROC): a new paradigm in reservoir engineering.

    Science.gov (United States)

    Gunda, Naga Siva Kumar; Bera, Bijoyendra; Karadimitriou, Nikolaos K; Mitra, Sushanta K; Hassanizadeh, S Majid

    2011-11-21

    In this study, we design a microfluidic chip, which represents the pore structure of a naturally occurring oil-bearing reservoir rock. The pore-network has been etched in a silicon substrate and bonded with a glass covering layer to make a complete microfluidic chip, which is termed as 'Reservoir-on-a-chip' (ROC). Here we report, for the first time, the ability to perform traditional waterflooding experiments in a ROC. Oil is kept as the resident phase in the ROC, and waterflooding is performed to displace the oil phase from the network. The flow visualization provides specific information about the presence of the trapped oil phase and the movement of the oil/water interface/meniscus in the network. The recovery curve is extracted based on the measured volume of oil at the outlet of the ROC. We also provide the first indication that this oil-recovery trend realized at chip-level can be correlated to the flooding experiments related to actual reservoir cores. Hence, we have successfully demonstrated that the conceptualized 'Reservoir-on-a-Chip' has the features of a realistic pore-network and in principle is able to perform the necessary flooding experiments that are routinely done in reservoir engineering.

  20. Application of 'BIPI' tests employing natural and artificial tracers in water flooded oil fields of the Neuquina Basin (Argentine)

    Energy Technology Data Exchange (ETDEWEB)

    Somaruga, C. [Comahue Univ., Engineering Dept., Neuquen (Argentina); Gazzera, C.; Wouterlood, C. [Petrolera Perez Companc SA. Area Entre Lomas., Neuquen (Argentina)

    2001-07-01

    A methodology to determine the origin and distribution of bottom water in an oil producing well influenced by several injectors in waterflooding projects is presented. This methodology is complementary of inter-well tracer tests and salinity records analysis and was denominated BIPI (brief interruptions of producing-injecting wells) test. It requires the closing of a well (injector or producer) during a short time and its later re-opening. The original flow pattern in the surroundings of the tested producing well is affected while the well is closed. So the water coming from a dominant injector can move forward invading areas of a layer that have been previously occupied by other waters. Once the well is re-opened, if there is a tracer concentration contrast between the waters, a concentration change is registered. The concentration change was measured and also its recurrence in waters produced during inter-well tracer tests and during waterflooding that are employing different injection water from the formation one. Also it was determined the original flow distribution in the surrounding of the producing well by means of a simple balance of tracer mass. It is presented and analyze here the results from tests that were performed in an oil field of the Neuquina Basin. They allowed to visualizing the current condition of the bottom water flow as well as to make predictions on future performance. (authors)

  1. Bridging the Gap between Chemical Flooding and Independent Oil Producers

    Energy Technology Data Exchange (ETDEWEB)

    Stan McCool; Tony Walton; Paul Whillhite; Mark Ballard; Miguel Rondon; Kaixu Song; Zhijun Liu; Shahab Ahmed; Peter Senior

    2012-03-31

    Ten Kanas oil reservoirs/leases were studied through geological and engineering analysis to assess the potential performance of chemical flooding to recover oil. Reservoirs/leases that have been efficiently waterflooded have the highest performance potential for chemical flooding. Laboratory work to identify efficient chemical systems and to test the oil recovery performance of the systems was the major effort of the project. Efficient chemical systems were identified for crude oils from nine of the reservoirs/leases. Oil recovery performance of the identified chemical systems in Berea sandstone rocks showed 90+ % recoveries of waterflood residual oil for seven crude oils. Oil recoveries increased with the amount of chemical injected. Recoveries were less in Indiana limestone cores. One formulation recovered 80% of the tertiary oil in the limestone rock. Geological studies for nine of the oil reservoirs are presented. Pleasant Prairie, Trembley, Vinland and Stewart Oilfields in Kansas were the most favorable of the studied reservoirs for a pilot chemical flood from geological considerations. Computer simulations of the performance of a laboratory coreflood were used to predict a field application of chemical flooding for the Trembley Oilfield. Estimates of field applications indicated chemical flooding is an economically viable technology for oil recovery.

  2. An exogenous surfactant-producing Bacillus subtilis facilitates indigenous microbial enhanced oil recovery

    Directory of Open Access Journals (Sweden)

    Peike eGao

    2016-02-01

    Full Text Available This study used an exogenous lipopeptide-producing Bacillus subtilis to strengthen the indigenous microbial enhanced oil recovery (IMEOR process in a water-flooded reservoir in the laboratory. The microbial processes and driving mechanisms were investigated in terms of the changes in oil properties and the interplay between the exogenous Bacillus subtilis and indigenous microbial populations. The exogenous Bacillus subtilis is a lipopeptide producer, with a short growth cycle and no oil-degrading ability. The Bacillus subtilis facilitates the IMEOR process through improving oil emulsification and accelerating microbial growth with oil as the carbon source. Microbial community studies using quantitative PCR and high-throughput sequencing revealed that the exogenous Bacillus subtilis could live together with reservoir microbial populations, and did not exert an observable inhibitory effect on the indigenous microbial populations during nutrient stimulation. Core-flooding tests showed that the combined exogenous and indigenous microbial flooding increased oil displacement efficiency by 16.71%, compared with 7.59% in the control where only nutrients were added, demonstrating the application potential in enhanced oil recovery in water-flooded reservoirs, in particular, for reservoirs where IMEOR treatment cannot effectively improve oil recovery.

  3. Engineering Behavior and Characteristics of Water-Soluble Polymers: Implication on Soil Remediation and Enhanced Oil Recovery

    Directory of Open Access Journals (Sweden)

    Shuang Cindy Cao

    2016-02-01

    Full Text Available Biopolymers have shown a great effect in enhanced oil recovery because of the improvement of water-flood performance by mobility control, as well as having been considered for oil contaminated-soil remediation thanks to their mobility control and water-flood performance. This study focused on the wettability analysis of biopolymers such as chitosan (85% deacetylated power, PEO (polyethylene oxide, Xanthan (xanthan gum, SA (Alginic Acid Sodium Salt, and PAA (polyacrylic acid, including the measurements of contact angles, interfacial tension, and viscosity. Furthermore, a micromodel study was conducted to explore pore-scale displacement phenomena during biopolymer injection into the pores. The contact angles of biopolymer solutions are higher on silica surfaces submerged in decane than at atmospheric conditions. While interfacial tensions of the biopolymer solutions have a relatively small range of 25 to 39 mN/m, the viscosities of biopolymer solutions have a wide range, 0.002 to 0.4 Pa·s, that dramatically affect both the capillary number and viscosity number. Both contact angles and interfacial tension have effects on the capillary entry pressure that increases along with an applied effective stress by overburden pressure in sediments. Additionally, a high injection rate of biopolymer solutions into the pores illustrates a high level of displacement ratio. Thus, oil-contaminated soil remediation and enhanced oil recovery should be operated in cost-efficient ways considering the injection rates and capillary entry pressure.

  4. An Exogenous Surfactant-Producing Bacillus subtilis Facilitates Indigenous Microbial Enhanced Oil Recovery.

    Science.gov (United States)

    Gao, Peike; Li, Guoqiang; Li, Yanshu; Li, Yan; Tian, Huimei; Wang, Yansen; Zhou, Jiefang; Ma, Ting

    2016-01-01

    This study used an exogenous lipopeptide-producing Bacillus subtilis to strengthen the indigenous microbial enhanced oil recovery (IMEOR) process in a water-flooded reservoir in the laboratory. The microbial processes and driving mechanisms were investigated in terms of the changes in oil properties and the interplay between the exogenous B. subtilis and indigenous microbial populations. The exogenous B. subtilis is a lipopeptide producer, with a short growth cycle and no oil-degrading ability. The B. subtilis facilitates the IMEOR process through improving oil emulsification and accelerating microbial growth with oil as the carbon source. Microbial community studies using quantitative PCR and high-throughput sequencing revealed that the exogenous B. subtilis could live together with reservoir microbial populations, and did not exert an observable inhibitory effect on the indigenous microbial populations during nutrient stimulation. Core-flooding tests showed that the combined exogenous and indigenous microbial flooding increased oil displacement efficiency by 16.71%, compared with 7.59% in the control where only nutrients were added, demonstrating the application potential in enhanced oil recovery in water-flooded reservoirs, in particular, for reservoirs where IMEOR treatment cannot effectively improve oil recovery.

  5. 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.

  6. Water injection in various fields of Argentina

    Energy Technology Data Exchange (ETDEWEB)

    1969-10-01

    Two successful pilot flood tests conducted in the Argentine oil fields have been sufficiently successful to indicate to Yacimientos Petroliferos Fiscales (YPF) that many other fields having similar reservoir characteristics would respond well to waterflooding. In 1966, YPF contracted with companies specializing in secondary recovery to make a study of these 4 reservoirs: Canadon Leon, in Santa Cruz, to the south of Comodoro Rivadavia; Barrancas South, in Mendoza; and El Sauce and Cerro Bandera, both in Neuquen (as indicated on the base map). These studies revealed which of the formations were most likely to respond to water injection. For Canadon Leon and Barrancas, pilot operations were recommended, while for the others, water injection on a large scale was recommended. The scheme of large-scale waterflooding for Cerro Bandera (Neuquen) and El Sauce (Neuquen) is illustrated. In Canadon Leon and Barrancas alone, secondary recovery is expected to increase the oil recovery to around 3,500,000 bbl; of this total 1,327,282 is primary and 2,190,000 is secondary recovery. Tabular data show the anticipated results of water injection in the 4 studied fields.

  7. Bridging the Gap between Chemical Flooding and Independent Oil Producers

    Energy Technology Data Exchange (ETDEWEB)

    Stan McCool; Tony Walton; Paul Willhite; Mark Ballard; Miguel Rondon; Kaixu Song; Zhijun Liu; Shahab Ahmend; Peter Senior

    2012-03-31

    Ten Kanas oil reservoirs/leases were studied through geological and engineering analysis to assess the potential performance of chemical flooding to recover oil. Reservoirs/leases that have been efficiently waterflooded have the highest performance potential for chemical flooding. Laboratory work to identify efficient chemical systems and to test the oil recovery performance of the systems was the major effort of the project. Efficient chemical systems were identified for crude oils from nine of the reservoirs/leases. Oil recovery performance of the identified chemical systems in Berea sandstone rocks showed 90+ % recoveries of waterflood residual oil for seven crude oils. Oil recoveries increased with the amount of chemical injected. Recoveries were less in Indiana limestone cores. One formulation recovered 80% of the tertiary oil in the limestone rock. Geological studies for nine of the oil reservoirs are presented. Pleasant Prairie, Trembley, Vinland and Stewart Oilfields in Kansas were the most favorable of the studied reservoirs for a pilot chemical flood from geological considerations. Computer simulations of the performance of a laboratory coreflood were used to predict a field application of chemical flooding for the Trembley Oilfield. Estimates of field applications indicated chemical flooding is an economically viable technology for oil recovery.

  8. Study of the Effect of Clay Particles on Low Salinity Water Injection in Sandstone Reservoirs

    Directory of Open Access Journals (Sweden)

    Sina Rezaei Gomari

    2017-03-01

    Full Text Available The need for optimal recovery of crude oil from sandstone and carbonate reservoirs around the world has never been greater for the petroleum industry. Water-flooding has been applied to the supplement primary depletion process or as a separate secondary recovery method. Low salinity water injection is a relatively new method that involves injecting low salinity brines at high pressure similar to conventional water-flooding techniques, in order to recover crude oil. The effectiveness of low salinity water injection in sandstone reservoirs depends on a number of parameters such as reservoir temperature, pressure, type of clay particle and salinity of injected brine. Clay particles present on reservoir rock surfaces adsorb polar components of oil and modify wettability of sandstone rocks to the oil-wet state, which is accountable for the reduced recovery rates by conventional water-flooding. The extent of wettability alteration caused by three low salinity brines on oil-wet sandstone samples containing varying clay content (15% or 30% and type of clay (kaolinite/montmorillonite were analyzed in the laboratory experiment. Contact angles of mica powder and clay mixture (kaolinite/montmorillonite modified with crude oil were measured before and after injection with three low salinity sodium chloride brines. The effect of temperature was also analyzed for each sample. The results of the experiment indicate that samples with kaolinite clay tend to produce higher contact angles than samples with montmorillonite clay when modified with crude oil. The highest degree or extent of wettability alteration from oil-wet to intermediate-wet state upon injection with low salinity brines was observed for samples injected with brine having salinity concentration of 2000 ppm. The increase in temperature tends to produce contact angles values lying in the higher end of the intermediate-wet range (75°–115° for samples treated at 50 °C, while their corresponding

  9. GEOGRAPHIC INFORMATION SYSTEM APPROACH FOR PLAY PORTFOLIOS TO IMPROVE OIL PRODUCTION IN THE ILLINOIS BASIN

    Energy Technology Data Exchange (ETDEWEB)

    Beverly Seyler; John Grube

    2004-12-10

    . Data from over 1,700 Illinois waterflood units and waterflood areas have been entered into an Access{reg_sign} database. The waterflood area data has also been assimilated into the ISGS Oracle database for mapping and dissemination on the ArcIMS website. Formation depths for the Beech Creek Limestone, Ste. Genevieve Limestone and New Albany Shale in all of the oil producing region of Illinois have been calculated and entered into a digital database. Digital contoured structure maps have been constructed, edited and added to the ILoil website as map layers. This technology/methodology addresses the long-standing constraints related to information access and data management in Illinois by significantly simplifying the laborious process that industry presently must use to identify underdeveloped pay zones in Illinois.

  10. Mechanistic study of wettability alteration using surfactants with applications in naturally fractured reservoirs.

    Science.gov (United States)

    Salehi, Mehdi; Johnson, Stephen J; Liang, Jenn-Tai

    2008-12-16

    In naturally fractured reservoirs, oil recovery from waterflooding relies on the spontaneous imbibition of water to expel oil from the matrix into the fracture system. The spontaneous imbibition process is most efficient in strongly water-wet rock where the capillary driving force is strong. In oil- or mixed-wet fractured carbonate reservoirs, however, the capillary driving force for the spontaneous imbibition process is weak, and therefore the waterflooding oil recoveries are low. The recovery efficiency can be improved by dissolving low concentrations of surfactants in the injected water to alter the wettability of the reservoir rock to a more water-wet state. This wettability alteration accelerates the spontaneous imbibition of water into matrix blocks, thereby increasing the oil recovery during waterflooding. Several mechanisms have been proposed to explain the wettability alteration by surfactants, but none have been verified experimentally. Understanding of the mechanisms behind wettability alteration could help to improve the performance of the process and aid in identification of alternative surfactants for use in field applications. Results from this study revealed that ion-pair formation and adsorption of surfactant molecules through interactions with the adsorbed crude oil components on the rock surface are the two main mechanisms responsible for the wettability alteration. Previous researchers observed that, for a given rock type, the effectiveness of wettability alteration is highly dependent upon the ionic nature of the surfactant involved. Our experimental results demonstrated that ion-pair formation between the charged head groups of surfactant molecules and the adsorbed crude oil components on rock surface was more effective in changing the rock wettability toward a more water-wet state than the adsorption of surfactant molecules as a monolayer on the rock surface through hydrophobic interaction with the adsorbed crude oil components. By comparing

  11. EVALUATION OF THE FLOOD POTENTIAL OF THE SOUTH HOUSE (BLINEBRY) FIELD, LEA COUNTY, NEW MEXICO

    Energy Technology Data Exchange (ETDEWEB)

    L. Stephen Melzer

    2000-12-01

    The Blinebry (Permian) formation of eastern Lea County, NM has a long history of exploitation for petroleum and continues even today to be a strong target horizon for new drilling in the Permian Basin. Because of this long-standing interest it should be classified of strategic interest to domestic oil production; however, the formation has gained a reputation as a primary production target with limited to no flooding potential. In late May of 1999, a project to examine the feasibility of waterflooding the Blinebry formation was proposed to the U.S. Department of Energy's National Petroleum Technology Office (Tulsa, OK). A new well was proposed in one region (the South House area) to examine the reputation by acquiring core and borehole logging data for the collection of formation property data in order to conduct the waterflood evaluation. Notice of the DOE award was received on August 19, 1999 and the preparations for drilling, coring and logging were immediately made for a drilling start on 9/9/99. The Blinebry formation at 6000 feet, foot depth was reached on 9/16/99 and the coring of two 60 foot intervals of the Blinebry was completed on 9/19/99 with more than 98% core recovery. The well was drilled to a total depth of 7800 feet and the Blinebry interval was logged with spectral gamma ray, photoelectric cross section, porosity, resistivity, and borehole image logs on 8/24/99. The well was determined to be likely productive from the Blinebry interval and five & 1/2 inch casing was cemented in the hole on 9/25/99. Detailed core descriptions including environment of deposition have been accomplished. Whole core (a 4-inch diameter) and plug (1.5 inch diameter) testing for formation properties has been completed and are reported. Acquisition and analysis of the borehole logging results have been completed and are reported. Perforation of the Blinebry intervals was accomplished on November 8, 1999. The intervals were acidized and hydrofraced on 11/9 and 11

  12. 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.

  13. Rock Physics of Reservoir Rocks with Varying Pore Water Saturation and Pore Water Salinity

    DEFF Research Database (Denmark)

    Katika, Konstantina

    be performed on specific geological structures and why it is sometimes successful; has yet to be established. The presence of both oil and water in the pore space, several different ions present in the injected water that contact the pore walls, possible changes in the fluid wetting the surface of the grains......Advanced waterflooding (injection of water with selective ions in reservoirs) is a method of enhanced oil recovery (EOR) that has attracted the interest of oil and gas companies that exploit the Danish oil and gas reservoirs. This method has been applied successfully in oil reservoirs...... and in the Smart Water project performed in a laboratory scale in order to evaluate the EOR processes in selected core plugs. A major step towards this evaluation is to identify the composition of the injected water that leads to increased oil recovery in reservoirs and to define changes in the petrophysical...

  14. Economic Recovery of Oil Trapped at Fan Margins Using High Angle Wells and Multiple Hydraulic Fractures

    Energy Technology Data Exchange (ETDEWEB)

    Mike L. Laue

    1997-05-30

    The distal fan margin in the northeast portion of the Yowlumne field contains significant reserves but is not economical to develop using vertical wells. Numerous interbedded shales and deteriorating rock properties limit producibility. In addition, extreme depths (13,000 ft) present a challenging environment for hydraulic fracturing and artificial lift. Lastly, a mature waterflood increases risk because of the uncertainty with size and location of flood fronts. This project attempts to demonstrate the effectiveness of exploiting the distal fan margin of this slope-basin clastic reservoir through the use of a high-angle well completed with multiple hydraulic-fracture treatments. The combination of a high-angle (or horizontal) well and hydraulic fracturing will allow greater pay exposure than can be achieved with conventional vertical wells while maintaining vertical communication between thin interbedded layers and the wellbore. The equivalent production rate and reserves of three vertical wells are anticipated at one-half to two-thirds the cost.

  15. In situ permeability modification using gelled polymer systems. Annual report, April 11, 1997--April 10, 1998

    Energy Technology Data Exchange (ETDEWEB)

    Green, D.W.; Willhite, G.P.; McCool, C.S.; Heppert, J.A.; Vossoughi, S.; Michnick, M.J.

    1998-09-01

    Results from a research program on the application of gelled polymer technology for in situ permeability modification are presented in this report. The objective of this technology when used with displacement processes such as waterflooding is to reduce the permeability in fractures and/or high permeability matrix zones to improve volumetric sweep efficiency of the displacement process. In production wells, the objective is to reduce water influx. The research program focused on five areas: Gel treatment in fractured systems; Gel treatment in carbonate rocks; In-depth placement of gels; Gel systems for application in carbon dioxide flooding; and Gel treatment in production wells. The research program is primarily an experimental program directed toward improving the understanding of gelled polymer systems and how these systems can be used to increase oil recovery from petroleum reservoirs. A summary of progress for research conducted in the second 12 month period of a 28 month program is described.

  16. In situ permeability modification using gelled polymer systems. Topical report, June 10, 1996--April 10, 1997

    Energy Technology Data Exchange (ETDEWEB)

    Green, D.W.; Willhite, G.P.; McCool, C.S.; Heppert, J.A.; Vossoughi, S.

    1997-10-01

    Results from a research program on the application of gelled polymer technology for in situ permeability modification are presented in this report. The objective of this technology when used with displacement processes such as waterflooding is to reduce the permeability in fractures and/or high permeability matrix zones to improve volumetric sweep efficiency of the displacement process. In production wells, the objective is to reduce water influx. The research program is focused on five areas: gel treatment in fractured systems; gel treatment in carbonate rocks; in-depth placement of gels; gel systems for application in carbon dioxide flooding; and gel treatment in production wells. The research program is primarily an experimental program directed at improving the understanding of gelled polymer systems and how these systems can be used to increase oil recovery from petroleum reservoirs. A summary of progress for research conducted in the first 10 months of a 28 month program is described in the following sections.

  17. Microbial enhanced oil recovery: Entering the log phase

    Energy Technology Data Exchange (ETDEWEB)

    Bryant, R.S.

    1995-12-31

    Microbial enhanced oil recovery (MEOR) technology has advanced internationally since 1980 from a laboratory-based evaluation of microbial processes to field applications. In order to adequately support the decline in oil production in certain areas, research on cost-effective technologies such as microbial enhanced oil recovery processes must focus on both near-term and long-term applications. Many marginal wells are desperately in need of an inexpensive improved oil recovery technology today that can assist producers in order to prevent their abandonment. Microbial enhanced waterflooding technology has also been shown to be an economically feasible technology in the United States. Complementary environmental research and development will also be required to address any potential environmental impacts of microbial processes. In 1995 at this conference, the goal is to further document and promote microbial processes for improved oil recovery and related technology for solving environmental problems.

  18. Advanced Reservoir Characterization and Development through High-Resolution 3C3D Seismic and Horizontal Drilling: Eva South Marrow Sand Unit, Texas County, Oklahoma

    Energy Technology Data Exchange (ETDEWEB)

    Wheeler,David M.; Miller, William A.; Wilson, Travis C.

    2002-03-11

    The Eva South Morrow Sand Unit is located in western Texas County, Oklahoma. The field produces from an upper Morrow sandstone, termed the Eva sandstone, deposited in a transgressive valley-fill sequence. The field is defined as a combination structural stratigraphic trap; the reservoir lies in a convex up -dip bend in the valley and is truncated on the west side by the Teepee Creek fault. Although the field has been a successful waterflood since 1993, reservoir heterogeneity and compartmentalization has impeded overall sweep efficiency. A 4.25 square mile high-resolution, three component three-dimensional (3C3D) seismic survey was acquired in order to improve reservoir characterization and pinpoint the optimal location of a new horizontal producing well, the ESU 13-H.

  19. 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.

  20. Branched alkyl alcohol propoxylated sulfate surfactants for improved oil recovery

    Energy Technology Data Exchange (ETDEWEB)

    Wu, Y.; Iglauer, S.; Shuler, P.; Tang, Y. [California Institute of Technology, Covina, CA (US). Power, Environmental and Energy Research (PEER) Center; Goddard, W.A. III [California Institute of Technology, Pasadena, CA (United States). Materials and Process Simulation Center

    2010-05-15

    This investigation considers branched alkyl alcohol propoxylated sulfate surfactants as candidates for chemical enhanced oil recovery (EOR) applications. Results show that these anionic surfactants may be preferred candidates for EOR as they can be effective at creating low interfacial tension (IFT) at dilute concentrations, without requiring an alkaline agent or cosurfactant. In addition, some of the formulations exhibit a low IFT at high salinity, and hence may be suitable for use in more saline reservoirs. Adsorption tests onto kaolinite clay indicate that the loss of these surfactants can be comparable to or greater than other types of anionic surfactants. Surfactant performance was evaluated in oil recovery core flood tests. Selected formulations recovered 35-50% waterflood residual oil even with dilute 0.2 wt% surfactant concentrations from Berea sandstone cores. (orig.)

  1. Applications of advanced petroleum production technology and water alternating gas injection for enhanced oil recovery: Mattoon Oil Field, Illinois. Third quarterly report, [July--September 1993

    Energy Technology Data Exchange (ETDEWEB)

    Baroni, M.R.

    1993-12-21

    The objectives of this project are to continue reservoir characterization of the Cypress Sandstone; to identify and map facies-defined waterflood units (FDWS); and to design and implement water-alternating-gas (WAG) oil recovery utilizing carbon dioxide (CO{sub 2}) The producibility problems are permeability variation and poor sweep efficiency. Part 1 of the project focuses on the development of computer-generated geological and reservoir simulation models that will be used to select sites for the demonstration and implementation of CO{sub 2} displacement programs in Part 2. Included in Part 1 is the site selection and drilling of an infill well, coring of the Cypress interval, and injectivity testing to gather information used to update the reservoir simulation model. Part 2 involves field implementation of WAG. Technology Transfer includes outreach activity such as seminars, workshops, and field trips.

  2. 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.

  3. The method of the spatial locating of macroscopic throats based-on the inversion of dynamic interwell connectivity

    Science.gov (United States)

    Lv, Aimin; Li, Xuyan; Yu, Miao; Li, Gangzhu; Wang, Shoulong; Peng, Ruigang; Zheng, Yawen

    2017-05-01

    This paper presents a practical technique to quantitatively locate macroscopic throats between injector/producer pairs in a reservoir, considering the problems of extensively developed macroscopic throats and the low sweep efficiency of waterflooding on high water cut stage. The method combines dynamic and static data, based on the results of geological research and the inversion of dynamic interwell connectivity. This technique has implemented the spatial locating of macroscopic throats, using the data of injection/production profiles and tracer test over the years, considering the sedimentary facies of each small layer and the permeability of each sand body. The results of this work show that this method is more convenient and less expensive than previous ones. It is able to locate macroscopic throats in a reservoir accurately and quantitatively. Multiple materials ensure the accuracy of results, and this method is convenient to be applied in the oilfield.

  4. Two-phase relative permeability models in reservoir engineering calculations

    Energy Technology Data Exchange (ETDEWEB)

    Siddiqui, S.; Hicks, P.J.; Ertekin, T.

    1999-01-15

    A comparison of ten two-phase relative permeability models is conducted using experimental, semianalytical and numerical approaches. Model predicted relative permeabilities are compared with data from 12 steady-state experiments on Berea and Brown sandstones using combinations of three white mineral oils and 2% CaCl1 brine. The model results are compared against the experimental data using three different criteria. The models are found to predict the relative permeability to oil, relative permeability to water and fractional flow of water with varying degrees of success. Relative permeability data from four of the experimental runs are used to predict the displacement performance under Buckley-Leverett conditions and the results are compared against those predicted by the models. Finally, waterflooding performances predicted by the models are analyzed at three different viscosity ratios using a two-dimensional, two-phase numerical reservoir simulator. (author)

  5. Symposium on Recent Developments in Large-Scale Computational Fluid Dynamics, University of Minnesota, Minneapolis, Apr. 23, 24, 1990, Technical Papers

    Science.gov (United States)

    Tezduyar, Tayfun E.; Hughes, Thomas J. R.

    1991-06-01

    Methodologies and applications in finite difference, finite element, and finite volume techniques, and spectral methods are considered. Topics discussed include a dual-porosity model for waterflooding in naturally fractured reservoirs, Navier-Stokes simulations of flow past 3D submarine models, current CFD issues relevant to the incompressible Navier-Stokes equations, efficient direct solvers for large-scale CFD problems, adaptive streamline diffusion methods for compressible flow using conservation variables, computational methods for shock waves in a 3D supersonic flow, the computation of 3D flows using unstructured grids, a large-scale method of lines solution of fluid dynamics equations on Japanese supercomputers, and time-accurate incompressible flow computations with quadrilateral velocity-pressure elements.

  6. Commercial scale demonstration enhanced oil recovery by miceller-polymer flooding. M-1 project: facilities report

    Energy Technology Data Exchange (ETDEWEB)

    Knight, B.L. (ed.)

    1977-04-01

    ERDA and Marathon Oil Company contracted together for a commercial scale demonstration of enhanced oil recovery by the Maraflood (TM) oil recovery process. This M-1 Project is located within Sections 15, 16, 21 and 22, T6N, R13W, Crawford County, Illinois, encompassing approximately 407 acres of Robinson Sand reservoir developed in the first decade of the century. The area covers portions of several waterfloods developed on 10-acre spacing in the 1950's that were approaching their economic limit. This report describes all M-1 Project facilities, how they were prepared or constructed, their purpose and how they operate: (1) wells (drilling and completion); (2) production facility; (3) injection facility; and (4) various service systems required during project development and/or operation. (48 fig, 7 tables) (DLC).

  7. Models of optimal technology for removing oil by secondary methods of developing highly viscous oil fields

    Energy Technology Data Exchange (ETDEWEB)

    Jewulski, J.

    1982-01-01

    This paper presents research on developing several methods of optimal technology for removing oil in highly viscous oil fields from the following wells: Lubno-3, Kharklova-Gvaretstvo 154 and Vetzhno (heavy oil). The problem connected with preparing the displacement fluids, with special emphasis on the authors patented technology for producing micellar solutions are discussed. The studies of dislocation fluids (including modified ones) were conducted at 3 temperatures: 293, 308, and 323/sup 0/K and with and without micellar solutions. The tests were used to idetify static regressive models of oil removal from oil fields. The model is satisfactorily accurate in predicting the amount of oil yield by using various secondary methods. Practical conclusions are reached based on an analysis of the studies. These conclusions provide the basis for industrial tests to increase the effectiveness of waterflooding highly viscous oil fields. They can also be used to develop old (gased) oil fields, an advantage considering the current fuel-energy situation.

  8. 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.

  9. Effect of neglecting geothermal gradient on calculated oil recovery

    Science.gov (United States)

    Safari, Mehdi; Mohammadi, Majid; Sedighi, Mehdi

    2017-03-01

    Reduced recovery rate with time is a common challenge for most of the oil producing reservoirs. Water flooding is one of the most common methods used for enhanced oil recovery. Simulating water-flooding process is sometimes carried out without considering the effect of geothermal gradient, and an average temperature is assumed for all the grid blocks. However, the gradient plays a significant role on the reservoir fluid properties. So neglecting its effect might result in a large error in the calculated oil recovery results, especially for the thick reservoirs, which in theory can show significant variations in temperature with depth. In this paper, first, advancing the waterfront during injection into a geothermal oil reservoir is discussed. Then, the performance of considering either an average temperature or gradient temperature, are considered and compared with each other. The results suggest that assuming a fixed average reservoir temperature with no geothermal gradient, can lead to a pronounced error for calculated oil recovery.

  10. Development and verification of simplified prediction models for enhanced oil recovery applications. CO/sub 2/ (miscible flood) predictive model. Final report

    Energy Technology Data Exchange (ETDEWEB)

    Paul, G.W.

    1984-10-01

    A screening model for CO/sub 2/ miscible flooding has been developed consisting of a reservoir model for oil rate and recovery and an economic model. The reservoir model includes the effects of viscous fingering, reservoir heterogeneity, gravity segregation and areal sweep. The economic model includes methods to calculate various profitability indices, the windfall profits tax, and provides for CO/sub 2/ recycle. The model is applicable to secondary or tertiary floods, and to solvent slug or WAG processes. The model does not require detailed oil-CO/sub 2/ PVT data for execution, and is limited to five-spot patterns. A pattern schedule may be specified to allow economic calculations for an entire project to be made. Models of similar architecture have been developed for steam drive, in-situ combustion, surfactant-polymer flooding, polymer flooding and waterflooding. 36 references, 41 figures, 4 tables.

  11. Applications of advanced petroleum production technology and water alternating gas injection for enhanced oil recovery: Mattoon Oil Field, Illinois. Fourth quarterly report, [October 1, 1993--December 31, 1993

    Energy Technology Data Exchange (ETDEWEB)

    Baroni, M.

    1994-01-25

    The objectives of this project are to continue reservoir characterization of the Cypress Sandstone; to identify and map fades-defined waterflood units (FDWS); and to design and Implement water-alternating-gas (WAG) oil recovery utilizing carbon dioxide (CO{sub 2}). The producibility problems are permeability variation and poor sweep efficiency. Phase 1 of the project focuses on the development of computer-generated geological and reservoir simulation models that will be used to select sites for the demonstration and implementation of CO{sub 2} displacement programs in Phase 2. Included in Phase 1 is the site selection and drilling of an infill well, coring of the Cypress interval, and injectivity testing to gather information used to update the reservoir simulation model. Phase 2 involves field implementation of WAG. Technology Transfer includes outreach activity such as seminars, workshops, and field trips. Technical progress for this quarter is described.

  12. Improved recovery demonstration for Williston Basin carbonates. Annual report, June 10, 1995--June 9, 1996

    Energy Technology Data Exchange (ETDEWEB)

    Carrell, L.A.; Sippel, M.A.

    1996-09-01

    The purpose of this project is to demonstrate targeted infill and extension drilling opportunities, better determinations of oil-in-place, methods for improved completion efficiency and the suitability of waterflooding in Red River and Ratcliffe shallow-shelf carbonate reservoirs in the Williston Basin, Montana, North Dakota and South Dakota. Improved reservoir characterization utilizing three-dimensional and multi-component seismic are being investigated for identification of structural and stratigraphic reservoir compartments. These seismic characterization tools are integrated with geological and engineering studies. Improved completion efficiency is being tested with extended-reach jetting lance and other ultra-short-radius lateral technologies. Improved completion efficiency, additional wells at closer spacing and better estimates of oil in place will result in additional oil recovery by primary and enhanced recovery processes.

  13. Surfactant-enhanced alkaline flooding: Buffering at intermediate alkaline pH

    Energy Technology Data Exchange (ETDEWEB)

    Rudin, J.; Wasan, D.T. (Illinois Inst. of Tech., Chicago, IL (United States))

    1993-11-01

    The alkaline flooding process involves injecting alkaline agents into the reservoir to produce more oil than is produced through conventional waterflooding. The interaction of the alkali in the flood water with the naturally occurring acids in the reservoir oil results in in-situ formation of soaps, which are partially responsible for lowering IFT and improving oil recovery. The extent to which IFT is lowered depends on the specific oil and injection water properties. Numerous investigators have attempted to clarify the relationship between system chemical composition and IFT. An experimental investigation of buffered alkaline flooding system chemistry was undertaken to determine the influence of various species present on interfacial tension (IFT) as a function of pH and ionic strength. IFT was found to go through an ultralow minimum in certain pH ranges. This synergism results from simultaneous adsorption of un-ionized and ionized acid species on the interface.

  14. Applications of advanced petroleum production technology and water alternating gas injection for enhanced oil recovery: Mattoon Oil Field, Illinois. [Quarterly report], January--March 1994

    Energy Technology Data Exchange (ETDEWEB)

    Baroni, M.R.

    1994-04-30

    The objectives of this project are to continue reservoir characterization of the Cypress Sandstone; to identify and map facies-defined waterflood units (FDWS); and to design and implement water-alternating-gas (WAG) oil recovery utilizing carbon dioxide (CO{sub 2}). The producibility problems are permeability variation and poor sweep efficiency. Phase 1 of the project focuses on the development of computer-generated geological and reservoir simulation models that will be used to select sites for the demonstration and implementation of CO{sub 2} displacement programs in Phase 2. Included in Phase 1 is the site selection and drilling of an infill well, coring of the Cypress internal and injectivity testing to gather information used to update the reservoir simulation model. Phase 2 involves field implementation of WAG. Technology Transfer includes outreach activity such as seminars, workshops, and field trips. Accomplishments for the past quarter are described.

  15. Field Laboratory in the Osage Reservation -- Determination of the Status of Oil and Gas Operations: Task 1. Development of Survey Procedures and Protocols

    Energy Technology Data Exchange (ETDEWEB)

    Carroll, Herbert B.; Johnson, William I.

    1999-04-27

    Procedures and protocols were developed for the determination of the status of oil, gas, and other mineral operations on the Osage Mineral Reservation Estate. The strategy for surveying Osage County, Oklahoma, was developed and then tested in the field. Two Osage Tribal Council members and two Native American college students (who are members of the Osage Tribe) were trained in the field as a test of the procedures and protocols developed in Task 1. Active and inactive surface mining operations, industrial sites, and hydrocarbon-producing fields were located on maps of the county, which was divided into four more or less equal areas for future investigation. Field testing of the procedures, protocols, and training was successful. No significant damage was found at petroleum production operations in a relatively new production operation and in a mature waterflood operation.

  16. Biodeterioration problems of North sea oil and gas production - a review

    Energy Technology Data Exchange (ETDEWEB)

    Edyvean, R.G.J.

    1987-01-01

    The North Sea is both a highly corrosive and highly biologically productive environment. Oil and gas production structures in this environment not only suffer from the physical effects, corrosion, wave and storm action, of being immersed in this environment, but also the effects of biological activity. Such biodeterioration problems occur both on the external and internal surfaces of the structure and the internal surfaces of any plant or pipework which contains, or has contained, water. The platform jacket may experience biological problems due to external macro- and microfouling or to internal microfouling. Pipelines, risers and topside systems have usually all been hydrostatically tested leaving residual water and possible sites for bacterial activity. Waterflooding with seawater and the separation of produced water from oil also provide sites suitable for biological activity and associated corrosion, slime and blockage problems.

  17. Effect of Brine Composition on Wettability Alteration and Oil Recovery from Oil-wet Carbonate Rocks

    Science.gov (United States)

    Purswani, P.; Karpyn, Z.

    2016-12-01

    Brine composition is known to affect the effectiveness of waterflooding during enhanced oil recovery from carbonate reservoirs. Recent studies have identified Mg2+, Ca2+ and SO42- as critical ions, responsible for incremental oil recovery via wettability alteration. To investigate the underlying mechanism of wettability alteration and, to evaluate the individual contribution of these ions towards improving oil recovery, a series of coreflooding experiments are performed. Various characterization techniques like zeta potential (ZP), drop angle analysis and inductively coupled plasma mass spectrometry (ICP MS) analysis are performed to evaluate the surface interactions taking place at the carbonate core samples, brine solution and crude oil interfaces. Total dissolved solids and electrical conductivity measurements confirm the ionic strength of the brine samples. Acid number calculations, ZP and contact angle measurements confirm the initial oil-wetting state of the core. ICP MS analysis of the effluent brine, confirm the relationship between the ionic interactions and oil recovery.

  18. Druzhba feasibility study: Barsukov and Tarasov fields, 1995. Barsukov and Tarasov production histories western equipment. Export trade information

    Energy Technology Data Exchange (ETDEWEB)

    NONE

    1996-01-03

    The study, conducted by NEFT, was funded by the U.S. Trade and Development Agency. The report shows the results of a feasibility study conducted for the rehabilitation of oil wells in Baruskov and Tarasov fields. The objectives of the study include a plan for improving well and waterflood performance, and to determine materials and equipment needed. The report also covers capital and operating costs, as well as an evaluation of project economics based on Russian law. This is Volume 2 of the study containing Production Histories-Western Equipment. It is divided into the following sections: (1) Job Descriptions; (2) Barsukov Histories/Logs; (3) Tarasov Histories/Logs; (4) Taxes Paid by PNG; (5) Vendors Literature; (6) Rigs; (7) Liners; (8) Directional Drilling; (9) Mechanical Perforating; (10) Camps; (11) Pumps; (12) Fishing; (13) Downhole Oil/Water Separator; (14) Plastic.

  19. 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.

  20. Upscaling of Two-Phase Immiscible Flows in Communicating Stratified Reservoirs

    DEFF Research Database (Denmark)

    Zhang, Xuan; Shapiro, Alexander; Stenby, Erling Halfdan

    2011-01-01

    forces and gravity may be neglected. The method is discussed on the example of its basic application: waterflooding in petroleum reservoirs. We apply asymptotic analysis to a system of two-dimensional (2D) mass conservation equations for incompressible fluids. For high anisotropy ratios, the pressure...... gradient in vertical direction may be set zero, which is the only assumption of our derivation. In this way, the 2D Buckley–Leverett problem may be reduced to a one-dimensional problem for a system of quasi-linear hyperbolic equations, of a number equal to the number of layers in the reservoir....... They are solved numerically, based on an upstream finite difference algorithm. Self-similarity of the solution makes it possible to compute pseudofractional flow functions depending on the average saturation. The computer partial differential equation solver COMSOL is used for comparison of the complete 2D...

  1. Measurement and Modelling of Phase Equilibrium of Oil - Water - Polar Chemicals

    DEFF Research Database (Denmark)

    Frost, Michael Grynnerup

    . Thesechemicals belong to different families like alcohols, glycols, alkanolamines, surfactants andpolymers. They have various functions, e.g., methanol and MEG are used as gas hydrate inhibitors,surfactants are used to lower interfacial tension between crude oil and microemulsion and polymersin a polymer......-waterflooding process act primarily as thickeners. The main purpose of this work, focusing on the phase equilibrium of complex systems containingthermodynamic gas hydrate inhibitors, is to give a solid contribution in bridging the existing gaps inwhat experimental data is concerned. This was achieved not just...... with the measurement of newexperimental data, but through the development of new experimental equipment for the study ofmulti-phase equilibrium. In addition to measurement of well-defined systems, LLE have beenmeasured for North Sea oils with MEG and water. The work can be split up into two parts: Experimental: VLE...

  2. Area balance and strain in an extensional fault system: Strategies for improved oil recovery in fractured chalk, Gilbertown Field, southwestern Alabama -- Year 2. Annual report, March 1997--March 1998

    Energy Technology Data Exchange (ETDEWEB)

    Pashin, J.C.; Raymond, D.E.; Rindsberg, A.K.; Alabi, G.G.; Carroll, R.E.

    1998-09-01

    Gilbertown Field is the oldest oil field in Alabama and has produced oil from fractured chalk of the Cretaceous Selma Group and glauconitic sandstone of the Eutaw Formation. Nearly all of Gilbertown Field is still in primary recovery, although waterflooding has been attempted locally. The objective of this project is to analyze the geologic structure and burial history of Mesozoic and Tertiary strata in Gilbertown Field and adjacent areas in order to suggest ways in which oil recovery can be improved. Indeed, the decline of oil production to marginally economic levels in recent years has made this type of analysis timely and practical. Key technical advancements being sought include understanding the relationship of requisite strain to production in Gilbertown reservoirs, incorporation of synsedimentary growth factors into models of area balance, quantification of the relationship between requisite strain and bed curvature, determination of the timing of hydrocarbon generation, and identification of the avenues and mechanisms of fluid transport.

  3. Coalinga polymer demonstration project. Fourth annual report, July 1978-July 1979

    Energy Technology Data Exchange (ETDEWEB)

    Schultz, V.

    1980-09-01

    A field demonstration test of displacement mobility control in the East Coalinga Field is being conducted in order to determine the relative merits of polymer flooding and waterflooding in a medium viscosity oil reservoir. The injection pattern consists of four inverted 5-spot patterns and an updip area. Water injection began in June 1976 and continued through April 1978. Polymer injection began in May 1978 and is ongoing. The overall production performance for the pilot has been far less than expected. The current oil production rate is currently below the expected primary decline rate. The polymer injection rate is substantially below original predictions and will increase the time required to inject the designed slug volume.

  4. SURFACTANT BASED ENHANCED OIL RECOVERY AND FOAM MOBILITY CONTROL

    Energy Technology Data Exchange (ETDEWEB)

    George J. Hirasaki; Clarence A. Miller; Gary A. Pope; Richard E. Jackson

    2004-02-01

    Surfactant flooding has the potential to significantly increase recovery over that of conventional waterflooding. The availability of a large number of surfactant structures makes it possible to conduct a systematic study of the relation between surfactant structure and its efficacy for oil recovery. Also, the addition of an alkali such as sodium carbonate makes possible in situ generation of surfactant and significant reduction of surfactant adsorption. In addition to reduction of interfacial tension to ultra-low values, surfactants and alkali can be designed to alter wettability to enhance oil recovery. An alkaline surfactant process is designed to enhance spontaneous imbibition in fractured, oil-wet, carbonate formations. It is able to recover oil from dolomite core samples from which there was no oil recovery when placed in formation brine.

  5. Microbial field pilot study. Final report

    Energy Technology Data Exchange (ETDEWEB)

    Knapp, R.M.; McInerney, M.J.; Menzie, D.E.; Coates, J.D.; Chisholm, J.L.

    1993-05-01

    A multi-well microbially enhanced oil recovery field pilot has been performed in the Southeast Vassar Vertz Sand Unit in Payne County, Oklahoma. The primary emphasis of the experiment was preferential plugging of high permeability zones for the purpose of improving waterflood sweep efficiency. Studies were performed to determine reservoir chemistry, ecology, and indigenous bacteria populations. Growth experiments were used to select a nutrient system compatible with the reservoir that encouraged growth of a group of indigenous nitrate-using bacteria and inhibit growth of sulfate-reducing bacteria. A specific field pilot area behind an active line drive waterflood was selected. Surface facilities were designed and installed. Injection protocols of bulk nutrient materials were prepared to facilitate uniform distribution of nutrients within the pilot area. By the end of December, 1991, 82.5 tons (75.0 tonnes) of nutrients had been injected in the field. A tracer test identified significant heterogeneity in the SEVVSU and made it necessary to monitor additional production wells in the field. The tracer tests and changes in production behavior indicate the additional production wells monitored during the field trial were also affected. Eighty two and one half barrels (13.1 m{sup 3}) of tertiary oil have been recovered. Microbial activity has increased CO{sub 2} content as indicated by increased alkalinity. A temporary rise in sulfide concentration was experienced. These indicate an active microbial community was generated in the field by the nutrient injection. Pilot area interwell pressure interference test results showed that significant permeability reduction occurred. The interwell permeabilities in the pilot area between the injector and the three pilot production wells were made more uniform which indicates a successful preferential plugging enhanced oil recovery project.

  6. Microbial field pilot study

    Energy Technology Data Exchange (ETDEWEB)

    Knapp, R.M.; McInerney, M.J.; Menzie, D.E.; Coates, J.D.; Chisholm, J.L.

    1993-05-01

    A multi-well microbially enhanced oil recovery field pilot has been performed in the Southeast Vassar Vertz Sand Unit in Payne County, Oklahoma. The primary emphasis of the experiment was preferential plugging of high permeability zones for the purpose of improving waterflood sweep efficiency. Studies were performed to determine reservoir chemistry, ecology, and indigenous bacteria populations. Growth experiments were used to select a nutrient system compatible with the reservoir that encouraged growth of a group of indigenous nitrate-using bacteria and inhibit growth of sulfate-reducing bacteria. A specific field pilot area behind an active line drive waterflood was selected. Surface facilities were designed and installed. Injection protocols of bulk nutrient materials were prepared to facilitate uniform distribution of nutrients within the pilot area. By the end of December, 1991, 82.5 tons (75.0 tonnes) of nutrients had been injected in the field. A tracer test identified significant heterogeneity in the SEVVSU and made it necessary to monitor additional production wells in the field. The tracer tests and changes in production behavior indicate the additional production wells monitored during the field trial were also affected. Eighty two and one half barrels (13.1 m[sup 3]) of tertiary oil have been recovered. Microbial activity has increased CO[sub 2] content as indicated by increased alkalinity. A temporary rise in sulfide concentration was experienced. These indicate an active microbial community was generated in the field by the nutrient injection. Pilot area interwell pressure interference test results showed that significant permeability reduction occurred. The interwell permeabilities in the pilot area between the injector and the three pilot production wells were made more uniform which indicates a successful preferential plugging enhanced oil recovery project.

  7. The Ardross reservoir gridblock analogue: Sedimentology, statistical representivity, and flow upscaling

    Energy Technology Data Exchange (ETDEWEB)

    Ringrose, P.; Pickup, G.; Jensen, J. [Heriot-Watt Univ., Edinburgh (United Kingdom)] [and others

    1997-08-01

    We have used a reservoir gridblock-sized outcrop (10m by 100m) of fluvio-deltaic sandstones to evaluate the importance of internal heterogeneity for a hypothetical waterflood displacement process. Using a dataset based on probe permeameter measurements taken from two vertical transacts representing {open_quotes}wells{close_quotes} (5cm sampling) and one {open_quotes}core{close_quotes} sample (exhaustive 1mm-spaced sampling), we evaluate the permeability variability at different lengthscales, the correlation characteristics (structure of the variogram, function), and larger-scale trends. We then relate these statistical measures to the sedimentology. We show how the sediment architecture influences the effective tensor permeability at the lamina and bed scale, and then calculate the effective relative permeability functions for a waterflood. We compare the degree of oil recovery from the formation: (a) using averaged borehole data and no geological structure, and (b) modelling the sediment architecture of the interwell volume using mixed stochastic/deterministic methods. We find that the sediment architecture has an important effect on flow performance, mainly due to bedscale capillary trapping and a consequent reduction in the effective oil mobility. The predicted oil recovery differs by 18% when these small-scale effects are included in the model. Traditional reservoir engineering methods, using averages permeability values, only prove acceptable in high-permeability and low-heterogeneity zones. The main outstanding challenge, represented by this illustration of sub-gridblock scale heterogeneity, is how to capture the relevant geological structure along with the inherent geo-statistical variability. An approach to this problem is proposed.

  8. Improved characterization of reservoir behavior by integration of reservoir performances data and rock type distributions

    Energy Technology Data Exchange (ETDEWEB)

    Davies, D.K.; Vessell, R.K. [David K. Davies & Associates, Kingwood, TX (United States); Doublet, L.E. [Texas A& M Univ., College Station, TX (United States)] [and others

    1997-08-01

    An integrated geological/petrophysical and reservoir engineering study was performed for a large, mature waterflood project (>250 wells, {approximately}80% water cut) at the North Robertson (Clear Fork) Unit, Gaines County, Texas. The primary goal of the study was to develop an integrated reservoir description for {open_quotes}targeted{close_quotes} (economic) 10-acre (4-hectare) infill drilling and future recovery operations in a low permeability, carbonate (dolomite) reservoir. Integration of the results from geological/petrophysical studies and reservoir performance analyses provide a rapid and effective method for developing a comprehensive reservoir description. This reservoir description can be used for reservoir flow simulation, performance prediction, infill targeting, waterflood management, and for optimizing well developments (patterns, completions, and stimulations). The following analyses were performed as part of this study: (1) Geological/petrophysical analyses: (core and well log data) - {open_quotes}Rock typing{close_quotes} based on qualitative and quantitative visualization of pore-scale features. Reservoir layering based on {open_quotes}rock typing {close_quotes} and hydraulic flow units. Development of a {open_quotes}core-log{close_quotes} model to estimate permeability using porosity and other properties derived from well logs. The core-log model is based on {open_quotes}rock types.{close_quotes} (2) Engineering analyses: (production and injection history, well tests) Material balance decline type curve analyses to estimate total reservoir volume, formation flow characteristics (flow capacity, skin factor, and fracture half-length), and indications of well/boundary interference. Estimated ultimate recovery analyses to yield movable oil (or injectable water) volumes, as well as indications of well and boundary interference.

  9. Integrated geological and engineering characterization of an Upper Permian, carbonate reservoir, South Cowden unit, Ector County Texas -- a work in progress

    Energy Technology Data Exchange (ETDEWEB)

    Gerard, M.G.; Johnson, J.V.; Snow, S.C. [Phillips Petroleum Company, Odessa, TX (United States)] [and others

    1995-09-01

    South Cowden Unit, located on the eastern margin of the Central Basin Platform, has produced 35 million barrels of oil since initial development in the late 1940`s. The Unit, under waterflood since 1965, has been proposed for a CO{sub 2} flood using horizontal injection wells. A team of geologists and engineers was formed to characterize the reservoir. The early and complete integration of geologic and engineering work has resulted in a detailed reservoir description to be used in reservoir simulation. Regional mapping and 3D seismic data indicate that sediments within the reservoir interval were draped over a paleohigh resulting in an unfaulted, anticlinal-like structure. A field-wide stratigraphic framework was developed using two to four-foot thick, gamma-ray log markers which correspond to low permeability, sandy dolomite layers recognized in core. These log correlations indicate fairly simple and uniform structure and stratigraphy. The gamma-ray markers delineate four zones within the 150 foot reservoir interval. Rocks composing these zones are extensively dolomitized and display a complex color mottling. This mottling is related most likely to bioturbation of carbonate sediments in a shallow, subtidal marine environment. Extensive and interconnected bioturbated areas have core analysis porosities averaging approximately 20% and permeabilities generally ranging from 2 to 350 md. The intervening, nonburrowed and unstained areas have porosities averaging 5% and permeabilities typically ranging form 0.01 to 2 md. Variations in the quality and thickness of the mottled facies are major parameters controlling oil recovery. A belt of better reservoir-quality rock runs roughly parallel to structure and results in an area of higher cumulative oil production. Good waterflood response and uniform pressure distribution indicate continuity of the pay zones within this belt.

  10. A study of secondary recovery possibilities of the Hogshooter field, Washington County, Oklahoma

    Science.gov (United States)

    Fox, I. William; Thigpen, Claude H.; Ginter, Roy L.; Alden, George P.

    1945-01-01

    The Hogshooter field, located in east central Washington County, Oklahoma, was first developed during the period 1906 to 1913. The field was extended later during the period 1918 to 1922. The principal producing horizon is the Bartlesville sand, found at an average depth of 1,150 feet. To January 1, 1944, the Bartlesville sand has produced 7,566,000 barrels of oil from 5,610 productive acres and 871 oil wells. Peak production, averaging 2,025 barrels per day for the year, was attained in the year 1910. The accumulation of oil in the Bartlesville sand is not related to structure. The total recovery from the Bartlesville sand in the Hogshooter field to January 1, 1944, is estimated to represent 10.3 per cent of the original oil in place, and the total residual oil is estimated to average 11,776 barrels per acre. Widespread application of vacuum, started in 1915, has had little beneficial effect on production. Some gas-repressuring in recent years has increased recovery to a small extent. Conservatively estimated water-flood recovery possibilities are: 3,500 barrels per acre for an area consisting of 1,393 acres (4,875,000 barrels total) with a reasonable profit at the present price of crude oil, and 2,500 barrels per acre for an area of 2,248 acres (5,620,000 barrels total), with no profit indicated under existing conditions. The latter area would show a profit equal to the first-mentioned area only with an increase in price of crude oil of forty-five cents per barrel. Subsurface waters at depths of 1,400 to 1,700 feet are indicated as a satisfactory source for use in water-flooding operations.

  11. 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.

  12. Coreflood assay using extremophile microorganisms for recovery of heavy oil in Mexican oil fields.

    Science.gov (United States)

    Castorena-Cortés, Gladys; Roldán-Carrillo, Teresa; Reyes-Avila, Jesús; Zapata-Peñasco, Icoquih; Mayol-Castillo, Martha; Olguín-Lora, Patricia

    2012-10-01

    A considerable portion of oil reserves in Mexico corresponds to heavy oils. This feature makes it more difficult to recover the remaining oil in the reservoir after extraction with conventional techniques. Microbial enhanced oil recovery (MEOR) has been considered as a promising technique to further increase oil recovery, but its application has been developed mainly with light oils; therefore, more research is required for heavy oil. In this study, the recovery of Mexican heavy oil (11.1°API and viscosity 32,906 mPa s) in a coreflood experiment was evaluated using the extremophile mixed culture A7, which was isolated from a Mexican oil field. Culture A7 includes fermentative, thermophilic, and anaerobic microorganisms. The experiments included waterflooding and MEOR stages, and were carried out under reservoir conditions (70°C and 9.65 MPa). MEOR consisted of injections of nutrients and microorganisms followed by confinement periods. In the MEOR stages, the mixed culture A7 produced surface-active agents (surface tension reduction 27 mN m⁻¹), solvents (ethanol, 1738 mg L⁻¹), acids (693 mg L⁻¹), and gases, and also degraded heavy hydrocarbon fractions in an extreme environment. The interactions of these metabolites with the oil, as well as the bioconversion of heavy oil fractions to lighter fractions (increased alkanes in the C₈-C₃₀ range), were the mechanisms responsible for the mobility and recovery of heavy oil from the porous media. Oil recovery by MEOR was 19.48% of the residual oil in the core after waterflooding. These results show that MEOR is a potential alternative to heavy oil recovery in Mexican oil fields. Copyright © 2012 The Society for Biotechnology, Japan. Published by Elsevier B.V. All rights reserved.

  13. COUPLING THE ALKALINE-SURFACTANT-POLYMER TECHNOLOGY AND THE GELATION TECHNOLOGY TO MAXIMIZE OIL PRODUCTION

    Energy Technology Data Exchange (ETDEWEB)

    Malcolm Pitts; Jie Qi; Dan Wilson

    2004-10-01

    Gelation technologies have been developed to provide more efficient vertical sweep efficiencies for flooding naturally fractured oil reservoirs or more efficient areal sweep efficiency for those with high permeability contrast ''thief zones''. The field proven alkaline-surfactant-polymer technology economically recovers 15% to 25% OOIP more oil than waterflooding from swept pore space of an oil reservoir. However, alkaline-surfactant-polymer technology is not amenable to naturally fractured reservoirs or those with thief zones because much of injected solution bypasses target pore space containing oil. This work investigates whether combining these two technologies could broaden applicability of alkaline-surfactant-polymer flooding into these reservoirs. A prior fluid-fluid report discussed interaction of different gel chemical compositions and alkaline-surfactant-polymer solutions. Gel solutions under dynamic conditions of linear corefloods showed similar stability to alkaline-surfactant-polymer solutions as in the fluid-fluid analyses. Aluminum-polyacrylamide, flowing gels are not stable to alkaline-surfactant-polymer solutions of either pH 10.5 or 12.9. Chromium acetate-polyacrylamide flowing and rigid flowing gels are stable to subsequent alkaline-surfactant-polymer solution injection. Rigid flowing chromium acetate-polyacrylamide gels maintained permeability reduction better than flowing chromium acetate-polyacrylamide gels. Silicate-polyacrylamide gels are not stable with subsequent injection of either a pH 10.5 or a 12.9 alkaline-surfactant-polymer solution. Neither aluminum citrate-polyacrylamide nor silicate-polyacrylamide gel systems produced significant incremental oil in linear corefloods. Both flowing and rigid flowing chromium acetate-polyacrylamide gels produced incremental oil with the rigid flowing gel producing the greatest amount. Higher oil recovery could have been due to higher differential pressures across cores. None of

  14. Chemical Methods for Ugnu Viscous Oils

    Energy Technology Data Exchange (ETDEWEB)

    Kishore Mohanty

    2012-03-31

    includes 1.5% of an alkali, 0.4% of a nonionic surfactant, and 0.48% of a polymer. The secondary waterflood in a 1D sand pack had a cumulative recovery of 0.61 PV in about 3 PV injection. The residual oil saturation to waterflood was 0.26. Injection of tertiary alkaline-surfactant-polymer slug followed by tapered polymer slugs could recover almost 100% of the remaining oil. The tertiary alkali-surfactant-polymer flood of the 330 cp oil is stable in three-dimensions; it was verified by a flood in a transparent 5-spot model. A secondary polymer flood is also effective for the 330 cp viscous oil in 1D sand pack. The secondary polymer flood recovered about 0.78 PV of oil in about 1 PV injection. The remaining oil saturation was 0.09. The pressure drops were reasonable (<2 psi/ft) and depended mainly on the viscosity of the polymer slug injected. For the heavy crude oil (of viscosity 10,000 cp), low viscosity (10-100 cp) oil-in-water emulsions can be obtained at salinity up to 20,000 ppm by using a hydrophilic surfactant along with an alkali at a high water-to-oil ratio of 9:1. Very dilute surfactant concentrations (~0.1 wt%) of the synthetic surfactant are required to generate the emulsions. It is much easier to flow the low viscosity emulsion than the original oil of viscosity 10,000 cp. Decreasing the WOR reverses the type of emulsion to water-in-oil type. For a low salinity of 0 ppm NaCl, the emulsion remained O/W even when the WOR was decreased. Hence a low salinity injection water is preferred if an oil-in-water emulsion is to be formed. Secondary waterflood of the 10,000 cp heavy oil followed by tertiary injection of alkaline-surfactants is very effective. Waterflood has early water breakthrough, but recovers a substantial amount of oil beyond breakthrough. Waterflood recovers 20-37% PV of the oil in 1D sand pack in about 3 PV injection. Tertiary alkali-surfactant injection increases the heavy oil recovery to 50-70% PV in 1D sand packs. As the salinity increased, the oil

  15. Chemical Methods for Ugnu Viscous Oils

    Energy Technology Data Exchange (ETDEWEB)

    Kishore Mohanty

    2012-03-31

    includes 1.5% of an alkali, 0.4% of a nonionic surfactant, and 0.48% of a polymer. The secondary waterflood in a 1D sand pack had a cumulative recovery of 0.61 PV in about 3 PV injection. The residual oil saturation to waterflood was 0.26. Injection of tertiary alkaline-surfactant-polymer slug followed by tapered polymer slugs could recover almost 100% of the remaining oil. The tertiary alkali-surfactant-polymer flood of the 330 cp oil is stable in three-dimensions; it was verified by a flood in a transparent 5-spot model. A secondary polymer flood is also effective for the 330 cp viscous oil in 1D sand pack. The secondary polymer flood recovered about 0.78 PV of oil in about 1 PV injection. The remaining oil saturation was 0.09. The pressure drops were reasonable (<2 psi/ft) and depended mainly on the viscosity of the polymer slug injected. For the heavy crude oil (of viscosity 10,000 cp), low viscosity (10-100 cp) oil-in-water emulsions can be obtained at salinity up to 20,000 ppm by using a hydrophilic surfactant along with an alkali at a high water-to-oil ratio of 9:1. Very dilute surfactant concentrations (~0.1 wt%) of the synthetic surfactant are required to generate the emulsions. It is much easier to flow the low viscosity emulsion than the original oil of viscosity 10,000 cp. Decreasing the WOR reverses the type of emulsion to water-in-oil type. For a low salinity of 0 ppm NaCl, the emulsion remained O/W even when the WOR was decreased. Hence a low salinity injection water is preferred if an oil-in-water emulsion is to be formed. Secondary waterflood of the 10,000 cp heavy oil followed by tertiary injection of alkaline-surfactants is very effective. Waterflood has early water breakthrough, but recovers a substantial amount of oil beyond breakthrough. Waterflood recovers 20-37% PV of the oil in 1D sand pack in about 3 PV injection. Tertiary alkali-surfactant injection increases the heavy oil recovery to 50-70% PV in 1D sand packs. As the salinity increased, the oil

  16. Coupling the Alkaline-Surfactant-Polymer Technology and The Gelation Technology to Maximize Oil Production

    Energy Technology Data Exchange (ETDEWEB)

    Malcolm Pitts; Jie Qi; Dan Wilson; David Stewart; Bill Jones

    2005-10-01

    Gelation technologies have been developed to provide more efficient vertical sweep efficiencies for flooding naturally fractured oil reservoirs or more efficient areal sweep efficiency for those with high permeability contrast ''thief zones''. The field proven alkaline-surfactant-polymer technology economically recovers 15% to 25% OOIP more oil than waterflooding from swept pore space of an oil reservoir. However, alkaline-surfactant-polymer technology is not amenable to naturally fractured reservoirs or those with thief zones because much of injected solution bypasses target pore space containing oil. This work investigates whether combining these two technologies could broaden applicability of alkaline-surfactant-polymer flooding into these reservoirs. A prior fluid-fluid report discussed interaction of different gel chemical compositions and alkaline-surfactant-polymer solutions. Gel solutions under dynamic conditions of linear corefloods showed similar stability to alkaline-surfactant-polymer solutions as in the fluid-fluid analyses. Aluminum-polyacrylamide, flowing gels are not stable to alkaline-surfactant-polymer solutions of either pH 10.5 or 12.9. Chromium acetate-polyacrylamide flowing and rigid flowing gels are stable to subsequent alkaline-surfactant-polymer solution injection. Rigid flowing chromium acetate-polyacrylamide gels maintained permeability reduction better than flowing chromium acetate-polyacrylamide gels. Silicate-polyacrylamide gels are not stable with subsequent injection of either a pH 10.5 or a 12.9 alkaline-surfactant-polymer solution. Chromium acetate-xanthan gum rigid gels are not stable to subsequent alkaline-surfactant-polymer solution injection. Resorcinol-formaldehyde gels were stable to subsequent alkaline-surfactant-polymer solution injection. When evaluated in a dual core configuration, injected fluid flows into the core with the greatest effective permeability to the injected fluid. The same gel stability

  17. 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

    The Paradox Basin of Utah, Colorado, and Arizona contains nearly 100 small oil fields producing from shallow-shelf carbonate buildups or mounds within the Desert Creek zone of 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 (111,300-318,000 m{sup 3}) of oil per field at a 15 to 20 percent recovery rate. Five fields in southeastern Utah were evaluated for waterflood or carbon-dioxide (CO{sub 2})-miscible flood projects based upon geological characterization and reservoir modeling. Geological characterization on a local scale focused on reservoir heterogeneity, quality, and lateral continuity as well as possible compartmentalization within each of the five project fields. The Desert Creek zone includes three generalized facies belts: (1) open-marine, (2) shallow-shelf and shelf-margin, and (3) intra-shelf, salinity-restricted facies. These deposits have modern analogs near the coasts of the Bahamas, Florida, and Australia, respectively, and outcrop analogs along the San Juan River of southeastern Utah. The analogs display reservoir heterogeneity, flow barriers and baffles, and lithofacies geometry observed in the fields; thus, these properties were incorporated in the reservoir simulation models. Productive carbonate buildups consist of three types: (1) phylloid algal, (2) coralline algal, and (3) bryozoan. Phylloid-algal buildups have a mound-core interval and a supra-mound interval. Hydrocarbons are stratigraphically trapped in porous and permeable lithotypes within the mound-core intervals of the lower part of the buildups and the more heterogeneous supramound intervals. To adequately represent the observed spatial heterogeneities in reservoir properties, the phylloid-algal bafflestones of the mound-core interval and the dolomites of the overlying supra-mound interval were subdivided into ten architecturally distinct lithotypes, each of which

  18. INJECTION PROFILE MODIFICATION IN A HOT, DEEP MINNELUSA WATER INJECTION PROJECT

    Energy Technology Data Exchange (ETDEWEB)

    Lyle A. Johnson Jr.

    2001-09-01

    As oil fields in the United States age, production enhancements and modifications will be needed to increase production from deeper and hotter oil reservoirs. New techniques and products must be tested in these areas before industry will adapt them as common practice. The Minnelusa fields of northeastern Wyoming are relatively small, deep, hot fields that have been developed in the past ten to twenty years. As part of the development, operators have established waterfloods early in the life of the fields to maximize cumulative oil production. However, channeling between injectors and producers does occur and can lead to excessive water production and bypassed oil left in the reservoir. The project evaluated the use of a recently developed, high-temperature polymer to modify the injection profiles in a waterflood project in a high-temperature reservoir. The field is the Hawk Point field in Campbell County, Wyoming. The field was discovered in 1986 and initially consisted of eight producing wells with an average depth of 11,500 feet and a temperature of 260 F (127 C). The polymer system was designed to plug the higher permeable channels and fractures to provide better conformance, i.e. sweep efficiency, for the waterflood. The project used a multi-well system to evaluate the treatment. Injection profile logging was used to evaluate the injection wells both before and after the polymer treatment. The treatment program was conducted in January 2000 with a treatment of the four injection wells. The treatment sizes varied between 500 bbl and 3,918 bbl at a maximum allowable pressure of 1,700 psig. Injection in three of the wells was conducted as planned. However, the injection in the fourth well was limited to 574 bbl instead of the planned 3,750 bbl because of a rapid increase in injection pressure, even at lower than planned injection rates. Following completion of polymer placement, the injection system was not started for approximately one week to permit the gel to

  19. 双重介质非饱和两相流岩体热流固损伤模型研究%Study on Thermal Deterioration Model of Liquid and Solid in Double Porous Medium Rock Matrix with Unsaturated Two-phase Flow

    Institute of Scientific and Technical Information of China (English)

    魏长霖; 齐悦

    2012-01-01

    以孔隙-裂缝双重孔隙介质为研究对象,建立孔隙度与岩体应变数学模型和温度场诱导应力模型.基于Terzaghi有效应力原理,建立注水开采过程温度-流体-岩石骨架的应力分布模型.考虑注水压力和注水温度场应力导致的岩体孔隙-裂隙的变形、成核和增长,采用应变孔隙度定义损伤变量,建立了以Gurson-Tvergaard-Needleman圆柱体胞模型为塑性屈服函数的双重孔隙介质饱和热流固损伤本构模型.以某1口生产井为研究对象,通过有限元软件数值模拟得到:温度场诱导应力、注水压力诱导应力和岩石应力分布规律;应力与损伤变量、应变孔隙度演化规律.新模型对油田注水开采过程中储层孔隙和裂缝的变化提供了新的研究方法和理论依据.%The double porous medium that is a medium between pore and fracture is selected as an object of study. The inductive stress model of thermal field is built, as well as the mathematical model of porosity and rock matrix strain. Based on the Terzaghi effective stress principle, the stress distribution model is built which is the relationship of temperature, liquid and rock skeleton during period of waterflood exploitation. The processes are considered , which are deformation, nucleation and growing of pore and fracture that are induced by stress of injection pressure and injection temperature field stress. The damage variable is defined by strain porosity. The constitutional equation of double pore medium saturated liquid-solid is set up where the Gurson Tvergaard Needleman cylindric representative volume element ( RVE) is taken as plastic yielding function. Take some well in one oil field, the result is concluded form numerical simulation of finite element software, which are induced stresses of thermal field and waterflood pressure and rock stress distribution rule, together with evolving regulations of stress and damage variable and strain porosity. The new model

  20. Evaluating the Influence of Pore Architecture and Initial Saturation on Wettability and Relative Permeability in Heterogeneous, Shallow-Shelf Carbonates

    Energy Technology Data Exchange (ETDEWEB)

    Byrnes, Alan P.; Bhattacharya, Saibal; Victorine, John; Stalder, Ken

    2007-09-30

    Thin (3-40 ft thick), heterogeneous, limestone and dolomite reservoirs, deposited in shallow-shelf environments, represent a significant fraction of the reservoirs in the U.S. midcontinent and worldwide. In Kansas, reservoirs of the Arbuckle, Mississippian, and Lansing-Kansas City formations account for over 73% of the 6.3 BBO cumulative oil produced over the last century. For these reservoirs basic petrophysical properties (e.g., porosity, absolute permeability, capillary pressure, residual oil saturation to waterflood, resistivity, and relative permeability) vary significantly horizontally, vertically, and with scale of measurement. Many of these reservoirs produce from structures of less than 30-60 ft, and being located in the capillary pressure transition zone, exhibit vertically variable initial saturations and relative permeability properties. Rather than being simpler to model because of their small size, these reservoirs challenge characterization and simulation methodology and illustrate issues that are less apparent in larger reservoirs where transition zone effects are minor and most of the reservoir is at saturations near S{sub wirr}. These issues are further augmented by the presence of variable moldic porosity and possible intermediate to mixed wettability and the influence of these on capillary pressure and relative permeability. Understanding how capillary-pressure properties change with rock lithology and, in turn, within transition zones, and how relative permeability and residual oil saturation to waterflood change through the transition zone is critical to successful reservoir management and as advanced waterflood and improved and enhanced recovery methods are planned and implemented. Major aspects of the proposed study involve a series of tasks to measure data to reveal the nature of how wettability and drainage and imbibition oil-water relative permeability change with pore architecture and initial water saturation. Focus is placed on

  1. 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

  2. Improvement of Sweep Efficiency in Gasflooding

    Energy Technology Data Exchange (ETDEWEB)

    Kishore Mohanty

    2008-12-31

    Miscible and near-miscible gasflooding has proven to be one of the few cost effective enhance oil recovery techniques in the past twenty years. As the scope of gas flooding is being expanded to medium viscosity oils in shallow sands in Alaska and shallower reservoirs in the lower 48, there are questions about sweep efficiency in near-miscible regions. The goal of this research is to evaluate sweep efficiency of various gas flooding processes in a laboratory model and develop numerical tools to estimate their effectiveness in the field-scale. Quarter 5-spot experiments were conducted at reservoir pressure to evaluate the sweep efficiency of gas, WAG and foam floods. The quarter 5-spot model was used to model vapor extraction (VAPEX) experiments at the lab scale. A streamline-based compositional simulator and a commercial simulator (GEM) were used to model laboratory scale miscible floods and field-scale pattern floods. An equimolar mixture of NGL and lean gas is multicontact miscible with oil A at 1500 psi; ethane is a multicontact miscible solvent for oil B at pressures higher than 607 psi. WAG improves the microscopic displacement efficiency over continuous gas injection followed by waterflood in corefloods. WAG improves the oil recovery in the quarter 5-spot over the continuous gas injection followed by waterflood. As the WAG ratio increases from 1:2 to 2:1, the sweep efficiency in the 5-spot increases, from 39.6% to 65.9%. A decrease in the solvent amount lowers the oil recovery in WAG floods, but significantly higher amount of oil can be recovered with just 0.1 PV solvent injection over just waterflood. Use of a horizontal production well lowers the oil recovery over the vertical production well during WAG injection phase in this homogeneous 5-spot model. Estimated sweep efficiency decreases from 61.5% to 50.5%. In foam floods, as surfactant to gas slug size ratio increases from 1:10 to 1:1, oil recovery increases. In continuous gasflood VAPEX processes, as the

  3. Enhanced Oil Recovery with Downhole Vibrations Stimulation in Osage County, Oklahoma

    Energy Technology Data Exchange (ETDEWEB)

    J. Ford Brett; Robert V. Westermark

    2001-09-30

    This Technical Quarterly Report is for the reporting period July 1, 2001 to September 30, 2001. The report provides details of the work done on the project entitled ''Enhanced Oil Recovery with Downhole Vibration Stimulation in Osage County Oklahoma''. The project is divided into nine separate tasks. Several of the tasks are being worked on simultaneously, while other tasks are dependent on earlier tasks being completed. The vibration stimulation well is permitted as Well 111-W-27, section 8 T26N R6E Osage County Oklahoma. It was spud July 28, 2001 with Goober Drilling Rig No. 3. The well was drilled to 3090-feet cored, logged, cased and cemented. The Rig No.3 moved off August 6, 2001. Phillips Petroleum Co. has begun analyzing the cores recovered from the test well. Standard porosity, permeability and saturation measurements will be conducted. They will then begin the sonic stimulation core tests Calumet Oil Company, the operator of the NBU, has begun to collect both production and injection wells information to establish a baseline for the project in the pilot field test area. Green Country Submersible Pump Company, a subsidiary of Calumet Oil Company, will provide both the surface equipment and downhole tools to allow the Downhole Vibration Tool to be operated by a surface rod rotating system. The 7-inch Downhole Vibration Tool (DHVT) has been built and is ready for initial shallow testing. The shallow testing will be done in a temporarily abandoned well operated by Calumet Oil Co. in the Wynona waterflood unit. The data acquisition doghouse and rod rotating equipment have been placed on location in anticipation of the shallow test in Well No.20-12 Wynona Waterflood Unit. A notice of invention disclosure was submitted to the DOE Chicago Operations Office. DOE Case No.S-98,124 has been assigned to follow the documentation following the invention disclosure. A paper covering the material presented to the Oklahoma Geologic Survey (OGS

  4. SOLVING THE SHUGART QUEEN SAND PENASCO UNIT DECLINING PRODUCTION PROBLEM

    Energy Technology Data Exchange (ETDEWEB)

    Lowell Deckert

    2000-08-25

    The Penasco Shugart Queen Sand Unit located in sections 8, 9, 16 & 17, T18S, 31E Eddy County New Mexico is operated by MNA Enterprises Ltd. Co. Hobbs, NM. The first well in the Unit was drilled in 1939 and since that time the Unit produced 535,000 bbl of oil on primary recovery and 375,000 bbl of oil during secondary recovery operations that commenced in 1973. The Unit secondary to primary ratio is 0.7, but other Queen waterfloods in the area had considerably larger S/P ratios. On June 25 1999 MNA was awarded a grant under the Department of Energy's ''Technology Development with Independents'' program. The grant was used to fund a reservoir study to determine if additional waterflood reserves could be developed. A total of 14 well bores that penetrate the Queen at 3150 ft are within the Unit boundaries. Eleven of these wells produced oil during the past 60 years. Production records were pieced together from various sources including the very early state production records. One very early well had a resistivity log, but nine of the wells had no logs, and four wells had gamma ray-neutron count-rate perforating logs. Fortunately, recent offset deep drilling in the area provided a source of modern logs through the Queen. The logs from these wells were used to analyze the four old gamma ray-neutron logs within the Unit. Additionally the offset well log database was sufficient to construct maps through the unit based on geostatistical interpolation methods. The maps were used to define the input parameters required to simulate the primary and secondary producing history. The history-matched simulator was then used to evaluate four production scenarios. The best scenario produces 51,000 bbl of additional oil over a 10-year period. If the injection rate is held to 300 BWPD the oil rate declines to a constant 15 BOPD after the first year. The projections are reasonable when viewed in the context of the historical performance ({approx}30 BOPD with a

  5. In-situ characterization of wettability and pore-scale displacements during two- and three-phase flow in natural porous media

    Science.gov (United States)

    Khishvand, M.; Alizadeh, A. H.; Piri, M.

    2016-11-01

    We establish a unique approach to measure in-situ contact angle from micro-CT images acquired during two- and three-phase miniature core-flooding experiments in order to overcome the uncertainties associated with conventional contact angle measurement techniques. The measurements are used to quantify the wettability behavior of the rock and explain pore-level displacement events occurring in three-phase flow. Six two-phase experiments are performed on individual core samples with three pairs of fluids, i.e., oil-brine, gas-oil, and gas-brine, and under two thermodynamic conditions: (a) binary-equilibrated, when only the two respective phases are at equilibrium and (b) ternary-equilibrated, when all three phases are equilibrated and only the two desired fluids are injected into the core. A three-phase experiment set is also performed under ternary-equilibrated conditions, which includes gas injection, a waterflood, and an oilflood process. All experiments are performed on Berea miniature core samples using a nonspreading brine-oil-gas fluid system. We measure receding and advancing contact angles at arc menisci and main terminal menisci for the two-phase binary-equilibrated experiments and characterize contact angle hysteresis for each fluid pair. Contact angle hysteresis values are almost identical for all fluid pairs. The results of the two-phase binary- and ternary-equilibrated experiments show similar contact angle distributions for each fluid pair. Contact angle distributions during the three-phase flow experiment are analyzed to develop new insights into relevant complex displacement mechanisms. The results indicate that, during gas injection, the majority of displacements involving oil and water are oil-to-water events. It is observed that, during the waterflood, both oil-to-gas and gas-to-oil displacement events take place. However, the relative frequency of the former is greater. For the oilflood, gas-water interfaces only slightly hinge in pore elements

  6. Using CO2 Prophet to estimate recovery factors for carbon dioxide enhanced oil recovery

    Science.gov (United States)

    Attanasi, Emil D.

    2017-07-17

    IntroductionThe Oil and Gas Journal’s enhanced oil recovery (EOR) survey for 2014 (Koottungal, 2014) showed that gas injection is the most frequently applied method of EOR in the United States and that carbon dioxide (CO2 ) is the most commonly used injection fluid for miscible operations. The CO2-EOR process typically follows primary and secondary (waterflood) phases of oil reservoir development. The common objective of implementing a CO2-EOR program is to produce oil that remains after the economic limit of waterflood recovery is reached. Under conditions of miscibility or multicontact miscibility, the injected CO2 partitions between the gas and liquid CO2 phases, swells the oil, and reduces the viscosity of the residual oil so that the lighter fractions of the oil vaporize and mix with the CO2 gas phase (Teletzke and others, 2005). Miscibility occurs when the reservoir pressure is at least at the minimum miscibility pressure (MMP). The MMP depends, in turn, on oil composition, impurities of the CO2 injection stream, and reservoir temperature. At pressures below the MMP, component partitioning, oil swelling, and viscosity reduction occur, but the efficiency is increasingly reduced as the pressure falls farther below the MMP. CO2-EOR processes are applied at the reservoir level, where a reservoir is defined as an underground formation containing an individual and separate pool of producible hydrocarbons that is confined by impermeable rock or water barriers and is characterized by a single natural pressure system. A field may consist of a single reservoir or multiple reservoirs that are not in communication but which may be associated with or related to a single structural or stratigraphic feature (U.S. Energy Information Administration [EIA], 2000). The purpose of modeling the CO2-EOR process is discussed along with the potential CO2-EOR predictive models. The data demands of models and the scope of the assessments require tradeoffs between reservoir

  7. MAJOR OIL PLAYS IN UTAH AND VICINITY

    Energy Technology Data Exchange (ETDEWEB)

    Thomas C. Chidsey Jr; Craig D. Morgan; Roger L. Bon

    2003-07-01

    production of the well, identify areas that may be by-passed by a waterflood, and prevent rapid water breakthrough. In the eastern Paradox Basin, Colorado, optimal drilling, development, and production practices consist of increasing the mud weight during drilling operations before penetrating the overpressured Desert Creek zone; centralizing treatment facilities; and mixing produced water from pumping oil wells with non-reservoir water and injecting the mixture into the reservoir downdip to reduce salt precipitation, dispose of produced water, and maintain reservoir pressure to create a low-cost waterflood. During this quarter, technology transfer activities consisted of technical presentations to members of the Technical Advisory Board in Colorado and the Colorado Geological Survey. The project home page was updated on the Utah Geological Survey Internet web site.

  8. Surfactant Based Enhanced Oil Recovery and Foam Mobility Control

    Energy Technology Data Exchange (ETDEWEB)

    George J. Hirasaki; Clarence A. Miller

    2006-09-09

    Surfactant flooding has the potential to significantly increase recovery over that of conventional waterflooding. The availability of a large number of surfactant structures makes it possible to conduct a systematic study of the relation between surfactant structure and its efficacy for oil recovery. A mixture of two surfactants was found to be particularly effective for application in carbonate formations at low temperature. The mixture is single phase for higher salinity or calcium concentrations than that for either surfactant used alone. This makes it possible to inject the surfactant slug with polymer close to optimal conditions and yet be single phase. A formulation has been designed for a particular field application. It uses partially hydrolyzed polyacrylamide for mobility control. The addition of an alkali such as sodium carbonate makes possible in situ generation of naphthenic soap and significant reduction of synthetic surfactant adsorption. The design of the process to maximize the region of ultra-low IFT takes advantage of the observation that the ratio of soap to synthetic surfactant is a parameter in the conditions for optimal salinity. Even for a fixed ratio of soap to surfactant, the range of salinity for low IFT was wider than that reported for surfactant systems in the literature. Low temperature, forced displacement experiments in dolomite and silica sandpacks demonstrate that greater than 95% recovery of the waterflood remaining oil is possible with 0.2% surfactant concentration, 0.5 PV surfactant slug, with no alcohol. Compositional simulation of the displacement process demonstrates the role of soap/surfactant ratio on passage of the profile through the ultralow IFT region, the importance of a wide salinity range of low IFT, and the importance of the viscosity of the surfactant slug. Mobility control is essential for surfactant EOR. Foam is evaluated to improve the sweep efficiency of surfactant injected into fractured reservoirs as well as a

  9. Saline contamination of soil and water on Pawnee tribal trust land, eastern Payne County, Oklahoma

    Science.gov (United States)

    Runkle, Donna L.; Abbott, Marvin M.; Lucius, Jeffrey E.

    2001-01-01

    solids concentrations, and plot the furthest from meteoric water on a graph of 8 deuterium and d 18oxygen. Waterflooding of the Bartlesville sand in the study area started in 1957 and continued until 1998. Waterflooding is the process of injecting brine water under pressure to drive the remaining oil to the production wells. The high dissolved solids concentration samples from observation wells 1, 3B, 5,7, and 8 could result from mixing of the Bartlesville brine from the waterfiood with meteoric water.

  10. Interaction between Fingering and Heterogeneity during Viscous Oil Recovery in Carbonate Rocks (Invited)

    Science.gov (United States)

    Mohanty, K. K.; Doorwar, S.

    2013-12-01

    Due to the fast depleting conventional oil reserves, research in the field of petroleum engineering has shifted focus towards unconventional (viscous and heavy) oils. Many of the viscous oil reserves are in carbonate rocks. Thermal methods in carbonate formations are complicated by mineral dissolution and precipitation. Non-thermal methods should be developed for viscous oils in carbonates. In viscous oil reservoirs, oil recovery due to water flood is low due to viscous fingering. Polymer flood is an attractive process, but the timing of the polymer flood start is an important parameter in the optimization of polymer floods. Vuggy Silurian dolomite cores were saturated with formation brine and reservoir oil (150-200 cp). They were then displaced by either a polymeric solution (secondary polymer flood) or brine followed the polymeric solution (tertiary polymer flood). The amount of brine injection was varied as a parameter. Oil recovery and pressure drop was monitored as a function of the starting point of the polymer flood. To visualize the displacement at the pore-scale, two types of micromodels were prepared: one with isolated heterogeneity and the other with connected heterogeneity. The wettability of the micromodels was either water-wet or oil-wet. The micromodels were saturated with formation brine and oil. A series of water flood and polymer flood was conducted to identify the mechanism of fluid flow. Dolomite corefloods show that a tertiary polymer flood following a secondary water flood recovers a substantial amount of oil unlike what is observed in typical sandstone cores with light oil. The tertiary oil recovery plus the secondary waterflood recovery can exceed the oil recovery in a secondary polymer flood in dolomite-viscous oil-brine system. These experiments were repeated in a Berea-oil-brine system which showed that the oil recovered in the secondary polymer flood was similar to the cumulative oil recovery in the tertiary polymer flood. The high

  11. Development adjustments: a case of an offshore heavy oilfield

    Energy Technology Data Exchange (ETDEWEB)

    Chen Peng; Tian Ji; Zhang Guoxiang

    2007-07-01

    The JZ9-3 Oilfield, operated by CNOOC limited in the northeast of the Bohai bay, has been put on production since 1999. Though there are some disadvantages in development, such as the gas cap, the weak nature energy, the thin oil-bearing formation and bottom water in some layers, the oilfield developed well by cold waterflooding. To date over 14% of its OOIP has been recovered and its production was continually improved. Since the high cost operation on offshore, few adjustments were taken in these fields. From the beginning of development, many adjustments were taken in the JZ9-3 oilfield, such as the adjustment of production layers, the well converting, the satisfaction control and the adjustment wells. These activities hold up the increasing rate of water cut, improved the oil production and make good profits. The integrate research of geology and reservoir, the sufficient well testing/logging activities and the reliable engineering operation gave solid foundations for these adjustments. (auth)

  12. Resistivity Variation Mechanism Analysis of the Petro-Rock Injected by Water

    Institute of Scientific and Technical Information of China (English)

    WANGYinghui; TANDehui

    2005-01-01

    Many oil fields have already been coming into exploitation period in the world. Physical property,lithology and oil-bearing property, etc., have been changed after oil-reservoir flooded by water, and responses of risistivity well-logging emerge in multiplicity, various welllogging responses make interpretation of water-floodedzone more difficult. But conventional resistivity welllogging series are economical and dominated tools in many oilflelds at present, it becomes more significant to research and analyse resistivity property g~ mechanism of rock injected by water. Discuss the mechanism of ""U"" type curve,including resistivity variation features of rock, relationship of Rz (mixture liquid resistivity) and Sw (water satura-tion) in water-flooded zone. Analyse various property of the most important index n based experimental curve, and display the relationship of the index n and rn according to experimental equation. At last, discuss electric property ofwater-flooded rock theoretically. All are bases to achieve more efficient interpretation model according to conventional resistivity well-logging.

  13. An Integrated Study of the Grayburg/San Andres Reservoir, Foster and South Cowden Fields, Ector County Texas

    Energy Technology Data Exchange (ETDEWEB)

    Weinbrandt, Richard; Trentham, Robert C; Robinson, William

    1997-10-23

    For a part of the Foster and South Cowden (Grayburg-San Andres) oil fields, improvement in oil production has been accomplished, in part, by using "pipeline fracturing" technology in the most recent completion to improve fluid flow rates, and filtration of waterflood injection water to preserve reservoir permeability. The 3D seismic survey acquired in conjunction with this DOE project has been used to calculate a 3D seismic inversion model, which has been analyzed to provide detailed maps of porosity within the productive upper 250 feet of the Grayburg Formation. Geologic data, particularly from logs and cores, have been combined with the geophysical interpretation and production history information to develop a model of the reservoir that defines estimations of remaining producible oil. The integrated result is greater than the sum of its parts, since no single data form adequately describes the reservoir. Each discipline relies upon computer software that runs on PC-type computers, allowing virtually any size company to affordably access the technology required to achieve similar results.

  14. Use of tracers to investigate drilling-fluid invasion and oil flushing during coring

    Energy Technology Data Exchange (ETDEWEB)

    Brown, A.; Marriott, F.T. (Texaco, Inc., Houston, TX (US))

    1988-11-01

    This work develops a method in which chemical tracers in the drilling fluid help determine mud filtrate invasion and the degree of oil flushing during coring of steamed and unsteamed heavy-oil formations. Salts of iodide and bromide were added to the drilling fluid while Well TO3 was cored through the Lombardi and Aurignac zones at San Ardo field in California. Vertical core plugs, taken from the periphery to the center of the retrieved whole core, were analyzed for tracer concentration. Tracer analyses indicated minimal filtrate invasion in the not-yet-steamflooded Lombardi zone and complete filtrate invasion in the steamflooded Aurignac zone. Tracer and oil saturation analyses showed the Lombardi zone to be uniform from top to bottom with an average oil saturation of 42.5% and an average porosity of 31.1%. Interpretation of tracer and oil saturation data permitted the construction of a layered model for the Aurignac zone. The layers ranged from an average oil saturation of 8% in the steamflooded layer to 37% in the bottom layer. The data showed that significant oil flushing (6%) occurred only in cores taken from the hot-waterflooded layer just below the steam zone. Vertical core-plug porosities and saturations, as determined by a unique calculating scheme, were compared with conventional and Elkins-corrected values. The comparison indicated that misapplication of the Elkins method in high-temperature formations may result in significant errors.

  15. Using surface heave to estimate reservoir volumetric strain

    Energy Technology Data Exchange (ETDEWEB)

    Nanayakkara, A.S.; Wong, R.C.K. [Calgary Univ., AB (Canada)

    2008-07-01

    This paper presented a newly developed numerical tool for estimating reservoir volumetric strain distribution using surface vertical displacements and solving an inverse problem. Waterflooding, steam injection, carbon dioxide sequestration and aquifer storage recovery are among the subsurface injection operations that are responsible for reservoir dilations which propagate to the surrounding formations and extend to the surface resulting in surface heaves. Global positioning systems and surface tiltmeters are often used to measure the characteristics of these surface heaves and to derive valuable information regarding reservoir deformation and flow characteristics. In this study, Tikhonov regularization techniques were adopted to solve the ill-posed inversion problem commonly found in standard inversion techniques such as Gaussian elimination and least squares methods. Reservoir permeability was then estimated by inverting the volumetric strain distribution. Results of the newly developed numerical tool were compared with results from fully-coupled finite element simulation of fluid injection problems. The reservoir volumetric strain distribution was successfully estimated along with an approximate value for reservoir permeability.

  16. Effect Analysis of Flood Pattern Optimization and Adjustment in Pingbei Oilfield%坪北油田注水系统优化调整效果分析

    Institute of Scientific and Technical Information of China (English)

    熊涛

    2015-01-01

    坪北油田注水系统存在注水能力不足,污水处理不达标,水源分布不合理等问题。为解决这些问题,坪北油田对其注水系统进行了优化调整,主要措施为:新建、改造注水站,提高注水能力;优化污水处理工艺,提高注水水质;优化系统运行,提高注水系统效率;优化注水管网系统,合理调配水资源;更换注水管线,降低安全风险。%In order to solve the problems of poor water -injection capacity ,substandard sewage treatment and unrea‐sonable water source distribution in flood pattern in Pingbei Oilfield ,optimization and adjustment has been done . Major measures include constructing or renewing water -injection plants to improve waterflooding capacity ,optimi‐zing sewage treatment process to enhance water quality ,improving system operation to make flood pattern more effi‐cient ,perfecting pipe network system to rationally distribute water source and replacing water -injection line to low‐er safety risk .

  17. Offshore heavy crude oil exploitation in Mexico phase 1 : east Campeche project

    Energy Technology Data Exchange (ETDEWEB)

    Garcia-Valenzuela, C.; Hernandez-Garcia [PEMEX E and P, Villahermosa, Tabasco (Mexico)

    2006-07-01

    Exploration in Campeche Sound, Mexico began in 1970. A number of offshore oil fields were discovered between 2004 and 2005 in this region with successful drilling of the Numan, Baksha, Pohp, Nab, Kayab, Tson, Pit, Yaxiltun, Kanche and Lem exploratory wells. Because of the quality of the oil and the complexity in the exploitation of these reservoirs, a development strategy was designed in several phases in order to ensure the feasibility and profitability through the project of exploitation called Campeche Orient. This paper discussed this development strategy and offshore heavy crude oil exploitation in Mexico and the east Campeche project. Background information on Campeche Sound was first presented. The paper also discussed oil field development of the Tson and Pohp fields including geological description and model. A numerical simulation model and exploitation cases were also analyzed and presented. Several schemes of development were analyzed, including primary recovery; thermal production processes; uncertainty analysis for pressure maintenance; waterflooding; and nitrogen injection. Other phases and topics that were discussed included field development; artificial systems; production handling and transport; project situation; and additional fields development. Last, associated risks to project execution as well as recommendations were identified. The stochastic analysis showed that there is a high probability of profitability and project execution was therefore recommended. 7 refs., 10 tabs., 19 figs.

  18. Development of a subsea system for water separation; Desenvolvimento de sistema submarino de separacao de agua produzida

    Energy Technology Data Exchange (ETDEWEB)

    Figueiredo, Mauricio W. de; Ramalho, Joao Batista V.S.; Souza, Antonio Luiz S. de; Gomes, Jose Adilson T.; Burmann, Clovis P. [PETROBRAS, Rio de Janeiro, RJ (Brazil)

    2004-07-01

    Oil production is normally followed by water production in increasing rates, mostly when waterflooding is used as oil recovery mechanism. In order to minimize the impact that high rates of produced water causes to the topside facilities , PETROBRAS is working on the development of a subsea system for oil-water separation, so that most of the produced water on the mud line can be removed and reinjected in the reservoir or in a bearing formation. The article shows how this development has been carried, the scenario definition for the pilot, the problems associated to an installation in a system already operating and the oil characteristics determination. These data constitute the base for the survey to define the technologies with potential application on the separation system to be developed. The special characteristic of the oil, with high tendency to form stable emulsions with water, are also analyzed, as well as the difficulties it brings to the process in the subsea environment, where there are vessel size and fluid heating limitations. (author)

  19. Characterization of microbial community and the alkylscccinate synthase genes in petroleum reservoir fluids of China

    Energy Technology Data Exchange (ETDEWEB)

    Zhou, Lei; Mu, Bo-Zhong [University of Science and Technology (China)], email: bzmu@ecust.edu.cn; Gu, Ji-Dong [The University of Hong Kong (China)], email: jdgu@hkucc.hku.hk

    2011-07-01

    Petroleum reservoirs represent a special ecosystem consisting of specific temperature, pressure, salt concentration, oil, gas, water, microorganisms and, enzymes among others. This paper presents the characterization of microbial community and the alkyl succinate synthase genes in petroleum reservoir fluids in China. A few samples were analyzed and the physical and chemical characteristics are given in a tabular form. A flow chart shows the methods and procedures for microbial activities. Six petroleum reservoirs were studied using an archaeal 16S rRNA gene-based approach to establish the presence of archaea and the results are given. The correlation of archaeal and bacterial communities with reservoir conditions and diversity of the arachaeal community in water-flooding petroleum reservoirs at different temperatures is also shown. From the study, it can be summarized that, among methane producers, CO2-reducing methanogens are mostly found in oil reservoir ecosystems and as more assA sequences are revealed, more comprehensive molecular probes can be designed to track the activity of anaerobic alkane-degrading organisms in the environment.

  20. Feasibility study of heavy oil recovery in the Permian Basin (Texas and New Mexico)

    Energy Technology Data Exchange (ETDEWEB)

    Olsen, D.K.; Johnson, W.I.

    1993-05-01

    This report is one of a series of publications assessing the feasibility of increasing domestic heavy oil production. Each report covers select areas of the United States. The Permian Basin of West Texas and Southeastern New Mexico is made up of the Midland, Delaware, Val Verde, and Kerr Basins; the Northwestern, Eastern, and Southern shelves; the Central Basin Platform, and the Sheffield Channel. The present day Permian Basin was one sedimentary basin until uplift and subsidence occurred during Pennsylvanian and early Permian Age to create the configuration of the basins, shelves, and platform of today. The basin has been a major light oil producing area served by an extensive pipeline network connected to refineries designed to process light sweet and limited sour crude oil. Limited resources of heavy oil (10`` to 20`` API gravity) occurs in both carbonate and sandstone reservoirs of Permian and Cretaceous Age. The largest cumulative heavy oil production comes from fluvial sandstones of the Cretaceous Trinity Group. Permian heavy oil is principally paraffinic and thus commands a higher price than asphaltic California heavy oil. Heavy oil in deeper reservoirs has solution gas and low viscosity and thus can be produced by primary and by waterflooding. Because of the nature of the resource, the Permian Basin should not be considered a major heavy oil producing area.

  1. Feasibility study of heavy oil recovery in the Permian Basin (Texas and New Mexico)

    Energy Technology Data Exchange (ETDEWEB)

    Olsen, D.K.; Johnson, W.I.

    1993-05-01

    This report is one of a series of publications assessing the feasibility of increasing domestic heavy oil production. Each report covers select areas of the United States. The Permian Basin of West Texas and Southeastern New Mexico is made up of the Midland, Delaware, Val Verde, and Kerr Basins; the Northwestern, Eastern, and Southern shelves; the Central Basin Platform, and the Sheffield Channel. The present day Permian Basin was one sedimentary basin until uplift and subsidence occurred during Pennsylvanian and early Permian Age to create the configuration of the basins, shelves, and platform of today. The basin has been a major light oil producing area served by an extensive pipeline network connected to refineries designed to process light sweet and limited sour crude oil. Limited resources of heavy oil (10'' to 20'' API gravity) occurs in both carbonate and sandstone reservoirs of Permian and Cretaceous Age. The largest cumulative heavy oil production comes from fluvial sandstones of the Cretaceous Trinity Group. Permian heavy oil is principally paraffinic and thus commands a higher price than asphaltic California heavy oil. Heavy oil in deeper reservoirs has solution gas and low viscosity and thus can be produced by primary and by waterflooding. Because of the nature of the resource, the Permian Basin should not be considered a major heavy oil producing area.

  2. Imaging techniques applied to the study of fluids in porous media

    Energy Technology Data Exchange (ETDEWEB)

    Tomutsa, L.; Brinkmeyer, A.; Doughty, D.

    1993-04-01

    A synergistic rock characterization methodology has been developed. It derives reservoir engineering parameters from X-ray tomography (CT) scanning, computer assisted petrographic image analysis, minipermeameter measurements, and nuclear magnetic resonance imaging (NMRI). This rock characterization methodology is used to investigate the effect of small-scale rock heterogeneity on oil distribution and recovery. It is also used to investigate the applicability of imaging technologies to the development of scaleup procedures from core plug to whole core, by comparing the results of detailed simulations with the images ofthe fluid distributions observed by CT scanning. By using the rock and fluid detailed data generated by imaging technology describe, one can verify directly, in the laboratory, various scaling up techniques. Asan example, realizations of rock properties statistically and spatially compatible with the observed values are generated by one of the various stochastic methods available (fuming bands) and are used as simulator input. The simulation results were compared with both the simulation results using the true rock properties and the fluid distributions observed by CT. Conclusions regarding the effect of the various permeability models on waterflood oil recovery were formulated.

  3. National Institute for Petroleum and Energy Research monthly progress report, May 1993

    Energy Technology Data Exchange (ETDEWEB)

    1993-06-01

    Accomplishments for the month of May are described briefly under tasks for: Energy Production Research; Fuels Research; and Supplemental Government Program. Energy Production Research includes: reservoir assessment and characterization; TORIS research support; development of improved microbial flooding methods; development of improved chemical flooding methods; development of improved alkaline flooding methods; mobility control and sweep improvement in chemical flooding; gas flood performance prediction improvement; mobility control, profile modification, and sweep improvement in gas flooding; three-phase relative permeability research; thermal processes for light oil recovery; thermal processes for heavy oil recovery; and imaging techniques applied to the study of fluids in porous media. Fuels Research covers: development of analytical methodology for analysis of heavy crudes; and thermochemistry and thermophysical properties of organic nitrogen- and diheteratom-containing compounds. Supplemental Government Program covers: microbial-enhanced waterflooding field project; feasibility study of heavy oil recovery in the midcontinent region--Oklahoma, Kansas, and Missouri; surfactant-enhanced alkaline flooding field project; process-engineering property measurements on heavy petroleum components; development and application of petroleum production technologies; upgrade BPO crude oil data base; simulation analysis of steam-foam projects; DOE education initiative project; field application of foams for oil production symposium; technology transfer to independent producers; compilation and analysis of outcrop data from the Muddy and Almond formations; implementation of oil and gas technology transfer initiative; horizontal well production from fractured reservoirs; and chemical EOR workshop.

  4. National Institute for Petroleum and Energy Research quarterly technical report, January 1--March 31, 1993

    Energy Technology Data Exchange (ETDEWEB)

    1993-06-01

    Accomplishments for the past quarter are briefly described for the following tasks: chemical flooding -- supporting research; gas displacement -- supporting research; thermal recovery -- supporting research; geoscience technology; resource assessment technology; and microbial technology. Chemical flooding covers: surfactant flooding methods; development of improved alkaline flooding methods; mobility control and sweep improvement in chemical flooding; and surfactant-enhanced alkaline flooding field project. Gas displacement covers: gas flooding performance prediction improvement; and mobility control, profile modification and sweep improvement in gas flooding. Thermal recovery includes: thermal processes for light oil recovery; thermal processes for heavy oil recovery; and feasibility study of heavy oil recovery in the mid-continent region -- Oklahoma, Kansas, and Missouri; simulation analysis of steam-foam projects; and field application of foams for oil production symposium. Geoscience technology covers: three-phase relative permeability; and imaging techniques applied to the study of fluids in porous media. Resource assessment technology includes: reservoir assessment and characterization; TORIS research support; upgrade the BPO crude oil analysis data base; and compilation and analysis of outcrop data from the Muddy and Almond Formations. Microbial technology covers development of improved microbial flooding methods; and microbial-enhanced waterflooding field project.

  5. Monthly progress report for April 1993

    Energy Technology Data Exchange (ETDEWEB)

    1993-05-01

    Accomplishments for the month of April are described briefly for the following tasks: energy production research; fuels research; and supplemental government program. Energy production research includes: reservoir assessment and characterization; TORIS research support; development of improved microbial flooding methods; development of improved chemical flooding methods; development of improved alkaline flooding methods; mobility control and sweep improvement in chemical flooding; gas flood performance prediction improvement; mobility control, profile modification, and sweep improvement in gas flooding; three-phase relative permeability research; thermal processes for light oil recovery; thermal processes for heavy oil recovery; and imaging techniques applied to the study of fluids in porous media. Fuel research includes: development of analytical methodology for analysis of heavy crudes; and thermochemistry and thermophysical properties of organic nitrogen- and diheteratom-containing compounds. Supplemental government program includes: microbial-enhanced waterflooding field project; feasibility study of heavy oil recovery in the midcontinent region--Oklahoma, Kansas, and Missouri; surfactant-enhanced alkaline flooding field project; process- engineering property measurements on heavy petroleum components; development and application of petroleum production technologies; upgrade BPO crude oil data base; simulation analysis of steam-foam projects; DOE education initiative project; field application of foams for oil production symposium; technology transfer to independent producers; compilations and analysis of outcrop data from the Muddy and Almond Formations; implementation of oil and gas technology transfer initiative; and horizontal well production from fractured reservoirs.

  6. [National Institute for Petroleum and Energy Research] monthly progress report for July 1993

    Energy Technology Data Exchange (ETDEWEB)

    1993-08-01

    Brief progress reports are presented under the following tasks: energy production research; fuels research; and supplemental Government programs. Energy production research includes: reservoir assessment and characterization; TORIS research support; development of improved microbial flooding methods; development of improved chemical flooding methods; development of improved alkaline flooding methods; mobility control and sweep improvement in chemical flooding; gas flood performance prediction improvement; mobility control, profile modification, and sweep improvement in gas flooding; three-phase relative permeability research; thermal processes for light oil recovery; thermal processes for heavy oil recovery; and imaging techniques applied to the study of fluids in porous media. Fuels research covers; development of analytical methodology for analysis of heavy crudes; and thermochemistry and thermophysical properties of organic nitrogen- and diheteroatom-containing compounds. Supplemental Government program includes: microbial-enhanced waterflooding field project; feasibility study of heavy oil recovery in the Midcontinent region: Oklahoma, Kansas, and Missouri; surfactant-enhanced alkaline flooding field project; process-engineering property measurements on heavy petroleum components; development and application of petroleum production technologies; upgrade PBO crude oil database; simulation analysis of steam-foam projects; DOE education initiative project; technology transfer to independent producers; compilation and analysis of outcrop data from the Muddy and Almond formations; implementation of oil and gas technology transfer initiative; horizontal well production from fractured reservoirs; chemical EOR workshop; and organization of UNITAR 6th International conference of Heavy Crude and Tar Sands.

  7. [National Institute for Petroleum and Energy Research] quarterly technical report for April--June 30, 1993. Volume 2, Energy Production Research

    Energy Technology Data Exchange (ETDEWEB)

    1993-09-01

    Progress reports are presented for: chemical flooding--supporting research; gas displacement--supporting research; thermal recovery--supporting research; geoscience technology; resource assessment technology; and microbial technology. Chemical flooding includes; development of improved chemical flooding methods; development of improved alkaline flooding methods; mobility control and sweep improvement in chemical flooding; and surfactant-enhanced alkaline flooding field project. Gas displacement research covers: gas flooding performance prediction improvement; and mobility control, profile modification, and sweep improvement in gas flooding. Thermal recovery research includes: thermal processes for light oil recovery; thermal processes for heavy oil recovery; feasibility study of heavy oil recovery in the Midcontinent region: Oklahoma, Kansas, and Missouri; simulation analysis of steam-foam projects; and organization of UNITAR 6th International Conference on Heavy Crude and Tar Sands. Geoscience technology covers: three-phase relative permeability; and imaging techniques applied to the study of fluids in porous media. Resource assessment technology includes: reservoir assessment and characterization; TORIS research support; upgrade the BPO Crude Oil Analysis Data Base; compilation and analysis of outcrop data from the Muddy and Almond Formations; and horizontal well production from fractured reservoir. Microbial Technology covers: development of improved microbial flooding methods; and microbial-enhanced waterflooding field project.

  8. [National Institute for Petroleum and Energy Research] monthly progress report, January 1993

    Energy Technology Data Exchange (ETDEWEB)

    1993-03-01

    Accomplishments for the month of January are briefly described for the following tasks: energy production research; fuels research; and supplemental government programs. Energy production research includes: reservoir assessment and characterization; TORI research support; development of improved microbial flooding methods; development of improved chemical flooding methods; development of improved alkaline flooding methods; mobility control and sweep improvement in chemical flooding; gas flood performance prediction improvement; mobility control, profile modifications, and sweep improvement in gas flooding; three-phase relative permeability research; thermal processes for light oil recovery; thermal processes for heavy oil recovery; and imaging techniques applied to the study of fluid in porous media. Fuel research includes: development of analytical methodology for analysis of heavy crudes; and thermochemistry and thermophysical properties of organic nitrogen and diheteroatom containing compounds. supplemental Government program includes: microbial-enhanced waterflooding field project; feasibility study of heavy oil recovery in the midcontinent region--Oklahoma, Kansas, and Missouri; surfactant- enhanced alkaline flooding field project; process-engineering property measurements on heavy petroleum components; development and application of petroleum production technologies; upgrade BPO crude oil data base; simulation analysis of steam-foam projects; DOE education initiative project; field application of foams for oil production symposium; technology transfer to independent producers; and compilations and analysis of outcrop data from the Muddy and Almond formations.

  9. National Institute for Petroleum and Energy Research quarterly technical report, January 1--March 31, 1993. Volume 2, Energy production research

    Energy Technology Data Exchange (ETDEWEB)

    1993-06-01

    Accomplishments for the past quarter are briefly described for the following tasks: chemical flooding -- supporting research; gas displacement -- supporting research; thermal recovery -- supporting research; geoscience technology; resource assessment technology; and microbial technology. Chemical flooding covers: surfactant flooding methods; development of improved alkaline flooding methods; mobility control and sweep improvement in chemical flooding; and surfactant-enhanced alkaline flooding field project. Gas displacement covers: gas flooding performance prediction improvement; and mobility control, profile modification and sweep improvement in gas flooding. Thermal recovery includes: thermal processes for light oil recovery; thermal processes for heavy oil recovery; and feasibility study of heavy oil recovery in the mid-continent region -- Oklahoma, Kansas, and Missouri; simulation analysis of steam-foam projects; and field application of foams for oil production symposium. Geoscience technology covers: three-phase relative permeability; and imaging techniques applied to the study of fluids in porous media. Resource assessment technology includes: reservoir assessment and characterization; TORIS research support; upgrade the BPO crude oil analysis data base; and compilation and analysis of outcrop data from the Muddy and Almond Formations. Microbial technology covers development of improved microbial flooding methods; and microbial-enhanced waterflooding field project.

  10. Imaging techniques applied to the study of fluids in porous media. Scaling up in Class 1 reservoir type rock

    Energy Technology Data Exchange (ETDEWEB)

    Tomutsa, L.; Brinkmeyer, A.; Doughty, D.

    1993-04-01

    A synergistic rock characterization methodology has been developed. It derives reservoir engineering parameters from X-ray tomography (CT) scanning, computer assisted petrographic image analysis, minipermeameter measurements, and nuclear magnetic resonance imaging (NMRI). This rock characterization methodology is used to investigate the effect of small-scale rock heterogeneity on oil distribution and recovery. It is also used to investigate the applicability of imaging technologies to the development of scaleup procedures from core plug to whole core, by comparing the results of detailed simulations with the images ofthe fluid distributions observed by CT scanning. By using the rock and fluid detailed data generated by imaging technology describe, one can verify directly, in the laboratory, various scaling up techniques. Asan example, realizations of rock properties statistically and spatially compatible with the observed values are generated by one of the various stochastic methods available (fuming bands) and are used as simulator input. The simulation results were compared with both the simulation results using the true rock properties and the fluid distributions observed by CT. Conclusions regarding the effect of the various permeability models on waterflood oil recovery were formulated.

  11. [National Institute for Petroleum and Energy Research], monthly progress report for March 1993

    Energy Technology Data Exchange (ETDEWEB)

    1993-04-01

    Accomplishments for the month of April are described briefly under tasks for: Energy Production Research; Fuels Research; and Supplemental Government Program. Energy Production Research includes: reservoir assessment and characterization; TORIS research support; development of improved microbial flooding methods; development of improved chemical flooding methods; development of improved alkaline flooding methods; mobility control and sweep improvement in chemical flooding; gas flood performance prediction improvement; mobility control, profile modification, and sweep improvement in gas flooding; three-phase relative permeability research; thermal processes for light oil recovery; thermal processes for heavy oil recovery; and imaging techniques applied to the study of fluids in porous media. Fuels Research includes: development of analytical methodology for analysis of heavy crudes; and thermochemistry and thermophysical properties of organic nigrogen- and diheteroatom-containing compounds. Supplemental Government Program includes: microbial-enhanced waterflooding field project; feasibility study of heavy oil recovery in the midcontinent region--Oklahoma, Kansas, and Missouri; surfactant- enhanced alkaline flooding field project; process- engineering property measurements on heavy petroleum components; development and application of petroleum production technologies; upgrade BPO crude oil data base; simulation analysis of steam-foam projects; DOE education initiative project; field application of foams of oil production symposium; technology transfer to independent producers; compilations and analysis of outcrop data from the Muddy and Almond formations; and horizontal well production from fractured reservoirs.

  12. 1963 : Oilweek changes hands

    Energy Technology Data Exchange (ETDEWEB)

    Anon.

    2008-06-15

    This article was a tribute to the founder of Oilweek, who in September 1963, sold the magazine to Maclean-Hunter Publishing. For 3 years, C.V. Myers resisted pressure to sell what was known as the best magazine in the oil patch at the time. Myers travelled for stories to Washington, Venezuela, England, Holland, Germany, Italy, North Africa, Iraq, Kuwait, Saudi Arabia and Egypt for stories. Writers were also sent to cover stories from Ottawa to Mexico. On the same day that Oilweek was sold, Maclean-Hunter also bought Oil in Canada and merged the two to become Oilweek. Other key events in 1963 included the proposal by federal finance minister to create a 30 per cent takeover tax; gas compressor stations turn to turbines, making them more fuel efficient and less costly to operate; and, the world's largest waterflood was planned for the Weyburn field in Saskatchewan, with an ultimate recovery expected to exceed 180 million barrels. 1 tab., 1 fig.

  13. 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.

  14. 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.

  15. 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.

  16. 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.

  17. Nanoparticle-stabilized CO₂ foam for CO₂ EOR application

    Energy Technology Data Exchange (ETDEWEB)

    Liu, Ning [New Mexico Petroleum Recovery Research Center, Socorro, NM (United States); Lee, Robert [New Mexico Petroleum Recovery Research Center, Socorro, NM (United States); Yu, Jianjia [New Mexico Petroleum Recovery Research Center, Socorro, NM (United States); Li, Liangxiong [New Mexico Petroleum Recovery Research Center, Socorro, NM (United States); Bustamante, Elizabeth [New Mexico Petroleum Recovery Research Center, Socorro, NM (United States); Khalil, Munawar [New Mexico Petroleum Recovery Research Center, Socorro, NM (United States); Mo, Di [New Mexico Petroleum Recovery Research Center, Socorro, NM (United States); Jia, Bao [New Mexico Petroleum Recovery Research Center, Socorro, NM (United States); Wang, Sai [New Mexico Petroleum Recovery Research Center, Socorro, NM (United States); San, Jingshan [New Mexico Petroleum Recovery Research Center, Socorro, NM (United States); An, Cheng [New Mexico Petroleum Recovery Research Center, Socorro, NM (United States)

    2015-01-31

    The purpose of this project was to develop nanoparticle-stabilized CO₂ foam for CO₂ -EOR application, in which nanoparticles instead of surfactants are used for stabilizing CO₂ foam to improve the CO₂ sweep efficiency and increase oil recovery. The studies included: (1) investigation of CO₂ foam generation nanoparticles, such as silica nanoparticles, and the effects of particle concentration and surface properties, CO₂/brine ratio, brine salinity, pressure, and temperature on foam generation and foam stability; (2) coreflooding tests to understand the nanoparticle-stabilized CO₂ foam for waterflooded residual oil recovery, which include: oil-free coreflooding experiments with nanoparticle-stabilized CO₂ foam to understand the transportation of nanoparticles through the core; measurements of foam stability and CO₂ sweep efficiency under reservoir conditions to investigate temperature and pressure effects on the foam performance and oil recovery as well as the sweep efficiency in different core samples with different rock properties; and (3) long-term coreflooding experiments with the nanoparticle- stabilized CO₂ foam for residual oil recovery. Finally, the technical and economical feasibility of this technology was evaluated.

  18. Breakdown of doublet recirculation and direct line drives by far-field flow in reservoirs: implications for geothermal and hydrocarbon well placement

    Science.gov (United States)

    Weijermars, R.; van Harmelen, A.

    2016-07-01

    An important real world application of doublet flow occurs in well design of both geothermal and hydrocarbon reservoirs. A guiding principle for fluid management of injection and extraction wells is that mass balance is commonly assumed between the injected and produced fluid. Because the doublets are considered closed loops, the injection fluid is assumed to eventually reach the producer well and all the produced fluid ideally comes from stream tubes connected to the injector of the well pair making up the doublet. We show that when an aquifer background flow occurs, doublets will rarely retain closed loops of fluid recirculation. When the far-field flow rate increases relative to the doublet's strength, the area occupied by the doublet will diminish and eventually vanishes. Alternatively, rather than using a single injector (source) and single producer (sink), a linear array of multiple injectors separated by some distance from a parallel array of producers can be used in geothermal energy projects as well as in waterflooding of hydrocarbon reservoirs. Fluid flow in such an arrangement of parallel source-sink arrays is shown to be macroscopically equivalent to that of a line doublet. Again, any far-field flow that is strong enough will breach through the line doublet, which then splits into two vortices. Apart from fundamental insight into elementary flow dynamics, our new results provide practical clues that may contribute to improve the planning and design of doublets and direct line drives commonly used for flow management of groundwater, geothermal and hydrocarbon reservoirs.

  19. (National Institute for Petroleum and Energy Research) monthly progress report, July 1992

    Energy Technology Data Exchange (ETDEWEB)

    1992-09-01

    Accomplishments for the month of July are described briefly under tasks for: Energy Production Research; Fuels Research; and Supplemental Government Program. Energy Production Research includes: reservoir assessment and characterization; TORIS research support; development of improved microbial flooding methods; surfactant flooding methods; development of improved alkaline flooding methods; mobility control and sweep improvement in chemical flooding; gas flood performance prediction improvement; mobility control, profile modification, and sweep improvement in gas flooding; three-phase relative permeability research; thermal processes for light oil recovery; thermal processes for heavy oil recovery; and imaging techniques applied to the study of fluids in porous media. Fuel Research includes: development of analytical methodology for analysis of heavy crudes; and thermochemistry and thermophysical properties of organic nitrogen- and diheteroatom-containing compounds. Supplement Government Program includes: microbial-enhanced waterflooding field project; feasibility study of heavy oil recovery in the midcontinent region--Oklahoma, Kansas, and Missouri; surfactant-enhanced alkaline flooding field project; development of methods for mapping distribution of clays in petroleum reservoirs; summary of geological and production characteristics of class 1. unstructured, deltaic reservoirs; third international reservoir characterization technical conference; process-engineering property measurements on heavy petroleum components; development and application of petroleum production technologies; upgrade BPO crude oil data base; simulation analysis of steam-foam projects; analysis of the US oil resource base and estimate of future recoverable oil; DOE education initiative project; and technology transfer to independent producers.

  20. [National Institute for Petroleum and Energy Research] monthly progress report, July 1992

    Energy Technology Data Exchange (ETDEWEB)

    1992-09-01

    Accomplishments for the month of July are described briefly under tasks for: Energy Production Research; Fuels Research; and Supplemental Government Program. Energy Production Research includes: reservoir assessment and characterization; TORIS research support; development of improved microbial flooding methods; surfactant flooding methods; development of improved alkaline flooding methods; mobility control and sweep improvement in chemical flooding; gas flood performance prediction improvement; mobility control, profile modification, and sweep improvement in gas flooding; three-phase relative permeability research; thermal processes for light oil recovery; thermal processes for heavy oil recovery; and imaging techniques applied to the study of fluids in porous media. Fuel Research includes: development of analytical methodology for analysis of heavy crudes; and thermochemistry and thermophysical properties of organic nitrogen- and diheteroatom-containing compounds. Supplement Government Program includes: microbial-enhanced waterflooding field project; feasibility study of heavy oil recovery in the midcontinent region--Oklahoma, Kansas, and Missouri; surfactant-enhanced alkaline flooding field project; development of methods for mapping distribution of clays in petroleum reservoirs; summary of geological and production characteristics of class 1. unstructured, deltaic reservoirs; third international reservoir characterization technical conference; process-engineering property measurements on heavy petroleum components; development and application of petroleum production technologies; upgrade BPO crude oil data base; simulation analysis of steam-foam projects; analysis of the US oil resource base and estimate of future recoverable oil; DOE education initiative project; and technology transfer to independent producers.

  1. Field project to obtain pressure core, wireline log, and production test data for evaluation of CO/sub 2/ flooding potential. Conoco MCA unit well No. 358, Maljamar Field, Lea County, New Mexico. Final report

    Energy Technology Data Exchange (ETDEWEB)

    Swift, T.E.; Kumar, R.M.; Marlow, R.E.; Wilhelm, M.H.

    1982-08-01

    Field operations, which were conducted as a cooperative effort between Conoco and Gruy Federal, began on January 16, 1980 when the well was spudded. The well was drilled to 3692 feet, and 18 cores recovered in 18 core-barrel runs (144 feet). Upon completion of the coring phase, the hole was drilled to a total depth of 4150 feet and a complete suite of geophysical logs was run. Logging was then followed by completion and testing by Concoco. Core porosities agreed well with computed log porosities. Core water saturation and computed log porosities agree fairly well from 3692 to 3712 feet, poorly from 3712 to 3820 feet and in a general way from 4035 to 4107 feet. Computer log analysis techniques did not improve the agreement of log versus core derived water saturations. However, both core and log analysis indicated the ninth zone had the highest residual hydrocarbon saturations. Residual oil saturation were 259 STB/acre-ft for the 4035 - 4055 feet interval, and 150 STB/acre-ft for the 3692 - 3718 feet interval. Nine BOPD was produced from the 4035 - 4055 feet interval and no oil was produced from 3692 to 3718 feet interval, qualitatively confirming the relative oil saturations. The low oil production in the zone from 4022 to 4055 and the lack of production from 3692 to 3718 feet indicated the zone to be at or near residual waterflood conditions as determined by log analysis. 68 figures, 11 tables.

  2. PEMANFAATAN METIL ESTER JARAK PAGAR MENJADI SURFAKTAN MES UNTUK APLIKASI SEBAGAI OIL WELL STIMULATION AGENT

    Directory of Open Access Journals (Sweden)

    Erliza Hambali

    2012-04-01

    Full Text Available Year by year, globally the production of petroleum decreases but its demand increases. The world will get the energy crisis including Indonesia if that condition happens continously. Because of that, Indonesia starts to develop IOR (improved oil recovery method for their oil fields. IOR method is an improvement of the secondary phase in which the oil recovery is expected to increase oil production. One method of IOR is chemical injection with surfactant for injection. Surfactant is dissolved with injection water and injected to reservoir. Generally, surfactant of petroleum sulphonates is used for oil recovery. Due to the weaknesses of petroleum suphonates such as not resistant in high salinity and high hardness water, therefore it triggers to get surfactant substitute like MES (methyl ester sulphonates that is synthesized by bio-oil from Jatropha curcas L. The study was aimed to know the performance of MES surfactant formula from jatropha oil for IOR in fluid sample of oil field and synthetic sandstone core. The best condition from this research was surfactant 0.2 PV with the soaking time of 12 hours. This formula gave the highest of incremental total oil recovery 61%. The number were resulted from 48% waterflooding and 13% surfactant injection.

  3. Parametric analysis of surfactant-aided imbibition in fractured carbonates.

    Science.gov (United States)

    Adibhatla, B; Mohanty, K K

    2008-01-15

    Many carbonate oil reservoirs are oil-wet and fractured; waterflood recovery is very low. Dilute surfactant solution injection into the fractures can improve oil production from the matrix by altering the wettability of the rock to a water-wetting state. A 2D, two-phase, multicomponent, finite-volume, fully-implicit numerical simulator calibrated with our laboratory results is used to assess the sensitivity of the process to wettability alteration, IFT reduction, oil viscosity, surfactant diffusivity, matrix block dimensions, and permeability heterogeneity. Capillarity drives the oil production at the early stage, but gravity is the major driving force afterwards. Surfactants which alter the wettability to a water-wet regime give higher recovery rates for higher IFT systems. Surfactants which cannot alter wettability give higher recovery for lower IFT systems. As the wettability alteration increases the rate of oil recovery increases. Recovery rate decreases with permeability significantly for a low tension system, but only mildly for high tension systems. Increasing the block dimensions and increasing oil viscosity decreases the rate of oil recovery and is in accordance with the scaling group for a gravity driven process. Heterogeneous layers in a porous medium can increase or decrease the rate of oil recovery depending on the permeability and the aspect ratio of the matrix block.

  4. Progress in crosswell induction imaging for EOR: field system design and field testing

    Energy Technology Data Exchange (ETDEWEB)

    Kirkendall, B A; Lewis, J P; Hunter, S L; Harben, P E

    1999-03-04

    At Lawrence Livermore National Laboratory (LLNL), we are continuing our effort to develop improved crosswell low-frequency electromagnetic imaging techniques, which are used to map in situ steamflood and waterflood movement during enhanced oil recovery (EOR) operations. Toward this effort, we procured two new borehole-logging field vehicles, and developed and integrated new crosswell electromagnetic transmitter and receiver data acquisition and control systems into these vehicles. We tested this new acquisition system by conducting a suite of background measurements and repeatability experiments at the Richmond Field Station in Richmond, California. Repeatability of a given scan in which the receiver was fixed and the transmitter position was varied over 60 m in 0.2-m increments resulted in amplitude differences of less than 0.6% and phase differences of less than 0.54 deg. Forward modeling produced a resistivity map fully consistent with well log data from the Richmond Field Station. In addition, modeling results suggest (1) that residual high-conductivity saltwater, injected in 1993 and pumped out in 1995, is present at the site and (2) that it has diffused outward from the original target strata. To develop crosswell electromagnetic imaging into a viable commercial product, our future research must be a two-fold approach: (1) improved quantification of system noise through experiments such as ferromagnetic core characterization as a function of temperature, and (2) development of procedures and codes to account for steel-cased hole scenarios.

  5. Horizontal high-pressure air injection well construction and operation

    Energy Technology Data Exchange (ETDEWEB)

    Hume, J. [Continental Resources Inc., ND (United States)

    2005-07-01

    This paper discussed the design and operational challenges of a horizontal high-pressure air injection well currently in use at the Cedar Hill Red River B field in North Dakota. The field was developed in 1994, using horizontal wells oriented from the northeast to the southwest corners of each section on 640 acre spacing. In March of 2001, the field was unitized resulting in a horizontal waterflood project and a 320 acre horizontal high pressure air injection project. Extreme temperatures and pressures occurring in the reservoir from the combustion processes associated with high pressure air injection have resulted in several challenges. Reservoir and fluid properties of the field were presented, as well as a type log. Details of the Buffalo and Cedar Hills field were also provided, with a comparison of horizontal and vertical patterns. A light oil displacement process was reviewed, with details of tubing leak corrosion, packer seal and detonation failures. Burn front exposure to casing was discussed, and a wellbore diagram was provided. Various horizontal conversions were discussed. A description of the Cedar Hills Compressor Station and compression trains was provided. It was concluded that knowledge gained from 25 years of vertical high pressure air injection experience has been successfully incorporated to create a safe and durable design. 1 tab., 16 figs.

  6. Surfactant enhanced volumetric sweep efficiency

    Energy Technology Data Exchange (ETDEWEB)

    Harwell, J.H.; Scamehorn, J.F.

    1989-10-01

    Surfactant-enhanced waterflooding is a novel EOR method aimed to improve the volumetric sweep efficiencies in reservoirs. The technique depends upon the ability to induce phase changes in surfactant solutions by mixing with surfactants of opposite charge or with salts of appropriate type. One surfactant or salt solution is injected into the reservoir. It is followed later by injection of another surfactant or salt solution. The sequence of injections is arranged so that the two solutions do not mix until they are into the permeable regions well away from the well bore. When they mix at this point, by design they form a precipitate or gel-like coacervate phase, plugging this permeable region, forcing flow through less permeable regions of the reservoir, improving sweep efficiency. The selectivity of the plugging process is demonstrated by achieving permeability reductions in the high permeable regions of Berea sandstone cores. Strategies were set to obtain a better control over the plug placement and the stability of plugs. A numerical simulator has been developed to investigate the potential increases in oil production of model systems. Furthermore, the hardness tolerance of anionic surfactant solutions is shown to be enhanced by addition of monovalent electrolyte or nonionic surfactants. 34 refs., 32 figs., 8 tabs.

  7. 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.

  8. 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.

  9. Extracting maximum petrophysical and geological information from a limited reservoir database

    Energy Technology Data Exchange (ETDEWEB)

    Ali, M.; Chawathe, A.; Ouenes, A. [New Mexico Institute of Mining and Technology, Socorro, NM (United States)] [and others

    1997-08-01

    The characterization of old fields lacking sufficient core and log data is a challenging task. This paper describes a methodology that uses new and conventional tools to build a reliable reservoir model for the Sulimar Queen field. At the fine scale, permeability measured on a fine grid with a minipermeameter was used in conjunction with the petrographic data collected on multiple thin sections. The use of regression analysis and a newly developed fuzzy logic algorithm led to the identification of key petrographic elements which control permeability. At the log scale, old gamma ray logs were first rescaled/calibrated throughout the entire field for consistency and reliability using only four modem logs. Using data from one cored well and the rescaled gamma ray logs, correlations between core porosity, permeability, total water content and gamma ray were developed to complete the small scale characterization. At the reservoir scale, outcrop data and the rescaled gamma logs were used to define the reservoir structure over an area of ten square miles where only 36 wells were available. Given the structure, the rescaled gamma ray logs were used to build the reservoir volume by identifying the flow units and their continuity. Finally, history-matching results constrained to the primary production were used to estimate the dynamic reservoir properties such as relative permeabilities to complete the characterization. The obtained reservoir model was tested by forecasting the waterflood performance and which was in good agreement with the actual performance.

  10. Reservoir compartmentalization and management strategies: Lessons learned in the Illinois basin

    Energy Technology Data Exchange (ETDEWEB)

    Grube, J.P.; Crockett, J.E.; Huff, B.G. [and others

    1997-08-01

    A research project jointly sponsored by the US Department of Energy and the Illinois State Geological Survey focused on the Cypress and Aux Vases Formations (Mississippian), major clastic reservoirs in the Illinois Basin. Results from the research showed that understanding the nature and distribution of reservoir compartments, and using effective reservoir management strategies, can significantly improve recovery efficiencies from oil fields in this mature basin. Compartments can be most effectively drained where they are geologically well defined and reservoir management practices are coordinated through unified, compartment-wide, development programs. Our studies showed that the Cypress and Aux Vases reservoirs contain lateral and vertical permeability barriers forming compartments that range in size from isolated, interlaminated sandstone and shale beds to sandstone bodies tens of feet in thickness and more than a mile in length. Stacked or shingled, genetically similar sandstone bodies are commonly separated by thin impermeable intervals that can be difficult to distinguish on logs and can, therefore, cause correlation problems, even between wells drilled on spacing of less than ten acres. Lateral separation of sandstone bodies causes similar problems. Reservoir compartmentalization reduces primary and particularly secondary recovery by trapping pockets of by-passed or banked oil. Compartments can be detected by comparing recovery factors of genetically similar sandstone bodies within a field; using packers to separate commingled intervals and analyzing fluid recoveries and pressures; making detailed core-to-log calibrations that identify compartment boundaries; and analyzing pressure data from waterflood programs.

  11. Evaluation and prevention of formation damage in offshore sandstone reservoirs in China

    Institute of Scientific and Technical Information of China (English)

    Yang Shenglai; Sheng Zhichao; Liu Wenhui; Song Zhixue; Wu Ming; Zhang Jianwei

    2008-01-01

    Reduction in water injectivity would be harmful to the waterflood development of offshore sandstone oil reservoirs. In this paper the magnitude of formation damage during water injection was evaluated by analyzing the performance of water injection in the Bohai offshore oilfield, China. Two parameters, permeability reduction and rate of wellhead pressure rise, were proposed to evaluate the formation damage around injection wells. The pressure performance curve could be divided into three stages with different characteristics. Analysis of field data shows that formation damage caused by water injection was severe in some wells in the Bohai offshore oilfield, China. In the laboratory, the content of clay minerals in reservoir rock was analyzed and sensitivity tests (including sensitivity to water,flow rate, alkali, salt and acid) were also conducted. Experimental results show that the reservoir had a strong to medium sensitivity to water (i.e. clay swelling) and a strong to medium sensitivity to flow rate,which may cause formation damage. For formation damage prevention, three injection schemes of clay stabilizer (CS) were studied, i.e. continuous injection of low concentration CS (Ci), slug injection of high concentration CS (SI), and slug injection of high concentration CS followed by continuous injection of low concentration CS (SI-CI). Core flooding experiments show that SI-CI is an effective scheme to prevent formation damage and is recommended for the sandstone oil reservoirs in the Bohai offshore oilfield during water injection.

  12. Automatic method for estimation of in situ effective contact angle from X-ray micro tomography images of two-phase flow in porous media.

    Science.gov (United States)

    Scanziani, Alessio; Singh, Kamaljit; Blunt, Martin J; Guadagnini, Alberto

    2017-02-08

    Multiphase flow in porous media is strongly influenced by the wettability of the system, which affects the arrangement of the interfaces of different phases residing in the pores. We present a method for estimating the effective contact angle, which quantifies the wettability and controls the local capillary pressure within the complex pore space of natural rock samples, based on the physical constraint of constant curvature of the interface between two fluids. This algorithm is able to extract a large number of measurements from a single rock core, resulting in a characteristic distribution of effective in situ contact angle for the system, that is modelled as a truncated Gaussian probability density distribution. The method is first validated on synthetic images, where the exact angle is known analytically; then the results obtained from measurements within the pore space of rock samples imaged at a resolution of a few microns are compared to direct manual assessment. Finally the method is applied to X-ray micro computed tomography (micro-CT) scans of two Ketton cores after waterflooding, that display water-wet and mixed-wet behaviour. The resulting distribution of in situ contact angles is characterized in terms of a mixture of truncated Gaussian densities.

  13. The Application of Adaptive Mesh Methods to Petroleum Reservoir Simulation Application des méthodes de maillages évolutifs à la simulation de réservoirs pétroliers

    Directory of Open Access Journals (Sweden)

    Lewis R. W.

    2006-11-01

    Full Text Available This paper describes the application of adaptive mesh methods to the numerical simulation of one and two-dimensional petroleum reservoir waterfloods. The method uses current information on the solution to adapt the mesh to the solution as the computation proceeds. It is shown that this leads to significant improvements in accuracy at a marginal increase in computational cost. Cet article décrit l'application des méthodes de maillages évolutifs à la simulation numérique dinjection d'eau à une ou deux dimensions dans des réservoirs pétroliers. La méthode utilise des informations disponibles sur la solution pour adapter le maillage à la solution pendant que se déroule le calcul. On montre que cela conduit à des améliorations significatives en ce qui concerne la précision avec une augmentation marginale du coût des calculs.

  14. Comparison between micro-emulsion and surfactant solution flooding efficiency for enhanced oil recovery in TinFouye Oil Field

    Energy Technology Data Exchange (ETDEWEB)

    Bouabboune, M.; Benhadid, S. [Applied and Theoretical Fluid Mechanical Laboratory, Algiers (Algeria). Faculty of Physics; Hammouch, N. [Sonatrach, Hydra, Algiers (Algeria). Forage Division

    2006-07-01

    The TinFouye (TFY) reservoir is among the largest oil reservoirs discovered in Algeria. The reservoir has been extensively gas lifted for many years, but gas lift is now reaching its economic limits. Therefore, a tertiary enhancement method is needed. This report investigated the technical feasibility of applying a microemulsion flood to TFY reservoir. The purpose of the study was to optimize the concentration of surfactant, in order to obtain a lower interfacial tension between oil and microemulsion phases, and a high viscosity of the microemulsion compared to that of the oil phase. Another objective was to test the effectiveness of the obtained optimum chemical system for the displacement of residual oil saturation after waterflooding (secondary recovery). TinFouye reservoir conditions and samples were used in this study. Geomechanical equipment was used for the displacement experiments in porous media. Two optimum microemulsion compositions were determined through phase behavior studies: 4 wt per cent anionic surfactant, 2.5 wt per cent pentanol, total salinity of 0.5 g/l. Two surfactant solutions were prepared with the same anionic and alcohol concentration as those of the optimized microemulsions. This made it possible to compare the efficiency of displacing residual oil saturation. 12 refs., 5 tabs., 4 figs.

  15. 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.

  16. Chemical and biological monitoring of MIOR on the pilot area of Vyngapour oil field, West Sibera, Russia

    Energy Technology Data Exchange (ETDEWEB)

    Arinbasarov, M.U.; Murygina, V.P.; Mats, A.A.

    1995-12-31

    The pilot area of the Vyngapour oil field allotted for MIOR tests contains three injection and three producing wells. These wells were treated in summer 1993 and 1994. Before, during, and after MIOR treatments on the pilot area the chemical compounds of injected and formation waters were studied, as well as the amount and species of microorganisms entering the stratum with the injected water and indigenous bacteria presented in bottomhole zones of the wells. The results of monitoring showed that the bottomhole zone of the injection well already had biocenosis of heterotrophic, hydrocarbon-oxidizing, methanogenic, and sulfate-reducing bacteria, which were besides permanently introduced into the reservoir during the usual waterflooding. The nutritious composition activated vital functions of all bacterial species presented in the bottomhole zone of the injection well. The formation waters from producing wells showed the increase of the content of nitrate, sulfate, phosphate, and bicarbonate ions by the end of MIOR. The amount of hydrocarbon-oxidizing bacteria in formation waters of producing wells increased by one order. The chemical and biological monitoring revealed the activation of the formation microorganisms, but no transport of food industry waste bacteria through the formation from injection to producing wells was found.

  17. 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.

  18. Capillary flow in porous media under highly reduced gravity investigated through high altitude parabolic aircraft flights and NASA space shuttle flight

    Energy Technology Data Exchange (ETDEWEB)

    Schramm, L.L. [Saskatchewan Research Council, Saskatoon, SK (Canada); Wassmuth, F. [Alberta Research Council, Edmonton, AB (Canada); Stasiuk, E.N. [Calgary Univ., AB (Canada); Hart, D. [Centre for Cold Ocean Resources Engineering, St. John' s, NF (Canada); Legros, J.C. [Brussels Univ., Brussels (Belgium); Smirnov, N.N. [Moscow State Univ., Moscow (Russian Federation)

    2003-07-01

    Several enhanced oil recovery methods are being developed to economically recover waterflooded residual oil. The challenge is comparable to understanding the mechanisms involved when liquid contaminants in soil are filtered and mixed with groundwater and then transported by convective flows. Multiphase flow and trapping of fluids in porous media are greatly affected by wettability and capillary forces. However, fluid flow in porous media is also strongly governed by gravity effects. In this study, a series of high altitude aircraft parabolic flights were conducted in which capillary flow experiments were performed in porous media using different fluids. Three capillary flow experiments were conducted on a shuttle flight where gravity was not a factor. This paper presents a newly developed finite-difference numerical model for two-dimensional homogeneous fluid flow in a porous medium confined by a horizontal bottom, two vertical boundaries and a free surface. The model describes movement of fluid flow in response to applied pressure gradients. It also considers capillary flow caused by surface tension. The simulator can be used to predict the effect of changing properties such as gravitational acceleration, permeability, pore radii, surface tension, liquid viscosity and wettability. The study showed that interfacial phenomena in highly reduced gravity conditions can be applied to problems associated with fluid handling in various types of space vehicles. 12 refs., 12 figs.

  19. Application of decline curve analysis to estimate recovery factors for carbon dioxide enhanced oil recovery

    Science.gov (United States)

    Jahediesfanjani, Hossein

    2017-07-17

    IntroductionIn the decline curve analysis (DCA) method of estimating recoverable hydrocarbon volumes, the analyst uses historical production data from a well, lease, group of wells (or pattern), or reservoir and plots production rates against time or cumu­lative production for the analysis. The DCA of an individual well is founded on the same basis as the fluid-flow principles that are used for pressure-transient analysis of a single well in a reservoir domain and therefore can provide scientifically reasonable and accurate results. However, when used for a group of wells, a lease, or a reservoir, the DCA becomes more of an empirical method. Plots from the DCA reflect the reservoir response to the oil withdrawal (or production) under the prevailing operating and reservoir conditions, and they continue to be good tools for estimating recoverable hydrocarbon volumes and future production rates. For predicting the total recov­erable hydrocarbon volume, the DCA results can help the analyst to evaluate the reservoir performance under any of the three phases of reservoir productive life—primary, secondary (waterflood), or tertiary (enhanced oil recovery) phases—so long as the historical production data are sufficient to establish decline trends at the end of the three phases.

  20. National Institute for Petroleum and Energy Research monthly progress report, May 1993

    Energy Technology Data Exchange (ETDEWEB)

    1993-06-01

    Accomplishments for the month of May are described briefly under tasks for: Energy Production Research; Fuels Research; and Supplemental Government Program. Energy Production Research includes: reservoir assessment and characterization; TORIS research support; development of improved microbial flooding methods; development of improved chemical flooding methods; development of improved alkaline flooding methods; mobility control and sweep improvement in chemical flooding; gas flood performance prediction improvement; mobility control, profile modification, and sweep improvement in gas flooding; three-phase relative permeability research; thermal processes for light oil recovery; thermal processes for heavy oil recovery; and imaging techniques applied to the study of fluids in porous media. Fuels Research covers: development of analytical methodology for analysis of heavy crudes; and thermochemistry and thermophysical properties of organic nitrogen- and diheteratom-containing compounds. Supplemental Government Program covers: microbial-enhanced waterflooding field project; feasibility study of heavy oil recovery in the midcontinent region--Oklahoma, Kansas, and Missouri; surfactant-enhanced alkaline flooding field project; process-engineering property measurements on heavy petroleum components; development and application of petroleum production technologies; upgrade BPO crude oil data base; simulation analysis of steam-foam projects; DOE education initiative project; field application of foams for oil production symposium; technology transfer to independent producers; compilation and analysis of outcrop data from the Muddy and Almond formations; implementation of oil and gas technology transfer initiative; horizontal well production from fractured reservoirs; and chemical EOR workshop.

  1. Application of 3 D seismic technology in Puesto Hernandez field, Neuquen Basin, Argentina

    Energy Technology Data Exchange (ETDEWEB)

    Groba, C.; Mendoza, E.; Musri, D.; Quinteros, J.; Sosa, H.

    1998-07-01

    Puesto Hernandez field, in the Neuquen Basin, Argentina, provides an excellent opportunity to assess the effects of modern 3D Seismic technologies on mature field-development strategies. Perez Company S A is conducting a waterflood project in the Avile Member of the Agrio Formation. A 3D seismic survey conducted in late 1995 resulted in an improved geological model of the Avile Member. This model allowed a better definition of the reservoir limits and structure and explained the presence of water oil contacts where earlier interpretations failed to predict them. A seismic attribute analysis enhanced the areal distribution of h{theta} and helped to detect the location of a gas cap. Using this information an outpost well as driller which revealed a new oil production zone where two horizontal well are now in production. This geological model was input in a numerical simulation model that helped to characterize faults as sealing, partial sealing and channelling, which explained the existence of early breakthroughs and yielded improvements in the design of the injection patterns. (author)

  2. Application of reservoir characterization and advanced technology to improve recovery and economics in a lower quality shallow shelf carbonate reservoir. End of budget period report, August 3, 1994--December 31, 1996

    Energy Technology Data Exchange (ETDEWEB)

    Taylor, A.R.; Hinterlong, G.; Watts, G.; Justice, J.; Brown, K.; Hickman, T.S.

    1997-12-01

    The Oxy West Welch project is designed to demonstrate how the use of advanced technology can improve the economics of miscible CO{sub 2} injection projects in a lower quality shallow shelf carbonate reservoir. The research and design phase primarily involves advanced reservoir characterization and accelerating the production response. The demonstration phase will implement the reservoir management plan based on an optimum miscible CO{sub 2} flood as designed in the initial phase. During Budget Period 1, work was completed on the CO{sub 2} stimulation treatments and the hydraulic fracture design. Analysis of the CO{sub 2} stimulation treatment provided a methodology for predicting results. The hydraulic fracture treatment proved up both the fracture design approach a and the use of passive seismic for mapping the fracture wing orientation. Although the 3-D seismic interpretation is still being integrated into the geologic model and interpretation of borehole seismic is still underway, the simulator has been enhanced to the point of giving good waterflood history matches. The simulator-forecasted results for an optimal designed miscible CO{sub 2} flood in the demonstration area gave sufficient economics to justify continuation of the project into Budget Period 2.

  3. SURFACTANT BASED ENHANCED OIL RECOVERY AND FOAM MOBILITY CONTROL

    Energy Technology Data Exchange (ETDEWEB)

    George J. Hirasaki; Clarence A. Miller; Gary A. Pope; Richard E. Jackson

    2004-07-01

    Surfactant flooding has the potential to significantly increase recovery over that of conventional waterflooding. The availability of a large number of surfactants makes it possible to conduct a systematic study of the relation between surfactant structure and its efficacy for oil recovery. Also, the addition of an alkali such as sodium carbonate makes possible in situ generation of surfactant and significant reduction of surfactant adsorption. In addition to reduction of interfacial tension to ultra-low values, surfactants and alkali can be designed to alter wettability to enhance oil recovery. An alkaline surfactant process is designed to enhance spontaneous imbibition in fractured, oil-wet, carbonate formations. It is able to recover oil from dolomite core samples from which there was no oil recovery when placed in formation brine. Mobility control is essential for surfactant EOR. Foam is evaluted to improve the sweep efficiency of surfactant injected into fractured reservoirs. UTCHEM is a reservoir simulator specially designed for surfactant EOR. A dual-porosity version is demonstrated as a potential scale-up tool for fractured reservoirs.

  4. Reservoir heterogeneity in carboniferous sandstone of the Black Warrior basin. Final report

    Energy Technology Data Exchange (ETDEWEB)

    Kugler, R.L.; Pashin, J.C.; Carroll, R.E.; Irvin, G.D.; Moore, H.E.

    1994-06-01

    Although oil production in the Black Warrior basin of Alabama is declining, additional oil may be produced through improved recovery strategies, such as waterflooding, chemical injection, strategic well placement, and infill drilling. High-quality characterization of reservoirs in the Black Warrior basin is necessary to utilize advanced technology to recover additional oil and to avoid premature abandonment of fields. This report documents controls on the distribution and producibility of oil from heterogeneous Carboniferous reservoirs in the Black Warrior basin of Alabama. The first part of the report summarizes the structural and depositional evolution of the Black Warrior basin and establishes the geochemical characteristics of hydrocarbon source rocks and oil in the basin. This second part characterizes facies heterogeneity and petrologic and petrophysical properties of Carter and Millerella sandstone reservoirs. This is followed by a summary of oil production in the Black Warrior basin and an evaluation of seven improved-recovery projects in Alabama. In the final part, controls on the producibility of oil from sandstone reservoirs are discussed in terms of a scale-dependent heterogeneity classification.

  5. Study of displacement efficiency and flow behavior of foamed gel in non-homogeneous porous media.

    Directory of Open Access Journals (Sweden)

    Yanling Wang

    Full Text Available Field trials have demonstrated that foamed gel is a very cost-effective technology for profile modification and water shut-off. However, the mechanisms of profile modification and flow behavior of foamed gel in non-homogeneous porous media are not yet well understood. In order to investigate these mechanisms and the interactions between foamed gel and oil in porous media, coreflooding and pore-scale visualization waterflooding experiments were performed in the laboratory. The results of the coreflooding experiment in non-homogeneous porous media showed that the displacement efficiency improved by approximately 30% after injecting a 0.3 pore volume of foamed gel, and was proportional to the pore volumes of the injected foamed gel. Additionally, the mid-high permeability zone can be selectively plugged by foamed gel, and then oil located in the low permeability zone will be displaced. The visualization images demonstrated that the amoeba effect and Jamin effect are the main mechanisms for enhancing oil recovery by foamed gel. Compared with conventional gel, a unique benefit of foamed gel is that it can pass through micropores by transforming into arbitrary shapes without rupturing, this phenomenon has been named the amoeba effect. Additionally, the stability of foam in the presence of crude oil also was investigated. Image and statistical analysis showed that these foams boast excellent oil resistance and elasticity, which allows them to work deep within formations.

  6. Static and dynamic effective stress coefficient of chalk

    DEFF Research Database (Denmark)

    Alam, M. Monzurul; Fabricius, Ida Lykke; Christensen, Helle Foged

    2012-01-01

    Deformation of a hydrocarbon reservoir can ideally be used to estimate the effective stress acting on it. The effective stress in the subsurface is the difference between the stress due to the weight of the sediment and a fraction (effective stress coefficient) of the pore pressure. The effective...... elastic deformation caused by pore pressure buildup, for example, during waterflooding. By contrast, during the increase in differential stress, as in the case of pore pressure depletion due to production, n increases with stress while α decreases.......Deformation of a hydrocarbon reservoir can ideally be used to estimate the effective stress acting on it. The effective stress in the subsurface is the difference between the stress due to the weight of the sediment and a fraction (effective stress coefficient) of the pore pressure. The effective...... stress coefficient is thus relevant for studying reservoir deformation and for evaluating 4D seismic for the correct pore pressure prediction. The static effective stress coefficient n is estimated from mechanical tests and is highly relevant for effective stress prediction because it is directly related...

  7. 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.

  8. 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.

  9. Monthly progress report for April 1993

    Energy Technology Data Exchange (ETDEWEB)

    1993-05-01

    Accomplishments for the month of April are described briefly for the following tasks: energy production research; fuels research; and supplemental government program. Energy production research includes: reservoir assessment and characterization; TORIS research support; development of improved microbial flooding methods; development of improved chemical flooding methods; development of improved alkaline flooding methods; mobility control and sweep improvement in chemical flooding; gas flood performance prediction improvement; mobility control, profile modification, and sweep improvement in gas flooding; three-phase relative permeability research; thermal processes for light oil recovery; thermal processes for heavy oil recovery; and imaging techniques applied to the study of fluids in porous media. Fuel research includes: development of analytical methodology for analysis of heavy crudes; and thermochemistry and thermophysical properties of organic nitrogen- and diheteratom-containing compounds. Supplemental government program includes: microbial-enhanced waterflooding field project; feasibility study of heavy oil recovery in the midcontinent region--Oklahoma, Kansas, and Missouri; surfactant-enhanced alkaline flooding field project; process- engineering property measurements on heavy petroleum components; development and application of petroleum production technologies; upgrade BPO crude oil data base; simulation analysis of steam-foam projects; DOE education initiative project; field application of foams for oil production symposium; technology transfer to independent producers; compilations and analysis of outcrop data from the Muddy and Almond Formations; implementation of oil and gas technology transfer initiative; and horizontal well production from fractured reservoirs.

  10. Displacement of polymer solution on residual oil trapped in dead ends

    Institute of Scientific and Technical Information of China (English)

    张立娟; 岳湘安

    2008-01-01

    For waterflooding reservoir,oil trapped in pore’s dead ends is hardly flushed out,and usually becomes one typical type of residual oil.The microscopic displacement characteristics of polymer solution with varied viscoelastic property were studied by numerical and experimental method.According to main pore structure characteristics and rheological property of polymer solution through porous media,displacement models for residual oil trapped in dead ends were proposed,and upper-convected Maxwell rheological model was used as polymer solution’s constitutive equation.The flow and stress field was given and displacement characteristic was quantified by introducing a parameter of micro swept coefficient.The calculated and experimental results show that micro swept coefficient rises with the increase of viscoelasticity;for greater viscoelasticity of polymer solution,vortices in the dead end have greater swept volume and displacing force on oil,and consequently entraining the swept oil in time.In addition,micro swept coefficient in dead end is function of the inclination angle(θ) between pore and dead end.The smaller of θ and 180-θ,the flow field of viscoelastic fluid is developed in dead ends more deeply,resulting in more contact with oil and larger swept coefficient.

  11. DILUTE SURFACTANT METHODS FOR CARBONATE FORMATIONS

    Energy Technology Data Exchange (ETDEWEB)

    Kishore K. Mohanty

    2005-01-01

    There are many carbonate reservoirs in US (and the world) with light oil and fracture pressure below its minimum miscibility pressure (or reservoir may be naturally fractured). Many carbonate reservoirs are naturally fractured. Waterflooding is effective in fractured reservoirs, if the formation is water-wet. Many fractured carbonate reservoirs, however, are mixed-wet and recoveries with conventional methods are low (less than 10%). Thermal and miscible tertiary recovery techniques are not effective in these reservoirs. Surfactant flooding (or huff-n-puff) is the only hope, yet it was developed for sandstone reservoirs in the past. The goal of this research is to evaluate dilute (hence relatively inexpensive) surfactant methods for carbonate formations and identify conditions under which they can be effective. Imbibition in an originally oil-wet 2D capillary is the fastest in the case of Alf-38 and slowest in the case of DTAB (among the surfactants studied). Force of adhesion studies and contact angle measurements show that greater wettability alteration is possible with these anionic surfactants than the cationic surfactant studied. The water imbibition rate does not increase monotonically with an increase in the surfactant concentration. A numerical model has been developed that fits the rate of imbibition. Plans for the next quarter include conducting simulation and imbibition studies.

  12. A New Calculation Method of Treatment Radius about Profile Control and Water Shutoff%一种新的调剖堵水处理半径计算方法

    Institute of Scientific and Technical Information of China (English)

    刘长贵

    2012-01-01

    针对非均质多储层或非均质厚油层油田,在注水开发过程中,注水井吸水剖面和产液井产液剖面的不均匀性,从调剖堵水前后地层流体渗流特性的变化出发,提出了一种新的残余阻力系数确定方法,用来计算调剖堵水时的处理半径以及最佳处理液用量.该方法对矿场调剖堵水处理具有较大的指导意义.%According to the characteristics of the oilfield with heterogeneous multiple or the heterogeneous thick reservoirs, during the process of waterflooding, unhomogeneity exists between the water injection profile of water injection well and the production profile of liquid producing well. Starting with the changes of seepage characteristics of formation fluid between pre-and post profile control and water shutoff, a new determination method of residual resistance factor to calculate treatment radius and optimum account of treatment liquid about profile control and water shutoff was proposed . This method has fairly good directive function to the profile control and water shutoff in field.

  13. Characterization of fractured reservoirs using tracer and flow-rate data

    Science.gov (United States)

    Juliusson, Egill; Horne, Roland N.

    2013-05-01

    This article introduces a robust method for characterizing fractured reservoirs using tracer and flow-rate data. The flow-rate data are used to infer the interwell connectivity matrix, which describes how injected fluids are divided between producers in the reservoir. The tracer data are used to find a function called the tracer kernel for each injector-producer connection. The tracer kernel describes the volume and dispersive properties of the interwell flow path. A combination of parametric and nonparametric regression methods was developed to estimate the tracer kernels in situations where data are collected at variable flow rate or variable-injected concentration conditions. This characterization method was developed to describe enhanced geothermal systems, although it works well in general for characterizing incompressible flow in fractured reservoirs (e.g., geothermal, carbon sequestration, radioactive waste and waterfloods of oil fields) where transverse dispersivity can be considered negligible and production takes place at constant bottomhole pressure conditions. The inferred metrics can be used to sketch informative field maps and predict tracer breakthrough curves at variable flow-rate conditions.

  14. Application of RMT Residual Oil Saturation Logging Technology in Tahe Oilfield%RMT剩余油饱和度测井技术在塔河油田的应用

    Institute of Scientific and Technical Information of China (English)

    胡全发; 李晓宇; 郝身立; 王琳; 阚朝晖

    2015-01-01

    This paper introduces the principle of RMT residual oil saturation logging, focuses on the advantages of RMT residual oil satura-tion logging technology and its application in Tahe oilfield. The application of RMT logging can re-evaluate the various geological parameters of reservoir after waterflooding, and provide accurate porosity, residual oil saturation and other physical property and oily parameters for oil-field development.%文章介绍了RMT剩余油饱和度测井原理,着重分析了RMT剩余油饱和度测井技术优势及在塔河油田的应用,应用RMT测井新技术可对储层水淹后的各种地质参数进行重新评价,为油田后期开发提供准确的孔隙度,剩余油饱和度等物性和含油性参数,具有非常广的应用前景。

  15. Reservoir heterogeneity in Carboniferous sandstone of the Black Warrior basin. Final report

    Energy Technology Data Exchange (ETDEWEB)

    Kugler, R.L.; Pashin, J.C.; Carroll, R.E.; Irvin, G.D.; Moore, H.E.

    1994-04-01

    Although oil production in the Black Warrior basin of Alabama is declining, additional oil may be produced through improved recovery strategies, such as waterflooding, chemical injection, strategic well placement, and infill drilling. High-quality characterization of reservoirs in the Black Warrior basin is necessary to utilize advanced technology to recover additional oil and to avoid premature abandonment of fields. This report documents controls on the distribution and producibility of oil from heterogeneous Carboniferous reservoirs in the Black Warrior basin of Alabama. The first part of the report summarizes the structural and depositional evolution of the Black Warrior basin and establishes the geochemical characteristics of hydrocarbon source rocks and oil in the basin. This second part characterizes facies heterogeneity and petrologic and petrophysical properties of Carter and Millerella sandstone reservoirs. This is followed by a summary of oil production in the Black Warrior basin and an evaluation of seven improved-recovery projects in Alabama. In the final part, controls on the producibility of oil from sandstone reservoirs are discussed in terms of a scale-dependent heterogeneity classification.

  16. ADDRESSING ENVIRONMENTAL CHALLENGES UNDER COMPREHENSIVE UTILIZATION OF GEOTHERMAL SALINE WATER RESOURCES IN THE NORTHERN DAGESTAN

    Directory of Open Access Journals (Sweden)

    A. Sh. Ramazanov

    2016-01-01

    Full Text Available Aim. The aim of the study is to develop technologies for processing geothermal brine produced with the extraction of oil as well as to solve environmental problems in the region.Methods. In order to determine the chemical composition and radioactivity of the geothermal water and solid samples, we used atomic absorption and gamma spectrometry. Evaluation of the effectiveness of the technology was made on the basis of experimental studies.Results. In the geothermal water, eight radionuclides were recognized and quantified with the activity of 87 ± 5 Bq / dm3. For the processing of this water to produce lithium carbonate and other components we propose a technological scheme, which provides a step of water purification from radio-nuclides. As a result of aeration and alkalinization, we can observe deactivation and purification of the geothermal water from mechanical impurities, iron ions, hydrogen carbonates and organic substances. Water treatment allows recovering lithium carbonate, magnesite caustic powder and salt from geothermal water. The mother liquors produced during manufacturing operations meet the requirements for the water suitable for waterflooding of oil reservoirs and can be injected for maintaining the reservoir pressure of the deposits.Conclusion. The implementation of the proposed processing technology of mineralized geothermal water produced with the extraction of oil in the Northern Dagestan will contribute to extend the life of the oil fields and improve the environmental problems. It will also allow import substitution in Russia for lithium carbonate and edible salt.

  17. Laboratory investigation of wettability and hysteresis effects on resistivity index and capillary pressure characteristics

    Energy Technology Data Exchange (ETDEWEB)

    Moss, A.K.; Jing, X.D. [Centre for Petroleum Studies, T.H. Huxley School, Imperial College of Science, Technology and Medicine, Prince Consort Road, London (United Kingdom); Archer, J.S. [Heriot-Watt University, Edinburgh (United Kingdom)

    1999-12-01

    This paper focuses on the experimental aspects of resistivity index and water/oil capillary pressure measurements. A novel experimental procedure using water-wet and oil-wet membranes has been developed. Six potential electrodes and two current electrodes are used to provide resistivity readings across the sample and for seven adjacent intervals along the length of the core plug. The resistivity profile along the core length enables assessment of saturation distribution and end effects. The desaturation tests mimic different displacement processes that could occur during the history of the reservoir, for example, the displacement of water by oil during the initial hydrocarbon migration; the displacement of oil by mud filtrate around the wellbore during drilling and the displacement processes during the formation of transition zones under gravity/capillary forces and during waterflooding. Results from our studies indicate that both the phase-dependent and cycle-dependent hysteresis should be taken into consideration for resistivity index and capillary pressure measurements. The hysteresis effects also depend on the wettability of the rock samples.

  18. Measurement of emulsion flow in porous media: Improvements in heavy oil recovery

    Science.gov (United States)

    Bryan, J.; Wang, J.; Kantzas, A.

    2009-02-01

    Many heavy oil and bitumen reservoirs in the world are too small or thin for thermal enhanced oil recovery methods to be economic. In these fields, novel methods of less energy intensive, non-thermal technologies are required. Previous experience has shown that the injection of low concentrations of aqueous alkali-surfactant solutions into the reservoir can significantly improve the oil recovery, beyond that of waterflooding. This is due to the in-situ formation of emulsions, which plug off the water channels and lead to improved sweep efficiency in the reservoir. The proper control of these floods requires methods for monitoring the formation and effect of these emulsions. In this paper, the results of laboratory core floods are interpreted to demonstrate how the pressure and flow response can be related to the formation of these emulsions. A new technique (low field NMR) is also used to directly measure W/O emulsions in porous media. Finally, a numerical study is performed in order to demonstrate how the in-situ formation of emulsions can be simply represented in simulation software.

  19. Numerical modelling of two phase flow with hysteresis in heterogeneous porous media

    Energy Technology Data Exchange (ETDEWEB)

    Abreu, E. [Instituto Nacional de Matematica Pura e Aplicada (IMPA), Rio de Janeiro, RJ (Brazil); Furtado, F.; Pereira, F. [University of Wyoming, Laramie, WY (United States). Dept. of Mathematicsatics; Souza, G. [Universidade do Estado do Rio de Janeiro (UERJ), RJ (Brazil)

    2008-07-01

    Numerical simulators are necessary for the understanding of multiphase flow in porous media in order to optimize hydrocarbon recovery. In this work, the immiscible flow of two incompressible phases, a problem very common in waterflooding of petroleum reservoirs, is considered and numerical simulation techniques are presented. The system of equations which describe this type of flow form a coupled, highly nonlinear system of time-dependent partial differential equations (PDEs). The equation for the saturation of the invading fluid is a convection-dominated, degenerate parabolic PDE whose solutions typically exhibit sharp fronts (i.e., internal layers with strong gradients) and is very difficult to approximate numerically. It is well known that accurate modeling of convective and diffusive processes is one of the most daunting tasks in the numerical approximation of PDEs. Particularly difficult is the case where convection dominates diffusion. Specifically, we consider the injection problem for a model of two-phase (water/oil) flow in a core sample of porous rock, taking into account hysteresis effects in the relative permeability of the oil phase. (author)

  20. Annex III-evaluation of past and ongoing enhanced oil recovery projects

    Energy Technology Data Exchange (ETDEWEB)

    1995-02-01

    The Infill Drilling Predictive Model (IDPM) was developed by Scientific Software-Intercomp (SSI) for the Bartlesville Project Office (BPO) of the United States Department of Energy (DOE). The model and certain adaptations thereof were used in conjunction with other models to support the Interstate Oil and Gas Compact Commission`s (IOGCC) 1993 state-by-state assessment of the potential domestic reserves achievable through the application of Advanced Secondary Recovery (ASR) and Enhanced Oil Recovery (EOR) techniques. Funding for this study was provided by the DOE/BPO, which additionally provided technical support. The IDPM is a three-dimensional (stratified, five-spot), two-phase (oil and water) model which uses a minimal amount of reservoir and geologic data to generate production and recovery forecasts for ongoing waterflood and infill drilling projects. The model computes water-oil displacement and oil recovery using finite difference solutions within streamtubes. It calculates the streamtube geometries and uses a two-dimensional reservoir simulation to track fluid movement in each streamtube slice. Thus the model represents a hybrid of streamtube and numerical simulators.

  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. Commercial scale demonstration enhanced oil recovery by micellar-polymer flood. Annual report, October 1979-September 1980

    Energy Technology Data Exchange (ETDEWEB)

    Howell, J.C.; Snyder, W.O.

    1981-04-01

    This commercial scale test, known as the M-1 Project, is located in Crawford County, Illinois. It encompasses 407 acres of Robinson sand reservoir and covers portions of several waterflood projects that were approaching economic limit. The project includes 248 acres developed on a 2.4-acre five-spot pattern and 159 acres developed on a 5.0-acre five-spot pattern. Development work commenced in late 1974 and has previously been reported. Micellar solution (slug) injection was initiated on February 10, 1977, and is now completed. After 10% of a pore volume of micellar slug was injected, injection of 11% pore volume of Dow 700 Pusher polymer was conducted at a concentration of 1156 ppM. At the end of this reporting period, 625 ppM polymer was being injected into the 2.5-acre pattern and 800 ppM polymer was being injected into the 5.0-acre pattern. The oil cut of the 2.5 and 5.0-acre patterns increased from 8.6% and 5.2%, respectively in September 1979, to 11.0% and 5.9% in September 1980. The oil cut performance has consistently exceeded that predicted for the project. This Fourth Annual Report is organized under the following three Work Breakdown Structures: fluid injection; production; and performance monitoring.

  3. Chemically enhanced in situ recovery

    Energy Technology Data Exchange (ETDEWEB)

    Sale, T. [CH2M Hill, Denver, CO (United States); Pitts, M.; Wyatt, K. [Surtek, Inc., Golden, CO (United States)] [and others

    1996-08-01

    Chemically enhanced recovery is a promising alternative to current technologies for management of subsurface releases of organic liquids. Through the inclusion of surfactants, solvents, polymers, and/or alkaline agents to a waterflood, the transport of targeted organic compounds can be increased and rates of recovery enhanced. By far, the vast majority of work done in the field of chemically enhanced recovery has been at a laboratory scale. The following text focuses on chemically enhanced recovery from a field application perspective with emphasis given to chlorinated solvents in a low permeability setting. While chlorinated solvents are emphasized, issues discussed are also relevant to organic liquids less dense than water such as petroleum products. Topics reviewed include: (1) Description of technology; (2) General technology considerations; (3) Low permeability media considerations; (4) Cost and reliability considerations; (5) Commercial availability; and (6) Case histories. Through this paper an appreciation is developed of both the potential and limitations of chemically enhanced recovery. Excluded from the scope of this paper is the in situ destruction of organic compounds through processes such as chemical or biological oxidation, chemically enhanced recovery of inorganic compounds, and ex situ soil treatment processes. 11 refs., 2 figs., 1 tab.

  4. 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.

  5. Experimental study of solvent-based emulsion injection to enhance heavy oil recovery in Alaska North Slope area

    Energy Technology Data Exchange (ETDEWEB)

    Qiu, F.; Mamora, D. [Texas A and M Univ., College Station, TX (United States)

    2010-07-01

    This study examined the feasibility of using a chemical enhanced oil recovery method to overcome some of the technical challenges associated with thermal recovery in the Alaska North Slope (ANS). This paper described the second stage research of an experimental study on nano-particle and surfactant-stabilized solvent-based emulsions for the ANS area. Four successful core flood experiments were performed using heavy ANS oil. The runs included water flooding followed by emulsion flooding; and pure emulsion injection core flooding. The injection rate and core flooding temperature remained constant and only 1 PV micro-emulsion was injected after breakthrough under water flooding or emulsion flooding. Oil recovery increased by 26.4 percent from 56.2 percent original oil in place (OOIP) with waterflooding to 82.6 percent OOIP with injection of emulsion following water flooding. Oil recovery was slightly higher with pure emulsion flooding, at 85.8 percent OOIP. The study showed that low permeability generally resulted in a higher shear rate, which is favourable for in-situ emulsification and higher displacement efficiency. 11 refs., 4 tabs., 20 figs.

  6. East Coalinga polymer project: polymer comparisons. [California

    Energy Technology Data Exchange (ETDEWEB)

    Snell, G.

    1976-01-01

    Shell Oil Co. conducted a series of injection and filtration tests in the E. Colainga field, California, to determine the injection characteristics of biopolymer and polyacrylamides. The choice of Xanflood biopolymer was made in order to evaluate the relative merits of polymer flooding and waterflooding in the Temblor Zone II reservoir. Conclusions to the field injection tests were (1) Xanflood biopolymers maintain their mobility properties during these tests; (2) it is possible to remove unhydrated Xanflood biopolymer or unhydrated biopolymer and bacterial debris with DE Filtration without significant loss in biopolymer viscosity; (3) the introduction of an optimum level of shear in the biopolymer mixing process increases the mobility control available for a given concentration of polymer; (4) currently available commercial biopolymers cause well-bore impairment so that effective filtration of the polymer solution is required to maintain injectivity; (5) at test injection rates (33 bpd/ft), polyacrylamide loses most of its mobility control by shear degradation at the injection well perforations; (6) polyacrylamide can be delivered to the sand face without severe loss of viscosity; and (7) polyacrylamide will not impair the formation. (12 refs.)

  7. User`s guide and documentation manual for ``BOAST-VHS for the PC``

    Energy Technology Data Exchange (ETDEWEB)

    Chang, Ming-Ming; Sarathi, P.; Heemstra, R.J.; Cheng, A.M.; Pautz, J.F.

    1992-01-01

    The recent advancement of computer technology makes reservoir simulations feasible in a personal computer (PC) environment. This manual provides a guide for running BOAST-VHS, a black oil reservoir simulator for vertical/horizontal/slant wells, using a PC. In addition to detailed explanations of input data file preparation for simulation runs, special features of BOAST-VHS are described and three sample problems are presented. BOAST-VHS is a cost-effective and easy-to-use reservoir simulation tool for the study of oil production from primary depletion and waterflooding in a black oil reservoir. The well model in BOAST-VHS permits specification of any combination of horizontal, slanted, and vertical wells in the reservoir. BOAST-VHS was designed for an IBM PC/AT, PS-2, or compatible computer with 640 K bytes of memory. BOAST-VHS can be used to model a three-dimensional reservoir of up to 810 grid blocks with any combination of rows, columns, and layers, depending on the input data supplied. This dynamic redimensioning feature facilitates simulation work by avoiding the need to recompiling the simulator for different reservoir models. Therefore the program is only supplied as executable code without any source code.

  8. User's guide and documentation manual for BOAST-VHS for the PC''

    Energy Technology Data Exchange (ETDEWEB)

    Chang, Ming-Ming; Sarathi, P.; Heemstra, R.J.; Cheng, A.M.; Pautz, J.F.

    1992-01-01

    The recent advancement of computer technology makes reservoir simulations feasible in a personal computer (PC) environment. This manual provides a guide for running BOAST-VHS, a black oil reservoir simulator for vertical/horizontal/slant wells, using a PC. In addition to detailed explanations of input data file preparation for simulation runs, special features of BOAST-VHS are described and three sample problems are presented. BOAST-VHS is a cost-effective and easy-to-use reservoir simulation tool for the study of oil production from primary depletion and waterflooding in a black oil reservoir. The well model in BOAST-VHS permits specification of any combination of horizontal, slanted, and vertical wells in the reservoir. BOAST-VHS was designed for an IBM PC/AT, PS-2, or compatible computer with 640 K bytes of memory. BOAST-VHS can be used to model a three-dimensional reservoir of up to 810 grid blocks with any combination of rows, columns, and layers, depending on the input data supplied. This dynamic redimensioning feature facilitates simulation work by avoiding the need to recompiling the simulator for different reservoir models. Therefore the program is only supplied as executable code without any source code.

  9. [National Institute for Petroleum and Energy Research] monthly progress report for June 1992

    Energy Technology Data Exchange (ETDEWEB)

    1992-08-01

    Accomplishments for this period are described briefly under tasks for: Energy Production Research; Fuels Research; and Supplemental Government Program. Energy Production Research includes: reservoir assessment and characterization; TORIS research support; development of improved microbial flooding methods; surfactant flooding methods; development of improved alkaline flooding methods; mobility control and sweep improvement in chemical flooding; gas flood performance prediction improvement; mobility control, profile modification, and sweep improvement in gas flooding; three-phase relative permeability research; thermal processes for light oil recovery; thermal processes for heavy oil recovery; and imaging techniques applied to the study of fluid in porous media. Fuels research includes; development of analytical methodology for analysis of heavy crudes; and thermochemistry and thermophysical properties of organic nitrogen- and diheteroatom-containing compounds. Supplemental Government Program includes: microbial-enhanced waterflooding field project; feasibility study of heavy oil recovery in the midcontinent region--Oklahoma, Kansas, and Missouri; surfactant-enhanced alkaline flooding field project; development of methods for mapping distribution of clays in petroleum reservoirs; summary of geological and production characteristics of class 1, unstructured, deltaic reservoirs; third international reservoir characterization technical conference; process-engineering property measurements on heavy petroleum components; development and application of petroleum production technologies; upgrade BPO crude oil data base; simulation analysis of steam-foam projects; and analysis of the U. S. oil resource base and estimate of future recoverable oil.

  10. (National Institute for Petroleum and Energy Research) monthly progress report for June 1992

    Energy Technology Data Exchange (ETDEWEB)

    1992-08-01

    Accomplishments for this period are described briefly under tasks for: Energy Production Research; Fuels Research; and Supplemental Government Program. Energy Production Research includes: reservoir assessment and characterization; TORIS research support; development of improved microbial flooding methods; surfactant flooding methods; development of improved alkaline flooding methods; mobility control and sweep improvement in chemical flooding; gas flood performance prediction improvement; mobility control, profile modification, and sweep improvement in gas flooding; three-phase relative permeability research; thermal processes for light oil recovery; thermal processes for heavy oil recovery; and imaging techniques applied to the study of fluid in porous media. Fuels research includes; development of analytical methodology for analysis of heavy crudes; and thermochemistry and thermophysical properties of organic nitrogen- and diheteroatom-containing compounds. Supplemental Government Program includes: microbial-enhanced waterflooding field project; feasibility study of heavy oil recovery in the midcontinent region--Oklahoma, Kansas, and Missouri; surfactant-enhanced alkaline flooding field project; development of methods for mapping distribution of clays in petroleum reservoirs; summary of geological and production characteristics of class 1, unstructured, deltaic reservoirs; third international reservoir characterization technical conference; process-engineering property measurements on heavy petroleum components; development and application of petroleum production technologies; upgrade BPO crude oil data base; simulation analysis of steam-foam projects; and analysis of the U. S. oil resource base and estimate of future recoverable oil.

  11. Review of the Lobstick Cardium miscible flood

    Energy Technology Data Exchange (ETDEWEB)

    Gillund, G.N.

    1969-05-26

    The Lobstick Cardium unit lies along the N. edge of the Pembina field. The formation in this portion is characterized by a conglomerate bar overlying the sand. The conglomerate permeabilities reach one darcy or more. Wells in this area exhibit high production rates due to this high capacity. A pattern waterflood covers 12,560 acres and an interior miscible flood, 2,240 acres. The miscible flood has one central injector and 36 offsetting producers. The solvent bank was formed by injecting alternate slugs of LPG, largely propane, and a dry lean gas in a 1.1 mole ratio. A buffer layer of normal sales gas was introduced, followed by alternate gas-water injection to reduce the mobility of the driving gas bank and improve sweep efficiency.With 4.3 million bbl of oil production to the end of 1968, performance predictions have been exceeded. There has been no significant water breakthrough and solvent cuts have been less then predicted. There is a varying degree of communication between the highly permeable conglomerate and the sand in which most of the wells are perforated.

  12. 高凝油油藏SMG可动微凝胶深部调驱技术研究与应用%The Study and Application of Deep Profile Control and Flooding Techniques with SMG Movable Microgel in High Pour-point Oil Reservoirs

    Institute of Scientific and Technical Information of China (English)

    海东明

    2013-01-01

    In order to solve the problems of the flooded seriousness and sweep unevenness in the waterflooding development of high pour-point oil reservoirs, the performance of SMG movable microgel system is evaluated scientifically and some parameters are designed optimally, such as the size of SMG movable microgel, the injection rate, the injection concentration and so on.The field test result shows that the SMG profile control and flooding achieves the desired results.This technology bears great value to improve the development effect in the similar reserviors.%针对高凝油油藏注水开发中存在油藏水淹严重、注水波及不均等突出问题,系统开展了SMG可动微凝胶调驱体系性能评价.并对SMG调驱体系胶团尺寸、注入量、注入浓度等参数进行优化设计.现场试验结果证明,SMG调驱可以有效实现油藏深部调驱.该技术可为同类油藏进一步改善开发效果提供借鉴.

  13. Evolution of wettability in terms of petroleum and petroleum fractions adsorption. An approach by the Wilhelmy method; Evolution de la mouillabilite en fonction de l`adsorption du petrole et de ses fractions. Approche par la methode des angles de contact dynamiques

    Energy Technology Data Exchange (ETDEWEB)

    Mattos Saliba, A.

    1996-12-06

    Reservoir wettability is very important to petroleum recovery by waterflooding and other processes. It is a key parameter controlling multiphase flow and fluids distribution in a porous medium. Nevertheless, the original water-wetness can be modified by the petroleum`s natural surfactants (asphaltenes and resins) adsorption onto the rock surface. This adsorption may reduce petroleum recovery. In this study, the adsorption of model molecules (pyridine and benzo-quinoline), of rude oil and of its heavier fractions (asphaltenes and resins) has been investigated in terms of wettability alteration for initially water-wet surfaces (glass or quartz). In this case, the dynamic Wilhelmy plate technique provides quantitative values of wetting preference to either oil or water. The results show that, at ambient conditions, adsorption depends on concentration, adsorbent/adsorbate interaction time, pH, solvent type, substrate surface, brine concentration and environment liquid phase (water or oil). However, the initial water film on the surface does not strongly influence this phenomena. (author) 222 refs.

  14. ENHANCED OIL RECOVERY WITH DOWNHOLE VIBRATION STIMULATION IN OSAGE COUNTY OKLAHOMA

    Energy Technology Data Exchange (ETDEWEB)

    Robert Westermark; J. Ford Brett

    2003-11-01

    This Final Report covers the entire project from July 13, 2000 to June 30, 2003. The report summarizes the details of the work done on the project entitled ''Enhanced Oil Recovery with Downhole Vibration Stimulation in Osage County Oklahoma'' under DOE Contract Number DE-FG26-00BC15191. The project was divided into nine separate tasks. This report is written in an effort to document the lessons learned during the completion of each task. Therefore each task will be discussed as the work evolved for that task throughout the duration of the project. Most of the tasks are being worked on simultaneously, but certain tasks were dependent on earlier tasks being completed. During the three years of project activities, twelve quarterly technical reports were submitted for the project. Many individual topic and task specific reports were included as appendices in the quarterly reports. Ten of these reports have been included as appendices to this final report. Two technical papers, which were written and accepted by the Society of Petroleum Engineers, have also been included as appendices. The three primary goals of the project were to build a downhole vibration tool (DHVT) to be installed in seven inch casing, conduct a field test of vibration stimulation in a mature waterflooded field and evaluate the effects of the vibration on both the produced fluid characteristics and injection well performance. The field test results are as follows: In Phase I of the field test the DHVT performed exceeding well, generating strong clean signals on command and as designed. During this phase Lawrence Berkeley National Laboratory had installed downhole geophones and hydrophones to monitor the signal generated by the downhole vibrator. The signals recorded were strong and clear. Phase II was planned to be ninety-day reservoir stimulation field test. This portion of the field tests was abruptly ended after one week of operations, when the DHVT became stuck in the well

  15. Southwest Regional Partnership on Carbon Sequestration Phase II

    Energy Technology Data Exchange (ETDEWEB)

    James Rutledge

    2011-02-01

    The Southwest Regional Partnership (SWP) on Carbon Sequestration designed and deployed a medium-scale field pilot test of geologic carbon dioxide (CO2) sequestration in the Aneth oil field. Greater Aneth oil field, Utah's largest oil producer, was discovered in 1956 and has produced over 455 million barrels of oil (72 million m3). Located in the Paradox Basin of southeastern Utah, Greater Aneth is a stratigraphic trap producing from the Pennsylvanian Paradox Formation. Because it represents an archetype oil field of the western U.S., Greater Aneth was selected as one of three geologic pilots to demonstrate combined enhanced oil recovery (EOR) and CO2 sequestration under the auspices of the SWP on Carbon Sequestration, sponsored by the U.S. Department of Energy. The pilot demonstration focuced on the western portion of the Aneth Unit as this area of the field was converted from waterflood production to CO2 EOR starting in late 2007. The Aneth Unit is in the northwestern part of the field and has produced 149 million barrels (24 million m3) of the estimated 450 million barrels (71.5 million m3) of the original oil in place - a 33% recovery rate. The large amount of remaining oil makes the Aneth Unit ideal to demonstrate both CO2 storage capacity and EOR by CO2 flooding. This report summarizes the geologic characterization research, the various field monitoring tests, and the development of a geologic model and numerical simulations conducted for the Aneth demonstration project. The Utah Geological Survey (UGS), with contributions from other Partners, evaluated how the surface and subsurface geology of the Aneth Unit demonstration site will affect sequestration operations and engineering strategies. The UGS-research for the project are summarized in Chapters 1 through 7, and includes (1) mapping the surface geology including stratigraphy, faulting, fractures, and deformation bands, (2) describing the local Jurassic and Cretaceous stratigraphy, (3) mapping the

  16. DEVELOPMENT AND APPLICATION OF 3D THREE-PHASE NON-LINEAR FLOW NUMERICAL SIMULATOR FOR ULTRA-LOW PERMEABILITYOIL RESERVOIR%特低渗透油藏三维三相非线性渗流数值模拟器研制与应用

    Institute of Scientific and Technical Information of China (English)

    于荣泽; 卞亚南; 王凯军; 杨正明; 姜瑞忠

    2012-01-01

    A non-linear flow mathematical model is established according to the fluid flow characteristics in ultra-low permeability oil reservoir. The non-linear flow numerical stimulator is developed based on black-oil model. Taking a five-spot well pattern unit as example, and the comparative analysis between different types of non-linear flow curves and the results of Darcy flow simulation is conducted. The simulation results show that comparing with Darcy flow and considering non-linear flow, for non-linear flow, the low oil production, rapid production decline, low-efficiency water-displacement and lagged injection response are obvious; of producing wells and water propulsion speeds along vertical direction of artificial fracture are slow; and moreover, water absorbing capacity of the injectors is poorer, the advance speed along vertical fractures becomes slower; under the condition of the same injection-production pressure difference, waterflood results are rather imperfect; the shut-up pressure area near the injectors is pretty large, more driving energy is exhausted for the fluids flowing in the formation, so the waterflood efficiency is reduced; in the course of oil-permeability oil reservoir development, except larger formation pressure gradient near the bole hole, the gradient in most part of the formation is rather lower, non-linear flow plays dominant role. Based on the laws .of non-linear flow, the developed numerical simulation software can more accurately predict the dynamic characteristics of ultra-low permeability oil reservoir development.%根据特低渗透油藏流体渗流特征,建立了非线性渗流油藏数学模型.在黑油模型基础上,开发了特低渗透油藏非线性渗流数值模拟器.以五点井网单元为例进行算例分析,将不同类型的非线性渗流曲线与达西渗流模拟结果进行对比分析.模拟结果表明:与达西渗流相比,考虑非线性渗流规律的油井产油量低,产量递减快,注水见效缓

  17. An Integrated Study of the Grayberg/San andres Reservoir, Foster and South Cowden Fields, Ector County, Texas

    Energy Technology Data Exchange (ETDEWEB)

    None

    1997-02-27

    The characteristics of seismic- derived porosity maps have been further qualified by geologic and production relationships not previously explained nor their significance recognized. Patterns of seismic- derived porosity in the upper Grayburg compare accurately to geologic well data and to historic oil production in section 36. Areas of economic reservoir seem to be separated hydrodynamically, based on the porosity distribution and related differences of gas- to- oil ratio values. Porosity values east of the current limit of the seismic inversion model (where the current seismic data quality is poor) have been estimated for the Grayburg zones, to be used in the next production model run. Production data for that area are being requested from offset operators. When those data become available, they will be included in a revised engineering model will be made to match the production history and to simulate the effect of waterflood efforts. The mapping of porosity of the upper Grayburg zones from the seismic data was completed during the third quarter of 1997, with further qualification of the results done during the fourth quarter. The cross- plots of well log- determined porosity versus seismic velocity have shown a strong linear relationship useful for calibrating the conversion of velocity to porosity. Maps of porosity for the A, B, and C zones are being tested against geological and engineering data. Complexity of reservoir demonstrated in those maps has exposed the need to include significantly more geologic and production data in the area around section 36 in order to create a proper model for the Grayburg reservoir in section 36.

  18. A model technology transfer program for independent operators: Kansas Technology Transfer Model (KTTM)

    Energy Technology Data Exchange (ETDEWEB)

    Schoeling, L.G.

    1993-09-01

    This report describes the development and testing of the Kansas Technology Transfer Model (KTTM) which is to be utilized as a regional model for the development of other technology transfer programs for independent operators throughout oil-producing regions in the US. It describes the linkage of the regional model with a proposed national technology transfer plan, an evaluation technique for improving and assessing the model, and the methodology which makes it adaptable on a regional basis. The report also describes management concepts helpful in managing a technology transfer program. The original Tertiary Oil Recovery Project (TORP) activities, upon which the KTTM is based, were developed and tested for Kansas and have proved to be effective in assisting independent operators in utilizing technology. Through joint activities of TORP and the Kansas Geological Survey (KGS), the KTTM was developed and documented for application in other oil-producing regions. During the course of developing this model, twelve documents describing the implementation of the KTTM were developed as deliverables to DOE. These include: (1) a problem identification (PI) manual describing the format and results of six PI workshops conducted in different areas of Kansas, (2) three technology workshop participant manuals on advanced waterflooding, reservoir description, and personal computer applications, (3) three technology workshop instructor manuals which provides instructor material for all three workshops, (4) three technologies were documented as demonstration projects which included reservoir management, permeability modification, and utilization of a liquid-level acoustic measuring device, (5) a bibliography of all literature utilized in the documents, and (6) a document which describes the KTTM.

  19. Increased oil production and reserves utilizing secondary/tertiary recovery techniques on small reservoirs in the Paradox Basin, Utah. Annual report, February 9, 1997--February 8, 1998

    Energy Technology Data Exchange (ETDEWEB)

    Chidsey, T.C. Jr. [ed.] [comp.

    1998-03-01

    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 (111,300-318,000 m{sup 3}) of oil per field at a 15 to 20 percent recovery rate. At least 200 million barrels (31,800,000 m{sup 3}) of oil are 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 (CO{sub 2})-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. Geological characterization on a local scale focused on reservoir heterogeneity, quality, and lateral continuity as well as possible compartmentalization within each of the five project fields. This study utilized representative core and modern geophysical logs to characterize and grade each of the five fields for suitability of enhanced recovery projects. The typical vertical sequence or cycle of lithofacies from each field, as determined from conventional core, was tied to its corresponding log response. The diagenetic fabrics and porosity types found in the various hydrocarbon-bearing rocks of each field can be an indicator of reservoir flow capacity, storage capacity, and potential for water- and/or CO{sub 2}-flooding. Diagenetic histories of the various Desert Creek reservoirs were determined from 50 representative samples selected from the conventional cores of each field. Thin sections were also made of each sample for petrographic description.

  20. Thermoelastic stresses induced by non-isothermal fluid injection into fractured rock

    Science.gov (United States)

    Mossop, A.; Matthai, S. K.

    2003-04-01

    The injection of cold water into hot fractured rock occurs in a number of industrial scenarios, most commonly in the recharge of geothermal reservoirs and during waterflood operations in hydrocarbon reservoirs. The cold water cools the rock local to the fracture flow pathways, the cooled rock contracts, causing localised stress perturbations. Essentially analogous physical processes are involved in the injection of hot fluids into cooler rock such as occur in steam flood operations in viscous oil recovery. In this study we investigate such thermoelastic stresses induced by non-isothermal injection into a three dimensional fractured rock mass. The starting point of our analysis is an idealized model of injection into a single, uniform, horizontal fracture. For this case we have previously found semi-analytic solutions and analytic estimates of the stress perturbation and these are in turn used for cross-verification of an isoparametric, quadratic, finite element model of the system. In the numerical model the fractures are treated as discrete conductive channels within the matrix and an additional feature is that the matrix itself can be assigned a non-zero permeability. As the numerical simulator follows a fundamentally different methodology for solving these thermoelastic problems, the results help to validate some of the scaling relationships and non-intuitive behaviour deduced from the analytic estimates (e.g. for a broad range of flow rates, fracture normal stress perturbations decrease with increasing injection rates). The finite element model is then used to explore progressively more complex fracture geometries and networks. Finally we investigate the validity of a continuum limit as fracture densities increase to the point that fracture separation length scales are comparable with thermal diffusion length scales.

  1. Development of an Advanced Simulator to Model Mobility Control and Geomechanics during CO{sub 2} Floods

    Energy Technology Data Exchange (ETDEWEB)

    Delshad, Mojdeh; Wheeler, Mary; Sepehrnoori, Kamy; Pope, Gary

    2013-12-31

    The simulator is an isothermal, three-dimensional, four-phase, compositional, equation-of– state (EOS) simulator. We have named the simulator UTDOE-CO2 capable of simulating various recovery processes (i.e., primary, secondary waterflooding, and miscible and immiscible gas flooding). We include both the Peng-Robinson EOS and the Redlich-Kwong EOS models. A Gibbs stability test is also included in the model to perform a phase identification test to consistently label each phase for subsequent property calculations such as relative permeability, viscosity, density, interfacial tension, and capillary pressure. Our time step strategy is based on an IMPEC-type method (implicit pressure and explicit concentration). The gridblock pressure is solved first using the explicit dating of saturation-dependent terms. Subsequently, the material balance equations are solved explicitly for the total concentration of each component. The physical dispersion term is also included in the governing equations. The simulator includes (1) several foam model(s) for gas mobility control, (2) compositional relative permeability models with the hysteresis option, (3) corner point grid and several efficient solvers, (4) geomechanics module to compute stress field as the result of CO{sub 2} injection/production, (5) the format of commercial visualization software, S3graf from Science-soft Ltd., was implemented for user friendly visualization of the simulation results. All tasks are completed and the simulator was fully tested and delivered to the DOE office including a user’s guide and several input files and the executable for Windows Pcs. We have published several SPE papers, presented several posters, and one MS thesis is completed (V. Pudugramam, 2013) resulting from this DOE funded project.

  2. Using surface deformation to infer reservoir dilation induced by injection

    Science.gov (United States)

    Nanayakkara, Asanga Sanjeewee

    Reservoir dilations occur due to variety of subsurface injection operations including waste disposal, waterflooding, steam injection, CO 2 sequestration and aquifer storage recovery. These reservoir dilations propagate to the surrounding formations and extend up to the ground surface resulting in surface deformations. The surface deformations can be measured by using various technologies such as tiltmeters and interferometric synthetic aperture radar (InSAR) and they can be inverted to infer reservoir dilations by solving an ill-posed inverse problem. This concept forms the basis of the research work presented in this thesis. Initially, the characteristics of the surface and subsurface deformations (induced by the injection operations) and correlations between them were investigated in detail by applying both analytical (based on center of dilatation approach) and numerical methods (fully coupled finite element method). Then, a simple set of guidelines to obtain quick estimates for the surface heave characteristics were proposed. The guidelines are in the form of simple analytical equations or charts and thereby they could be very useful in obtaining preliminary assessment for the surface deformation characteristics induced by the subsurface injection operations. Next, the mathematical aspects of the inverse problem were discussed in detail and the factors affecting the accuracy of the inverse solution were investigated through an extensive parametric study including both two-dimensional and three-dimensional problems. Then, a method was developed to infer reservoir dilation (with high accuracy and high spatial resolution) using a limited number of surface deformation measurements. The proposed method was applied to infer the reservoir dilation induced by a waste disposal operation conducted at Frog Lake, Alberta and the practical issues pertaining to the proposed method were discussed. Finally, guidelines for tiltmeter array design were proposed and

  3. Effects of initial saturation on properties modification and displacement of tetrachloroethene with aqueous isobutanol.

    Science.gov (United States)

    Boyd, Glen R; Ocampo-Gómez, Ana M; Li, Minghua; Husserl, Johana

    2006-11-20

    Packed column experiments were conducted to study effects of initial saturation of tetrachloroethene (PCE) in the range of 1.0-14% pore volume (PV) on mobilization and downward migration of the non-aqueous phase liquid (NAPL) product upon contact with aqueous isobutanol ( approximately 10 vol.%). This study focused on the consequences of swelling beyond residual saturation. Columns were packed with mixtures of neat PCE, water and glass beads and waterflooded to establish a desired homogeneous residual saturation, and then flooded with aqueous isobutanol under controlled hydraulic conditions. Results showed a critical saturation of approximately 8% PV for these packed column experimental conditions. At low initial PCE saturations (8% PV), results showed NAPL-product mobilization and downward migration which was attributed to interfacial tension (IFT) reduction, swelling of the NAPL-product, and reduced density modification. Packed column results were compared with good agreement to theoretical predictions of NAPL-product mobilization using the total trapping number, N(T). In addition to the packed column study, preliminary batch experiments were conducted to study the effects of PCE volumetric fraction in the range of 0.5-20% on density, viscosity, and IFT modification as a function of time following contact with aqueous isobutanol ( approximately 10 vol.%). Modified NAPL-product fluid properties approached equilibrium within approximately 2 h of contact for density and viscosity. IFT reduction occurred immediately as expected. Measured fluid properties were compared with good agreement to theoretical equilibrium predictions based on UNIQUAC. Overall, this study demonstrates the importance of initial DNAPL saturation, and the associated risk of downward NAPL-product migration, in applying alcohol flooding for remediation of DNAPL contaminated ground water sites.

  4. Microbial field pilot study

    Energy Technology Data Exchange (ETDEWEB)

    Knapp, R.M.; McInerney, M.J.; Menzie, D.E.; Chisholm, J.L.

    1992-03-01

    The objective of this project is to perform a microbial enhanced oil recovery field pilot in the Southeast Vassar Vertz Sand Unit (SEVVSU) in Payne County, Oklahoma. Indigenous, anaerobic, nitrate reducing bacteria will be stimulated to selectively plug flow paths which have been referentially swept by a prior waterflood. This will force future flood water to invade bypassed regions of the reservoir and increase sweep efficiency. This report covers progress made during the second year, January 1, 1990 to December 31, 1990, of the Microbial Field Pilot Study project. Information on reservoir ecology, surface facilities design, operation of the unit, core experiments, modeling of microbial processes, and reservoir characterization and simulation are presented in the report. To better understand the ecology of the target reservoir, additional analyses of the fluids which support bacteriological growth and the microbiology of the reservoir were performed. The results of the produced and injected water analysis show increasing sulfide concentrations with respect to time. In March of 1990 Mesa Limited Partnership sold their interest in the SEVVSU to Sullivan and Company. In April, Sullivan and Company assumed operation of the field. The facilities for the field operation of the pilot were refined and implementation was begun. Core flood experiments conducted during the last year were used to help define possible mechanisms involved in microbial enhanced oil recovery. The experiments were performed at SEVVSU temperature using fluids and inoculum from the unit. The model described in last year's report was further validated using results from a core flood experiment. The model was able to simulate the results of one of the core flood experiments with good quality.

  5. Microbial field pilot study

    Energy Technology Data Exchange (ETDEWEB)

    Knapp, R.M.; McInerney, M.J.; Menzie, D.E.; Chisholm, J.L.

    1992-03-01

    The objective of this project is to perform a microbial enhanced oil recovery field pilot in the Southeast Vassar Vertz Sand Unit (SEVVSU) in Payne County, Oklahoma. Indigenous, anaerobic, nitrate reducing bacteria will be stimulated to selectively plug flow paths which have been referentially swept by a prior waterflood. This will force future flood water to invade bypassed regions of the reservoir and increase sweep efficiency. This report covers progress made during the second year, January 1, 1990 to December 31, 1990, of the Microbial Field Pilot Study project. Information on reservoir ecology, surface facilities design, operation of the unit, core experiments, modeling of microbial processes, and reservoir characterization and simulation are presented in the report. To better understand the ecology of the target reservoir, additional analyses of the fluids which support bacteriological growth and the microbiology of the reservoir were performed. The results of the produced and injected water analysis show increasing sulfide concentrations with respect to time. In March of 1990 Mesa Limited Partnership sold their interest in the SEVVSU to Sullivan and Company. In April, Sullivan and Company assumed operation of the field. The facilities for the field operation of the pilot were refined and implementation was begun. Core flood experiments conducted during the last year were used to help define possible mechanisms involved in microbial enhanced oil recovery. The experiments were performed at SEVVSU temperature using fluids and inoculum from the unit. The model described in last year`s report was further validated using results from a core flood experiment. The model was able to simulate the results of one of the core flood experiments with good quality.

  6. COUPLING THE ALKALINE-SURFACTANT-POLYMER TECHNOLOGY AND THE GELATION TECHNOLOGY TO MAXIMIZE OIL PRODUCTION

    Energy Technology Data Exchange (ETDEWEB)

    Malcolm Pitts; Jie Qui; Dan Wilson; Phil Dowling

    2004-05-01

    Gelation technologies have been developed to provide more efficient vertical sweep efficiencies for flooding naturally fractured oil reservoirs or more efficient areal sweep efficiency those with high permeability contrast ''thief zones''. The field proven alkaline-surfactant-polymer technology economically recovers 15% to 25% OOIP more oil than waterflooding in the swept pore space of an oil reservoir. However, alkaline-surfactant-polymer technology is not amenable to the naturally fractured reservoirs or those with thief zones because much of the injected solution bypasses the target pore space containing oil. The objective of this work is to investigate whether combining these two technologies could broaden the applicability of alkaline-surfactant-polymer flooding into these reservoirs. Fluid-fluid interaction with different gel chemical compositions and alkaline-surfactant-polymer solution with pH values ranging from 9.2 to 12.9 have been tested. Aluminum-polyacrylamide gels are not stable to alkaline-surfactant-polymer solutions at any pH. Chromium--polyacrylamide gels with polymer to chromium ion ratios of 25 or greater were stable to alkaline-surfactant-polymer solutions if solution pH was 10.6 or less. When the polymer to chromium ion was 15 or less, chromium-polyacrylamide gels were stable to alkaline-surfactant-polymer solutions with pH values up to 12.9. Chromium-xanthan gum gels were stable to alkaline-surfactant-polymer solutions with pH values of 12.9 at the polymer to chromium ion ratios tested. Silicate-polyacrylamide, resorcinol-formaldehyde, and sulfomethylated resorcinol-formaldehyde gels were also stable to alkaline-surfactant-polymer solutions with pH values ranging from 9.2 to 12.9. Iron-polyacrylamide gels were immediately destroyed when contacted with any of the alkaline-surfactant-polymer solutions with pH values of 9.2 to 12.9.

  7. Surfactant-enhanced alkaline flooding field project. Annual report

    Energy Technology Data Exchange (ETDEWEB)

    French, T.R.; Josephson, C.B.

    1993-12-01

    The Tucker sand from Hepler field, Crawford County, Kansas, was characterized using routine and advanced analytical methods. The characterization is part of a chemical flooding pilot test to be conducted in the field, which is classified as a DOE Class I (fluvial-dominated delta) reservoir. Routine and advanced methods of characterization were compared. Traditional wireline logs indicate that the reservoir is vertically compartmentalized on the foot scale. Routine core analysis, X-ray computed tomography (CT), minipermeameter measurement, and petrographic analysis indicate that compartmentalization and lamination extend to the microscale. An idealized model of how the reservoir is probably structured (complex layering with small compartments) is presented. There was good agreement among the several methods used for characterization, and advanced characterization methods adequately explained the coreflood and tracer tests conducted with short core plugs. Tracer and chemical flooding tests were conducted in short core plugs while monitoring with CT to establish flow patterns and to monitor oil saturations in different zones of the core plugs. Channeling of injected fluids occurred in laboratory experiments because, on core plug scale, permeability streaks extended the full length of the core plugs. A graphic example of how channeling in field core plugs can affect oil recovery during chemical injection is presented. The small scale of compartmentalization indicated by plugs of the Tucker sand may actually help improve sweep between wells. The success of field-scale waterflooding and the fluid flow patterns observed in highly heterogeneous outcrop samples are reasons to expect that reservoir flow patterns are different from those observed with short core plugs, and better sweep efficiency may be obtained in the field than has been observed in laboratory floods conducted with short core plugs.

  8. Use of microbes for paraffin cleanup at Naval Petroleum Reserve No. 3

    Energy Technology Data Exchange (ETDEWEB)

    Giangiacomo, L.; Khatib, A.

    1995-12-31

    Naval Petroleum Reserve No. 3 (NPR-3), also known as Teapot Dome, is a government-owned oil field in Natrona County, Wyoming. It is an asymmetrical anticline located on the western edge of the Powder River Basin, just south of the Salt Creek Anticline. Production started in 1922, and today the field is a marginally economic stripper field with average production of less than 3 BOPD (0.5 m{sup 3}/D) per well. Total field production is about 1,800 BOPD (286 m{sup 3}/D). The Second Wall Creek Formation was waterflooded from 1979 until June 1992 with poor results due to the extensive natural fracture system in this sandstone unit. Since water injection ceased, reservoir pressure has declined to very low levels. Liquids extraction and reinjection of the gas produced from high-GOR wells along the gas-oil contact continues, but the average gas cap pressure has fallen to approximately 150 psi (1.03 MPa) from an original pressure of 1,120 psi (7.72 MPa). Since the oil is highly paraffinic, wax deposition in the hydraulic fractures and the perforations has become a serious production problem. Microbial treatment was considered as a possible low-cost solution. Four wells were selected in the Second Wall Creek Reservoir with severe paraffin problems and production rates high enough to economically justify the treatment. Problems were experienced with the production of thick oil after approximately three months. This was interpreted to be a result of previously immobile paraffin being cleaned up. A slight decrease in the decline rate was seen in the wells, although some external factors cloud the interpretation. Microbial treatments were discontinued because of marginal economics. Three of the four wells produced additional oil and had a positive incremental cash flow. Oil viscosity tests did indicate that some positive microbial thinning was occurring, and changes to the treatment procedure may potentially yield more economic results in the future.

  9. Development and application of a new biotechnology of the molasses in-situ method; detailed evaluation for selected wells in the Romashkino carbonate reservoir

    Energy Technology Data Exchange (ETDEWEB)

    Wagner, M.; Lungerhausen, D. [Erdoel-Erdgas Gommern GmbH (Germany); Murtada, H.; Rosenthal, G. [VEBA OEL AG, Gelsenkirchen (Germany)

    1995-12-31

    On the basis of different laboratory studies, by which special strains of the type Clostridium tyrobutyricum were found, the application of molasses in-situ method for the enhanced recovery of oil in Romashkino oil field was executed. In an anaerobic, 6%-molasses medium the strains produce about 11,400 mg/l of organic acids (especially butyric acid), 3,200 mg/l ethanol, butanol, etc., and more than 350 ml/g of molasses biogas with a content of 80% C0{sub 2} and 20% H{sub 2}. The metabolics of Clostridium tyrobutyricum depress the growth of SRB, whereas methanogenic bacteria grow in an undiluted fermented molasses medium very well. In this way the dominant final fermentation process is methanogenesis. By laboratory studies with original cores under the conditions of the carbonate reservoir in Bashkir, the recovery of oil increased from 15% after waterflooding to 29% OOIP during the treatment with molasses and bacteria. We developed a new biotechnological method for a self-regulated, automatic continuous culture and constructed a special pilot plant with a high technical standard. The plant produced during the pilot on Romashkino field (September 1992 to August 1994) about 1,000 m{sup 3} of clean inoculum with a content of 3-4 billion cells per ml. This inoculum was injected in slugs together with 15,000 m{sup 3} of molasses medium, first in one, later in five wells. We will demonstrate for two example wells the complex microbiological and chemical changes in the oil, gas, and water phases, and their influences on the recover of oil.

  10. Multiple flow processes accompanying a dam-break flood in a small upland watershed, Centralia, Washington

    Science.gov (United States)

    Costa, John E.

    1994-01-01

    On October 5, 1991, following 35 consecutive days of dry weather, a 105-meter long, 37-meter wide, 5.2-meter deep concrete-lined watersupply reservoir on a hillside in the eastern edge of Centralia, Washington, suddenly failed, sending 13,250 cubic meters of water rushing down a small, steep tributary channel into the city. Two houses were destroyed, several others damaged, mud and debris were deposited in streets, on lawns, and in basements over four city blocks, and 400 people were evacuated. The cause of failure is believed to have been a sliding failure along a weak seam or joint in the siltstone bedrock beneath the reservoir, possibly triggered by increased seepage into the rock foundation through continued deterioration of concrete panel seams, and a slight rise (0.6 meters) in the pool elevation. A second adjacent reservoir containing 18,900 cubic meters of water also drained, but far more slowly, when a 41-cm diameter connecting pipe was broken by the landslide. The maximum discharge resulting from the dam-failure was about 71 cubic meters per second. A reconstructed hydrograph based on the known reservoir volume and calculated peak discharge indicates the flood duration was about 6.2 minutes. Sedimentologic evidence, high-water mark distribution, and landforms preserved in the valley floor indicate that the dam failure flood consisted of two flow phases: an initial debris flow that deposited coarse bouldery sediment along the slope-area reach as it lost volume, followed soon after by a water-flood that achieved a stage about one-half meter higher than the debris flow. The Centralia dam failure is one of three constructed dams destroyed by rapid foundation failure that defines the upper limits of an envelope curve of peak flood discharge as a function of potential energy for failed constructed dams worldwide.

  11. User`s guide and documentation manual for ``PC-Gel`` simulator

    Energy Technology Data Exchange (ETDEWEB)

    Chang, Ming-Ming; Gao, Hong W.

    1993-10-01

    PC-GEL is a three-dimensional, three-phase (oil, water, and gas) permeability modification simulator developed by incorporating an in-situ gelation model into a black oil simulator (BOAST) for personal computer application. The features included in the simulator are: transport of each chemical species of the polymer/crosslinker system in porous media, gelation reaction kinetics of the polymer with crosslinking agents, rheology of the polymer and gel, inaccessible pore volume to macromolecules, adsorption of chemical species on rock surfaces, retention of gel on the rock matrix, and permeability reduction caused by the adsorption of polymer and gel. The in-situ gelation model and simulator were validated against data reported in the literature. The simulator PC-GEL is useful for simulating and optimizing any combination of primary production, waterflooding, polymer flooding, and permeability modification treatments. A general background of permeability modification using crosslinked polymer gels is given in Section I and the governing equations, mechanisms, and numerical solutions of PC-GEL are given in Section II. Steps for preparing an input data file with reservoir and gel-chemical transport data, and recurrent data are described in Sections III and IV, respectively. Example data inputs are enclosed after explanations of each input line to help the user prepare data files. Major items of the output files are reviewed in Section V. Finally, three sample problems for running PC-GEL are described in Section VI, and input files and part of the output files of these problems are listed in the appendices. For the user`s reference a copy of the source code of PC-GEL computer program is attached in Appendix A.

  12. Improved methods for water shutoff. Semi-annual report, May 1, 1996--September 30, 1996

    Energy Technology Data Exchange (ETDEWEB)

    Seright, R.S.

    1997-08-01

    In the United States, more than 20 billion barrels of water are produced each year during oilfield operations. Today, the cost of water disposal is typically between $0.25 and $0.50 per bbl for pipeline transport and $1.50 per bbl for trucked water. Therefore, there is a tremendous economic incentive to reduce water production if that can be accomplished without significantly sacrificing hydrocarbon production. For each 1% reduction in water production, the cost-savings to the oil industry could be between $50,000,000 and $100,000,000 per year. Reduced water production would result directly in improved oil recovery (IOR) efficiency in addition to reduced oil-production costs. A substantial positive environmental impact could also be realized if significant reductions are achieved in the amount of water produced during oilfield operations. In an earlier project, we identified fractures (either naturally or artificially induced) as a major factor that causes excess water production and reduced oil recovery efficiency, especially during waterfloods and IOR projects. We also found fractures to be a channeling and water-production problem that has a high potential for successful treatment by gels and certain other chemical blocking agents. By analogy, these blocking materials also have a high potential for treating narrow channels behind pipe and small casing leaks. We also determined that the ability of blocking agents to reduce permeability to water much more than that to oil is critical to the success of these blocking treatments in production wells if zones are not isolated during placement of the blocking agents.

  13. Challenges in Implementing a Multi-Partnership Geothermal Power Plant

    Energy Technology Data Exchange (ETDEWEB)

    Gosnold, Will; Mann, Michael [Universit of North Dakota; Salehfar, Hossein

    2017-03-02

    The UND-CLR binary geothermal power plant project is a piggyback operation on a secondary-recovery water-flood project in the Cedar Hills oil field in the Williston Basin. Two open-hole horizontal wells at 2,300 m and 2,400 m depths with lateral lengths of 1,290 m and 860 m produce water at a combined flow of 51 l s -1 from the Lodgepole formation (Miss.) for injection into the Red River formation (Ordovician). The hydrostatic head for the Lodgepole is at ground surface and the pumps, which are set at 650 m depth, have run continuously since 2009. Water temperature at the wellhead is 103 °C and CLR passes the water through two large air-cooled heat exchangers prior to injection. In all aspects, the CLR water flood project is ideal for demonstration of electrical power production from a low-temperature geothermal resource. However, implementation of the project from concept to power production was analogous to breaking trail in deep snow in an old growth forest. There were many hidden bumps, detours, and in some instances immoveable barriers. Problems with investors, cost share, contracts with CLR, resistance from local industry, cost of installation, delays by the ORC supplier, and the North Dakota climate all caused delays and setbacks. Determination and problem solving by the UND team eventually overcame most setbacks, and in April 2016, the site began generating power. Figure 1: Schematic of the water supply well at the UND CLR binary geothermal power plant REFERENCES Williams, Snyder, and Gosnold, 2016, Low Temperature Projects Evaluation and Lesson Learned, GRC Transactions, Vol. 40, 203-210 Gosnold, LeFever, Klenner, Mann, Salehfar, and Johnson, 2010, Geothermal Power from Coproduced Fluids in the Williston Basin, GRC Transactions, Vol. 34, 557-560

  14. Characterization of facies and permeability patterns in carbonate reservoirs based on outcrop analogs. Final report

    Energy Technology Data Exchange (ETDEWEB)

    Kerans, C.; Lucia, F.J.; Senger, R.K.; Fogg, G.E.; Nance, H.S.; Hovorka, S.D.

    1993-07-01

    The primary objective of this research is to develop methods for better describing the three-dimensional geometry of carbonate reservoir flow units as related to conventional or enhanced recovery of oil. San Andres and Grayburg reservoirs were selected for study because of the 13 Bbbl of remaining mobile oil and 17 Bbbl of residual oil in these reservoirs. The key data base is provided by detailed characterization of geologic facies and rock permeability in reservior-scale outcrops of the Permian San Andres Formation in the Guadalupe Mountains of New Mexico. Emphasis is placed on developing an outcrop analog for San Andres strata that can be used as (1) a guide to interpreting the regional and local geologic framework of the subsurface reservoirs (2) a data source illustrating the scales and patterns of variability of rock-fabric facies and petrophysical properties, particularly in lateral dimension, and on scales that cannot be studied during subsurface reservoir characterization. The research approach taken to achieve these objectives utilizes the integration of geologic description, geostatistical techniques, and reservoir flow simulation experiments. Results from this research show that the spatial distribution of facies relative to the waterflood direction can significantly affect how the reservoir produces. Bypassing of unswept oil occurs due to cross flow of injected water from high permeability zones into lower permeability zones were high permeability zones terminate. An area of unswept oil develops because of the slower advance of the water-injection front in the lower permeability zones. When the injection pattern is reversed, the cross-flow effect changes due to the different arrangements of rock-fabric flow units relative to the flow of injected water, and the sweep efficiency is significantly different. Flow across low-permeability mudstones occurs showing that these layers do not necessarily represent flow barriers.

  15. Biologically formed calcium carbonate : a durable plugging agent for enhanced oil recovery

    Energy Technology Data Exchange (ETDEWEB)

    Nemati, M.; Voordouw, G. [Calgary Univ., AB (Canada)

    2002-06-01

    Waterflooding is a common enhanced oil recovery method in which water is injected into an oil reservoir. The flow is diverted into high permeability zones from which oil has already been recovered during primary production. The increased permeability variation decreases volumetric sweep efficiency of injected water. Cross flow complicates this problem by allowing flow between contrasting layers. This results in a ratio of produced water to oil that is much too high. The use of calcium carbonate (CaCO{sub 3}) and silica may be an effective method for selective plugging of reservoirs. The controlled biological formation of CaCO{sub 3} depends on the decomposition of urea to carbonate and ammonium ions by the catalytic action of urease enzyme. This study shows that biological formation of CaCO{sub 3} could be induced successfully using a bacterium with urease producing activity or urease enzyme. It is shown that the yield of enzymatically produced CaCO{sub 3} is substantially higher than when bacterially produced because the tolerable level of urea for bacteria is lower than the concentration of urea that participates in the enzymatic reaction. Plugging studies in unconsolidated porous media have shown that in situ formation of CaCO{sub 3} may decrease the permeability of porous media. The extent of plugging depends on the enzyme and reactant concentration. The extent of enzymatically produced CaCO{sub 3} increases with higher enzyme concentrations as well as with higher temperature. In situ formation of CaCO{sub 3} could result in a major decrease in permeability. 4 refs., 1 tab., 1 fig.

  16. 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.

  17. Surfactant Based Enhanced Oil Recovery and Foam Mobility Control

    Energy Technology Data Exchange (ETDEWEB)

    George J. Hirasaki; Clarence A. Miller; Gary A. Pope

    2005-07-01

    Surfactant flooding has the potential to significantly increase recovery over that of conventional waterflooding. The availability of a large number of surfactant structures makes it possible to conduct a systematic study of the relation between surfactant structure and its efficacy for oil recovery. A combination of two surfactants was found to be particularly effective for application in carbonate formations at low temperature. A formulation has been designed for a particular field application. The addition of an alkali such as sodium carbonate makes possible in situ generation of surfactant and significant reduction of surfactant adsorption. In addition to reduction of interfacial tension to ultra-low values, surfactants and alkali can be designed to alter wettability to enhance oil recovery. The design of the process to maximize the region of ultra-low IFT is more challenging since the ratio of soap to synthetic surfactant is a parameter in the conditions for optimal salinity. Compositional simulation of the displacement process demonstrates the interdependence of the various components for oil recovery. An alkaline surfactant process is designed to enhance spontaneous imbibition in fractured, oil-wet, carbonate formations. It is able to recover oil from dolomite core samples from which there was no oil recovery when placed in formation brine. Mobility control is essential for surfactant EOR. Foam is evaluated to improve the sweep efficiency of surfactant injected into fractured reservoirs. UTCHEM is a reservoir simulator specially designed for surfactant EOR. It has been modified to represent the effects of a change in wettability. Simulated case studies demonstrate the effects of wettability.

  18. Commercial scale demonstration: enhanced oil recovery by micellar-polymer flood. Annual report, October 1980-September 1981

    Energy Technology Data Exchange (ETDEWEB)

    Howell, J.C.

    1982-05-01

    This commercial scale test, known as the M-1 Project, is located in Crawford County, Illinois. It encompasses 407 acres of Robinson sand reservoir and covers portions of several waterflood projects that were approaching economic limit. The project includes 248 acres developed on a 2.5-acre five-spot pattern and 159 acres developed on a 5.0-acre five-spot pattern. Development work commenced in late 1974 and has previously been reported. Micellar solution (slug) injection was initiated on February 10, 1977, and is now completed. After 10% of a pore volume of micellar slug was injected, injection of 11% pore volume of Dow 700 Pusher polymer was conducted at a concentration of 1156 ppM. At the end of this reporting period, 625 ppM polymer was being injected into the 2.5-acre pattern and 800 ppM polymer was being injected into the 5.0-acre pattern. The oil cut of the 2.5-acre pattern has decreased from 11.0% in September 1980, to 7.9% in September 1981. The 2.5-acre pattern had been on a plateau since May 1980, and as of May 1981 appears to be on a decline. The oil cut of the 5.0-acre pattern has increased from 5.9% in September 1980, to 10.9% in September 1981. The 5.0-acre pattern experienced a sharp increase in oil cut after 34% of a pore volume of total fluid had been injected and appears to be continuing its incline. This fifth annual report is organized under the following three work breakdown structures: fluid injection; production; and performance monitoring.

  19. An approach to speed up simulation time of WAG-CO{sub 2} process; Uma abordagem para reducao do tempo de simulacao do processo WAG-CO{sub 2}

    Energy Technology Data Exchange (ETDEWEB)

    Ligero, Eliana Luci [Centro de Estudos de Petroleo (CEPETRO/UNICAMP), SP (Brazil); Schiozer, Denis Jose [Universidade Estadual de Campinas (DEP/FEM/UNICAMP), SP (Brazil). Fac. de Engenharia Mecanica. Dept. de Engenharia de Petroleo

    2012-07-01

    The use of CO{sub 2} in EOR processes is an attractive alternative to increase oil recovery and, at the same time, to avoid the emission of CO{sub 2} into the atmosphere. The possibility of CO{sub 2} injections is not limited to depleted reservoirs or to reservoirs after waterflooding, but also to reservoirs in the initial phase of their lives. A possible manner to inject CO{sub 2} is through the WAG process that combines the advantages of the two injection processes. The rigorous simulation of the WAG process is executed by a compositional formulation instead the simplified Black-Oil formulation. The compositional formulation requires more computational time to run a simulation model. Also, the procedure to shut-in and shut-off the injector wells alternately, to change the injection fluid, will once again increase the computational time of the WAG process. For this reason, a numerical approach was investigated in order to reduce this computational time. In this approach, called Pseudo WAG, water and CO{sub 2} are simultaneously injected into the simulation model, maintaining the same quantity of injection fluid as in the WAG process. The possibility of the Pseudo WAG to adequately represent the physical phenomena resulting from WAG-CO{sub 2} was investigated using a commercial and compositional simulator. The simulation runs executed for light oil with dissolved CO{sub 2} indicated that the WAG-CO{sub 2} process was effective for oil recovery. For the studied cases, the Pseudo WAG was capable of adequately representing the WAG-CO{sub 2} process, thus validating the proposed approach, providing a significant reduction in the computational time.(author)

  20. Enhanced oil recovery by surfactant-enhanced volumetric sweep efficiency: First annual report for the period September 30, 1985-September 30, 1986. [Sandpacks

    Energy Technology Data Exchange (ETDEWEB)

    Harwell, J H; Scamehorn, J F

    1987-05-01

    Surfactant-enhanced volumetric sweep efficiency is a novel EOR method which utilizes precipitation/coacervation of surfactants to plug the most permeable regions of the reservoir, improving the efficiency of a waterflooding operation. This technique does not rely on reduction of interfacial tension between aqueous and oleic phases to enhance oil recovery. Therefore, even though surfactants are involved, this new technique is not a substitute or improvement on classical surfactant flooding; however, it has the potantial to compete with polymer flooding as an alternative sweep efficiency improvement method. In surfactant-enhanced volumetric sweep efficiency, a slug containing one kind of surfactant is injected into the reservoir, followed by a brine spacer. This is followed by injection of a second kind of surfactant which has lower adsorption than the first surfactant used. Anionic and cationic surfactants are one possible combination for this application. These may form either a precipitate or a coacervate upon mixing. Phase boundaries for some specific systems of this type have been determined over a wide range of conditions and a model developed to describe this behavior. Another possibility is the use of nonionic surfactants, which may form coacervate under proper conditions. The adsorption behavior of mixtures of anionic and nonionic surfactants was measured to aid in modeling the chromatographic effects with these surfactants in the reservoir. Studies with sandpacks of different permeabilities in parallel configuration using mixtures of anionic and cationic surfactants have demonstrated the capability of this method to reduce flow rates through a more permeable sandpack more than that through a less permeable sandpack. 4 refs., 23 figs., 8 tabs.

  1. 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.

  2. Relating to fossil energy resource characterization, research, technology development, and technology transfer

    Energy Technology Data Exchange (ETDEWEB)

    Poston, S.W.; Berg, R.R.; Friedman, M.M.; Gangi, A.F.; Wu, C.H.

    1993-12-01

    Geological, geophysical and petroleum engineering aspects of oil recovery from low-permeability reservoirs have been studied over the past three years. Significant advances were made in using Formation Microscanner Surveys (FMS) data to extrapolate fracture orientation, abundance, and spacing from the outcrop to the subsurface. Highly fractured zones within the reservoir can be detected, thus the fracture stratigraphy defined. Multi-component,vertical-seismic profile (VSP), shear wave data were used to improve the detection of fractures. A balancing scheme was developed to improve the geophysical detection of fractures based on balanced source magnitudes and geophone couplings. Resistivity logs can be used to identify the zone of immature organic material, the zone of storage where oil is generated but held in the matrix and the zone of migration whee oil is expelled from the rock to fractures. Natural fractures can be detected in many wells by the response of density logs in combination with gamma-ray, resistivity, and sonic logs. Theoretical studies and analysis of daily production data, from field case histories, have shown the utility of the Chef Type Curves to derive reservoir character from production test data. This information is ordinarily determined from transient pressure data. Laboratory displacement as well as MI and CT studies show that the carbonated water imbibition oil displacement process significantly accelerates and increases recovery from saturated, low-permeability core material. The created gas drive, combined with oil shrinkage significantly increased oil recovery. A cyclic-carbonated-water-imbibition process improves oil recovery. A semi-analytical model (MOD) and a 3-dimensional, 3-phase, dual-porosity, compositional simulator (COMAS) were developed to describe the imbibition carbonated waterflood performance. MOD model is capable of computing the oil recovery and saturation profiles for oil/water viscosity ratios other than one.

  3. North Stanley Polymer Demonstration Project, second annual report

    Energy Technology Data Exchange (ETDEWEB)

    Johnson, J.P.; Cunningham, J.W.; DuBois, B.M.

    1977-10-01

    This project is a cooperative test of the economics of polymer enhanced waterflooding and is a field scale test involving 1,010 productive acres containing 72 million barrels of pore volume, 19 injection wells, and 28 producers. The primary activity during the second year was successful injection of the polymer slug. Polymer injection was completed June 22, 1977, after injecting 1,194,770 pounds of Dow Pusher 700 and 11,962,918 barrels of water over a period of 372 days. The average polymer concentration was 285 ppM. Nine of the injection wells were given Channelblock (TM) treatments. One well, Pappin 12, did not respond to the Channelblock treatment; it was the closest well to the injection plant, and the pressure was too high for the soft gel to hold. The rate on Pappin 12 was then restricted by use of a flow regulator coil; the polymer (250 ppM) underwent 12% shear degradation passing through the regulator coil. Movement of the slug through the reservoir was monitored by analysis of produced water samples. The producing wells were sampled every two weeks from Feb. through June and once a month thereafter. The water samples were analyzed for salinity and polymer. The primary producing problem was a change in the producing well fluid levels resulting from the changes in injection distribution, and it was necessary to either change out the pump or lower the present pump which resulted in less efficiency. The oil production started responding in Sept. 1976 by increasing 15 BPD to 581 BPD. It increased to 586 BPD in Oct., 590 BPD in Nov., and 592 BPD in Dec. In Jan., production jumped to 660 BPD. It fell back to 641 in Feb. but slowly increased to 658 BPD by May. June's production fell back to 645 BPD, partially as a result of lower injection rates experienced when polymer injection was terminated. (DLC)

  4. Bugging out : biological H{sub 2}S removal is gaining a toehold in the sour gas fields of western Canada

    Energy Technology Data Exchange (ETDEWEB)

    Collison, M.

    2006-04-15

    New hydrogen sulphide (H{sub 2}S) removal techniques and applications in the oil and gas sector were reviewed. H{sub 2}S has been blamed for a variety of health problems in people and livestock. Although the Claus process is still recognized as the industry standard when there are very high levels of H{sub 2}S, nitrates are increasingly being used where lower levels of H{sub 2}S are found and in a variety of novel situations. Sweet reservoirs can often become sour due to contamination over time by bacteria introduced by drilling muds and waterflooding. Naturally occurring microbial life and elements such as nitrogen are now being used to manipulate or rebalance reservoir chemistry. Microbes also being used for H{sub 2}S contamination in gas storage in underground reservoirs. However, although nitrates have been used to neutralize H{sub 2}S for many years in sewer systems in Paris, more engineering research is needed for the process to gain widespread acceptance in the oil and gas sector. Customizing nutrients to the specific situation and choosing the right process for any given gas stream or oilfield have been central challenges to the use of microbes. EnCana Corporation has recently tested a new desulphurization process where bacteria is cultured and introduced into reactors using an above-ground gas/liquid absorber injected with buffered alkaline solution through which the sour gas is directed. A modified Claus process has also been tested which uses a catalyst by which air reacts with H{sub 2}S without affecting hydrocarbon components to produce elemental sulphur and water. The pilot plant still in the early stages of development. 2 figs.

  5. Inverse Modeling Using Markov Chain Monte Carlo Aided by Adaptive Stochastic Collocation Method with Transformation

    Science.gov (United States)

    Zhang, D.; Liao, Q.

    2016-12-01

    The Bayesian inference provides a convenient framework to solve statistical inverse problems. In this method, the parameters to be identified are treated as random variables. The prior knowledge, the system nonlinearity, and the measurement errors can be directly incorporated in the posterior probability density function (PDF) of the parameters. The Markov chain Monte Carlo (MCMC) method is a powerful tool to generate samples from the posterior PDF. However, since the MCMC usually requires thousands or even millions of forward simulations, it can be a computationally intensive endeavor, particularly when faced with large-scale flow and transport models. To address this issue, we construct a surrogate system for the model responses in the form of polynomials by the stochastic collocation method. In addition, we employ interpolation based on the nested sparse grids and takes into account the different importance of the parameters, under the condition of high random dimensions in the stochastic space. Furthermore, in case of low regularity such as discontinuous or unsmooth relation between the input parameters and the output responses, we introduce an additional transform process to improve the accuracy of the surrogate model. Once we build the surrogate system, we may evaluate the likelihood with very little computational cost. We analyzed the convergence rate of the forward solution and the surrogate posterior by Kullback-Leibler divergence, which quantifies the difference between probability distributions. The fast convergence of the forward solution implies fast convergence of the surrogate posterior to the true posterior. We also tested the proposed algorithm on water-flooding two-phase flow reservoir examples. The posterior PDF calculated from a very long chain with direct forward simulation is assumed to be accurate. The posterior PDF calculated using the surrogate model is in reasonable agreement with the reference, revealing a great improvement in terms of

  6. Origin and Distribution of Hydrogen Sulfide in Oil-Bearing Basins, China

    Institute of Scientific and Technical Information of China (English)

    ZHU Guangyou; ZHANG Shuichang; LIANG Yingbo

    2009-01-01

    The concentration of hydrogen sulfide gas (H_2S) varies greatly in the oil-bearing basins of China, from zero to 90%. At present, oil and gas reservoirs with high H_2S concentration have been discovered in three basins, viz. the Bohai Bay Basin, Sichuan Basin and the Tarim Basin, whereas natural gas with low H_2S concentration has been found in the Ordos Basin, the Songiiao Basin and the Junggar Basin. Studies suggest that in China H_2S origin types are very complex. In the carbonate reservoir of the Sichuan Basin, the Ordos Basin and the Tarim Basin, as well as the carbonate-dominated reservoir in the Luojia area of the Jiyang depression in the Bohai Bay Basin, Wumaying areas of the Huanghua depression, and Zhaolanzhuang areas of the Jizhong depression, the H_2S is of Thermochemical Sulfate Reduction (TSR) origin. The H_2S is of Bacterial Sulphate Reduction (BSR) origin deduced from the waterflooding operation in the Changheng Oiifieid (placanticline oil fields) in the Songliao Basin. H_2S originates from thermal decomposition of sulfur-bearing crude oil in the heavy oil area in the Junggar Basin and in the Liaohe heavy oil steam pilot area in the western depression of the Bohai Bay Basin. The origin types are most complex, including TSR and thermal decomposition of sulfcompounds among other combinations of causes. Various methods have been tried to identify the origin mechanism and to predict the distribution of H_2S. The origin identification methods for H_2S mainly comprise sulfur and carbon isotopes, reservoir petrology, particular biomarkers, and petroleum geology integrated technologies; using a combination of these applications can allow the accurate identification of the origins of H_2S. The prediction technologies for primary and secondary origin of H_2S have been set up separately.

  7. Reservoir characterization of the Ordovician Red River Formation in southwest Williston Basin Bowman County, ND and Harding County, SD

    Energy Technology Data Exchange (ETDEWEB)

    Sippel, M.A.; Luff, K.D.; Hendricks, M.L.; Eby, D.E.

    1998-07-01

    This topical report is a compilation of characterizations by different disciplines of the Red River Formation in the southwest portion of the Williston Basin and the oil reservoirs which it contains in an area which straddles the state line between North Dakota and South Dakota. Goals of the report are to increase understanding of the reservoir rocks, oil-in-place, heterogeneity, and methods for improved recovery. The report is divided by discipline into five major sections: (1) geology, (2) petrography-petrophysical, (3) engineering, (4) case studies and (5) geophysical. Interwoven in these sections are results from demonstration wells which were drilled or selected for special testing to evaluate important concepts for field development and enhanced recovery. The Red River study area has been successfully explored with two-dimensional (2D) seismic. Improved reservoir characterization utilizing 3-dimensional (3D) and has been investigated for identification of structural and stratigraphic reservoir compartments. These seismic characterization tools are integrated with geological and engineering studies. Targeted drilling from predictions using 3D seismic for porosity development were successful in developing significant reserves at close distances to old wells. Short-lateral and horizontal drilling technologies were tested for improved completion efficiency. Lateral completions should improve economics for both primary and secondary recovery where low permeability is a problem and higher density drilling is limited by drilling cost. Low water injectivity and widely spaced wells have restricted the application of waterflooding in the past. Water injection tests were performed in both a vertical and a horizontal well. Data from these tests were used to predict long-term injection and oil recovery.

  8. Micellar-polymer joint demonstration project, Wilmington Field, California. Annual report, 1976--1977

    Energy Technology Data Exchange (ETDEWEB)

    Wade, J.E.

    1977-12-01

    Work accomplished under the contract during the first year of operation consisted of Micellar-Polymer laboratory systems design; Test Pattern Model Studies; Drilling and coring injection well FT-1; Pressure Transient Tests of Wells Z-81, Z1-16and FT-1; as well as design and construction of a portion of the surface facilities. Radial core floods conducted by Marathon Research Center using reservoir rock and fluid samples from the Wilmington Field demonstrated that Micellar-Polymer systems showing good recovery efficiency could be made from several different commercially available sulfonates. Residual oil saturations obtained were as low as 7 to 10% pore volume. Sulfonates made from Wilmington crude oil also proved to be effective. Polyacrylamides, both liquid and dry, as well as polysaccharides proved equally effective as a mobility buffer. Test pattern model studies were conducted on seven different arrays of wells. These studies showed that the pattern originally proposed exhibited poor areal sweep efficiency and was seriously affected by waterflood operations in the North Flank of the fault block. An E-W staggered line drive backed-up against the Pier A Fault appeared to be the best pattern studied, assuming the Pier A Fault to be a pressure barrier. Injection well FT-1 was drilled, cored and completed in the Hx/sub a/ sand. Cores were taken using low-solids, polymer drilling fluid and were frozen on site. The frozen cores from the project area will be used in the Phase B laboratory work. Pressure Transient Tests run in Z-81 and Z1-16 indicated the Pier A Fault to be pressure competent. The plant site was located adjacent to a railroad siding near the injection wells. The site was graded and seven 2000 barrel tanks were erected. The tanks were internally plastic coated on site. Mixing, filtering and injection facilities are being installed.

  9. Study of Water Treatment Residue Used as a Profile Control Agent%水处理残渣调剖剂室内研究及现场应用

    Institute of Scientific and Technical Information of China (English)

    侯天江; 赵化廷; 李宗田; 赵普春; 肖利平

    2005-01-01

    A large amount of residue from the water treatment process has gradually accumulated and thus caused serious environmental pollution in waterflood oilfields. The water treatment residue is a grey suspension, with a density of 1.08 g/cm3, and mainly contains over 65% of light CaCO3, MgCO3, CaSO4, Fe2S3 and Ca(OH)2. This paper ascertains the effect of water treatment residue on core permeability and its application in oilfields. Coreflooding tests in laboratory were conducted in two artificial cores and one natural core. Core changes were evaluated by cast model image analysis, mercury injection method and scanning electron microscopy (SEM). Fresh water was injected into another natural core, which was plugged with water treatment residue, to determine the effective life.The results indicate that the water treatment residue has a strongly plugging capability, a resistance to erosion and a long effective life, and thus it can be used as a cheap raw material for profile control.In the past 8 years, a total of 60,164 m3 of water treatment residue has been used for profile control of 151 well treatments, with a success ratio of 98% and an effective ratio of 83.2%. In the field tests, the profile control agent increased both starting pressure and injection pressure of injectors, and decreased the apparent water injectivity coefficient, significantly improving intake profiles and lengthening average service life of injectors. 28,381 tons of additional oil were recovered from these corresponding oil wells, with economic benefits of ¥3,069.55×104 (RMB) and a remarkable input-output ratio of 8.6:1.

  10. Characterization of sulphate scaling formation damage from laboratory measurements to predict well productivity decline

    Energy Technology Data Exchange (ETDEWEB)

    Bedrikovetsky, P.G.; Monteiro, R. [Universidade Estadual do Norte Fluminense (UENF), Macae, RJ (Brazil). Lab. de Engenharia e Exploracao de Petroleo (LENEP); Moraes, G.P. [Centro Federal de Educacao Tecnologica (CEFET), Macae, RJ (Brazil). Unidade de Ensino Descentralizada (UNED-Macae); Lopes Junior, R.P. [PETROBRAS, Macae, RJ (Brazil). Unidade de Negocios da Bacia de Campos; Rosario, F.F.; Bezerra, M.C. [PETROBRAS, Rio de Janeiro, RJ (Brazil). Centro de Pesquisas (CENPES)

    2004-07-01

    Barium sulphate scaling is a chronicle disaster during offshore waterflood project where injected and formation waters are incompatible, and their mixing causes salt precipitation. It was detected in several fields of Campos Basin. The mathematical model for sulphate precipitation contains two empirical parameters: the reaction kinetics coefficient that characterizes how fast the precipitation is going on, and the formation damage coefficient showing which permeability impairment the precipitation causes. Knowledge of these two parameters is essential for reliable prediction of the well productivity decline during sea/produced water injection. These parameters are empirical and depend on rock properties; therefore they should be determined from laboratory coreflood tests by forcing the injected and formation waters through rock. Despite these tests have been presented in numerous papers, there were no attempts to determine the model coefficients from laboratory data in order to perform the laboratory-data-based reservoir simulation. A new method for simultaneous determination of both coefficients from the coreflood data is developed. The method determines the kinetic coefficient from ion concentration measurements at the core effluent; then the formation damage coefficient is determined from the pressure drop measurements. The laboratory procedures are routine, the data are available in the literature. The method is based on inverse problem for reactive flow in rocks. The inverse solution is obtained from the exact quasi steady state concentration profile during coreflood. The proposed method furnishes unique values for two coefficients, and the solution is stable with respect to small perturbations of the measured values. The laboratory data on sulphate scaling by CENPES/PETROBRAS, Brazil, and Herriot-Watt University, UK, were treated, and the data were used for prediction of productivity decline in Campos Basin reservoir. The well behaviour forecast and history

  11. Performance of a Polymer Flood with Shear-Thinning Fluid in Heterogeneous Layered Systems with Crossflow

    Directory of Open Access Journals (Sweden)

    Kun Sang Lee

    2011-08-01

    Full Text Available Assessment of the potential of a polymer flood for mobility control requires an accurate model on the viscosities of displacement fluids involved in the process. Because most polymers used in EOR exhibit shear-thinning behavior, the effective viscosity of a polymer solution is a highly nonlinear function of shear rate. A reservoir simulator including the model for the shear-rate dependence of viscosity was used to investigate shear-thinning effects of polymer solution on the performance of the layered reservoir in a five-spot pattern operating under polymer flood followed by waterflood. The model can be used as a quantitative tool to evaluate the comparative studies of different polymer flooding scenarios with respect to shear-rate dependence of fluids’ viscosities. Results of cumulative oil recovery and water-oil ratio are presented for parameters of shear-rate dependencies, permeability heterogeneity, and crossflow. The results of this work have proven the importance of taking non-Newtonian behavior of polymer solution into account for the successful evaluation of polymer flood processes. Horizontal and vertical permeabilities of each layer are shown to impact the predicted performance substantially. In reservoirs with a severe permeability contrast between horizontal layers, decrease in oil recovery and sudden increase in WOR are obtained by the low sweep efficiency and early water breakthrough through highly permeable layer, especially for shear-thinning fluids. An increase in the degree of crossflow resulting from sufficient vertical permeability is responsible for the enhanced sweep of the low permeability layers, which results in increased oil recovery. It was observed that a thinning fluid coefficient would increase injectivity significantly from simulations with various injection rates. A thorough understanding of polymer rheology in the reservoir and accurate numerical modeling are of fundamental importance for the exact estimation

  12. Mechanism and environmental effects on MEOR induced by the alpha process

    Energy Technology Data Exchange (ETDEWEB)

    Hiebert, F.K.; Zumberge, J.; Rouse, B.; Cowes, A.; Lake, L.W.

    1993-04-01

    This project was an interdisciplinary investigation of the enhanced oil recovery effects of a commercial microbial enhanced oil recovery (MEOR) system. The purpose was to investigate in parallel laboratory and field studies the response of a portion of the Shannon Sandstone reservoir to two single-well treatments with a commercial MEOR system, to investigate basic bacteria/rock interactions, and to investigate mechanisms of oil release. The MEOR system consisted of a mixed culture of hydrocarbon-utilizing bacteria, inorganic nutrients, and other growth factors. Parallel field and laboratory investigations into the effect and mechanisms of the treatment were carried out by independent principal investigators. The Shannon Sandstone at the Naval Petroleum Reserve [number sign]3 (NPR [number sign]3), Teapot Dome Field, Wyoming, was the location of the pilot field treatment. The treated and adjacent observation wells showed production and microbiological perturbations that are attributed to the effects of treatment during the first four post-treatment months. Effects of treatment declined to background levels within four months of inoculation. No production response was recorded in control wells unaffected by microbial stimulation. Laboratory research resulted in descriptions of colonization patterns of hydrocarbon-utilizing bacteria in the reservoir rock environment. Core-flooding research utilizing various components of the MEOR system did not result in the isolation of an oilrelease mechanism or measure incremental oil recovery from cores at residual oil saturation to waterflood. Chemical analysis of pre- and post-treatment produced oil identified large organic acid molecules concentrated in the asphaltenic fraction of posttreatment oil, but not in the oil from untreated control wells. No significant changes were measured in the overall quality of the oil produced from MEOR treated wells.

  13. Mechanism and environmental effects on MEOR induced by the alpha process. Final report

    Energy Technology Data Exchange (ETDEWEB)

    Hiebert, F.K.; Zumberge, J.; Rouse, B.; Cowes, A.; Lake, L.W.

    1993-04-01

    This project was an interdisciplinary investigation of the enhanced oil recovery effects of a commercial microbial enhanced oil recovery (MEOR) system. The purpose was to investigate in parallel laboratory and field studies the response of a portion of the Shannon Sandstone reservoir to two single-well treatments with a commercial MEOR system, to investigate basic bacteria/rock interactions, and to investigate mechanisms of oil release. The MEOR system consisted of a mixed culture of hydrocarbon-utilizing bacteria, inorganic nutrients, and other growth factors. Parallel field and laboratory investigations into the effect and mechanisms of the treatment were carried out by independent principal investigators. The Shannon Sandstone at the Naval Petroleum Reserve {number_sign}3 (NPR {number_sign}3), Teapot Dome Field, Wyoming, was the location of the pilot field treatment. The treated and adjacent observation wells showed production and microbiological perturbations that are attributed to the effects of treatment during the first four post-treatment months. Effects of treatment declined to background levels within four months of inoculation. No production response was recorded in control wells unaffected by microbial stimulation. Laboratory research resulted in descriptions of colonization patterns of hydrocarbon-utilizing bacteria in the reservoir rock environment. Core-flooding research utilizing various components of the MEOR system did not result in the isolation of an oilrelease mechanism or measure incremental oil recovery from cores at residual oil saturation to waterflood. Chemical analysis of pre- and post-treatment produced oil identified large organic acid molecules concentrated in the asphaltenic fraction of posttreatment oil, but not in the oil from untreated control wells. No significant changes were measured in the overall quality of the oil produced from MEOR treated wells.

  14. Time-lapse 3D VSP monitoring of a carbon dioxide injection project at Delhi Field, Louisiana

    Science.gov (United States)

    Lubis, Muhammad Husni Mubarak

    Delhi Field is a producing oil field located in northeastern Louisiana. The estimated original oil in place (OOIP) is 357 mmbo and approximately 54% of OOIP has been produced through the primary production and water-flooding. A CO2-EOR program has been implemented since November 2009 to recover an additional 17% of OOIP. Reservoir surveillance using time-lapse 3D seismic data has been conducted to monitor the CO2 sweep efficiency. The goal of this study is to monitor the CO2 flow-path in the area around the injector using time-lapse 3D VSP data. For this purpose, two 3D VSPs acquired in June 2010 and again in August 2011 were processed together. Fluid substitution and VSP modeling were performed to understand the influence of pore-fluid saturation change on VSP records. A cross-equalization was performed to improve the similarity of the datasets. This step is important to reduce the ambiguity in time-lapse observation. The splice of a 3D VSP image into the surface seismic data becomes the key point in determining the reflector of the reservoir. By integrating the observation from the modeling and the splice of 3D VSP image to surface seismic, the CO2 flow-path from injector 164-3 can be identified from 3D time-lapse VSP data. The CO2 was not radially distributed around the injector, but moved toward southwest direction. This finding is also consistent with the flow-path interpreted from surface seismic. This consistency implies that time-lapse 3D VSP surveys at Delhi Field confirm and augment the time-lapse interpretation from surface seismic data.

  15. Improved Criteria for Increasing CO2 Storage Potential with CO2 Enhanced Oil Recovery

    Science.gov (United States)

    Bauman, J.; Pawar, R.

    2013-12-01

    In recent years it has been found that deployment of CO2 capture and storage technology at large scales will be difficult without significant incentives. One of the technologies that has been a focus in recent years is CO2 enhanced oil/gas recovery, where additional hydrocarbon recovery provides an economic incentive for deployment. The way CO2 EOR is currently deployed, maximization of additional oil production does not necessarily lead to maximization of stored CO2, though significant amounts of CO2 are stored regardless of the objective. To determine the potential of large-scale CO2 storage through CO2 EOR, it is necessary to determine the feasibility of deploying this technology over a wide range of oil/gas field characteristics. In addition it is also necessary to accurately estimate the ultimate CO2 storage potential and develop approaches that optimize oil recovery along with long-term CO2 storage. This study uses compositional reservoir simulations to further develop technical screening criteria that not only improve oil recovery, but maximize CO2 storage during enhanced oil recovery operations. Minimum miscibility pressure, maximum oil/ CO2 contact without the need of significant waterflooding, and CO2 breakthrough prevention are a few key parameters specific to the technical aspects of CO2 enhanced oil recovery that maximize CO2 storage. We have developed reduced order models based on simulation results to determine the ultimate oil recovery and CO2 storage potential in these formations. Our goal is to develop and demonstrate a methodology that can be used to determine feasibility and long-term CO2 storage potential of CO2 EOR technology.

  16. Major Oil Plays in Utah and Vicinity

    Energy Technology Data Exchange (ETDEWEB)

    Thomas C. Chidsey; Craig D. Morgan; Kevin McClure; Douglas A. Sprinkel; Roger L. Bon; Hellmut H. Doelling

    2003-12-31

    fractured and sealed by overlying argillaceous and non-fractured units. The best outcrop analogs for Twin Creek reservoirs are found at Devils Slide and near the town of Peoa, Utah, where fractures in dense, homogeneous non-porous limestone beds are in contact with the basal siltstone units (containing sealed fractures) of the overlying units. The shallow marine, Mississippian Leadville Limestone is a major oil and gas reservoir in the Paradox Basin of Utah and Colorado. Hydrocarbons are produced from basement-involved, northwest-trending structural traps with closure on both anticlines and faults. Excellent outcrops of Leadville-equivalent rocks are found along the south flank of the Uinta Mountains, Utah. For example, like the Leadville, the Mississippian Madison Limestone contains zones of solution breccia, fractures, and facies variations. When combined with subsurface geological and production data, these outcrop analogs can improve (1) development drilling and production strategies such as horizontal drilling, (2) reservoir-simulation models, (3) reserve calculations, and (4) design and implementation of secondary/tertiary oil recovery programs and other best practices used in the oil fields of Utah and vicinity. In the southern Green River Formation play of the Uinta Basin, optimal drilling, development, and production practices consist of: (1) owning drilling rigs and frac holding tanks; (2) perforating sandstone beds with more than 8 percent neutron porosity and stimulate with separate fracture treatments; (3) placing completed wells on primary production using artificial lift; (4) converting wells relatively soon to secondary waterflooding maintaining reservoir pressure above the bubble point to maximize oil recovery; (5) developing waterflood units using an alternating injector--producer pattern on 40-acre (16-ha) spacing; and (6) recompleting producing wells by perforating all beds that are productive in the waterflood unit. As part of technology transfer

  17. Evaluating the Influence of Pore Architecture and Initial Saturation on Wettability and Relative Permeability in Heterogeneous, Shallow-Shelf Carbonates

    Energy Technology Data Exchange (ETDEWEB)

    Byrnes, Alan P.; Bhattacharya, Saibal; Victorine, John; Stalder, Ken

    2007-09-30

    Thin (3-40 ft thick), heterogeneous, limestone and dolomite reservoirs, deposited in shallow-shelf environments, represent a significant fraction of the reservoirs in the U.S. midcontinent and worldwide. In Kansas, reservoirs of the Arbuckle, Mississippian, and Lansing-Kansas City formations account for over 73% of the 6.3 BBO cumulative oil produced over the last century. For these reservoirs basic petrophysical properties (e.g., porosity, absolute permeability, capillary pressure, residual oil saturation to waterflood, resistivity, and relative permeability) vary significantly horizontally, vertically, and with scale of measurement. Many of these reservoirs produce from structures of less than 30-60 ft, and being located in the capillary pressure transition zone, exhibit vertically variable initial saturations and relative permeability properties. Rather than being simpler to model because of their small size, these reservoirs challenge characterization and simulation methodology and illustrate issues that are less apparent in larger reservoirs where transition zone effects are minor and most of the reservoir is at saturations near S{sub wirr}. These issues are further augmented by the presence of variable moldic porosity and possible intermediate to mixed wettability and the influence of these on capillary pressure and relative permeability. Understanding how capillary-pressure properties change with rock lithology and, in turn, within transition zones, and how relative permeability and residual oil saturation to waterflood change through the transition zone is critical to successful reservoir management and as advanced waterflood and improved and enhanced recovery methods are planned and implemented. Major aspects of the proposed study involve a series of tasks to measure data to reveal the nature of how wettability and drainage and imbibition oil-water relative permeability change with pore architecture and initial water saturation. Focus is placed on

  18. Enzymes for Enhanced Oil Recovery (EOR)

    Energy Technology Data Exchange (ETDEWEB)

    Nasiri, Hamidreza

    2011-04-15

    Primary oil recovery by reservoir pressure depletion and secondary oil recovery by waterflooding usually result in poor displacement efficiency. As a consequence there is always some trapped oil remaining in oil reservoirs. Oil entrapment is a result of complex interactions between viscous, gravity and capillary forces. Improving recovery from hydrocarbon fields typically involves altering the relative importance of the viscous and capillary forces. The potential of many EOR methods depends on their influence on fluid/rock interactions related to wettability and fluid/fluid interactions reflected in IFT. If the method has the potential to change the interactions favorably, it may be considered for further investigation, i.e. core flooding experiment, pilot and reservoir implementation. Enzyme-proteins can be introduced as an enhanced oil recovery method to improve waterflood performance by affecting interactions at the oil-water-rock interfaces. An important part of this thesis was to investigate how selected enzymes may influence wettability and capillary forces in a crude oil-brine-rock system, and thus possibly contribute to enhanced oil recovery. To investigate further by which mechanisms selected enzyme-proteins may contribute to enhance oil recovery, groups of enzymes with different properties and catalytic functions, known to be interfacially active, were chosen to cover a wide range of possible effects. These groups include (1) Greenzyme (GZ) which is a commercial EOR enzyme and consists of enzymes and stabilizers (surfactants), (2) The Zonase group consists of two types of pure enzyme, Zonase1 and Zonase2 which are protease enzymes and whose catalytic functions are to hydrolyze (breakdown) peptide bonds, (3) The Novozyme (NZ) group consists of three types of pure enzyme, NZ2, NZ3 and NZ6 which are esterase enzymes and whose catalytic functions are to hydrolyze ester bonds, and (4) Alpha-Lactalbumin ( -La) which is an important whey protein. The effect of

  19. 注入水中悬浮微粒导致储层伤害网络模拟研究%Network Simulation of Formation Damage Due to Suspended Particles in Injection Water

    Institute of Scientific and Technical Information of China (English)

    冯其红; 韩晓冬; 王守磊; 张欣; 周文胜

    2014-01-01

    注入流体中的悬浮固体微粒随流体进入储层后会对储层造成伤害,导致储层渗透率降低,明确不同因素对储层伤害的影响规律对现场储层伤害的预防和治理有十分重要的意义。因此应用网络模拟方法对不同条件下储层伤害变化规律及孔喉变化规律进行了研究。模拟结果表明:随驱替的不断进行,孔喉半径总体逐渐减小,且距离注入端面越近,孔喉半径减小幅度越大;注入流量越小、注入流体内微粒浓度越大、流体黏度越小、微粒粒径越大,越有利于微粒的沉积,造成的储层伤害越严重。%Particles suspended in injection water could damage the formation and decrease the permeability. And it’s of great importance to study the impact of various factors on the formation impairment for its prevention and treatment. In our study here,pore scale network modeling method is applied to the study of the formation damage patterns and the change of the pore-throat radius under various conditions. In network models,different microcosmic particle variation mechanisms are taken into consideration. The results indicate that the pore-throat radius will decrease with the process of waterflooding and pore-throats that are closer to the inlet face will have a much higher decrease of their radius. Besides,the lower the flow rate is,the higher the particle concentration in injection water is,the lower the fluid viscosity and bigger particle size,it will be beneficial for the formation damage.

  20. Reservoir characterization using core, well log, and seismic data and intelligent software

    Science.gov (United States)

    Soto Becerra, Rodolfo

    We have developed intelligent software, Oilfield Intelligence (OI), as an engineering tool to improve the characterization of oil and gas reservoirs. OI integrates neural networks and multivariate statistical analysis. It is composed of five main subsystems: data input, preprocessing, architecture design, graphics design, and inference engine modules. More than 1,200 lines of programming code as M-files using the language MATLAB been written. The degree of success of many oil and gas drilling, completion, and production activities depends upon the accuracy of the models used in a reservoir description. Neural networks have been applied for identification of nonlinear systems in almost all scientific fields of humankind. Solving reservoir characterization problems is no exception. Neural networks have a number of attractive features that can help to extract and recognize underlying patterns, structures, and relationships among data. However, before developing a neural network model, we must solve the problem of dimensionality such as determining dominant and irrelevant variables. We can apply principal components and factor analysis to reduce the dimensionality and help the neural networks formulate more realistic models. We validated OI by obtaining confident models in three different oil field problems: (1) A neural network in-situ stress model using lithology and gamma ray logs for the Travis Peak formation of east Texas, (2) A neural network permeability model using porosity and gamma ray and a neural network pseudo-gamma ray log model using 3D seismic attributes for the reservoir VLE 196 Lamar field located in Block V of south-central Lake Maracaibo (Venezuela), and (3) Neural network primary ultimate oil recovery (PRUR), initial waterflooding ultimate oil recovery (IWUR), and infill drilling ultimate oil recovery (IDUR) models using reservoir parameters for San Andres and Clearfork carbonate formations in west Texas. In all cases, we compared the results from

  1. Potential for horizontal well technology in the U.S

    Energy Technology Data Exchange (ETDEWEB)

    Biglarbigi, K.; Mohan, H. [Intek Inc., Fairfax, VA (United States); Ray, R.M. [USDOE, National Petroleum Technology Office, Tulsa, OK (United States); Meehan, D.N. [Union Pacific Resources Inc., Fort Worth, TX (United States)

    2000-11-01

    In the past decade, the use of horizontal well technology has increased significantly in the U.S., contributing to the drilling of 600 to 1000 horizontal oil wells annually. A total of 86 per cent of the existing horizontal wells have been drilled in three formations, the Austin chalk in Texas, the Bakken shale in North Dakota, and the Niobrara in Colorado and Wyoming. A unique analytical system has been developed by the United States Department of Energy, National Petroleum Technology Office (USDOE/NPTO) to assess the potential for greater use of horizontal well technology for other oil resources in other geological formations. The analytical system is designed to be used in association with other enhanced recovery methods that make up the DOE's Total Oil Recovery Information System (TORIS). The DOE/NPTO collaborated with industry to identify the target resource for horizontal well technology and to evaluate its future recovery potential under different economic and technological conditions. This paper provides a national summary of the potential for additional production and reserves with more diverse application of horizontal wells in various types of U.S. oil resources, including the rest of the fractured reservoirs in the Austin chalk, other fractured reservoirs in the north and northwestern states, thin-bed reservoirs, and mature waterflood field. The results were presented in terms of production, reserves and national economic benefits with a full cash-flow analysis at oil prices in the range of $16 to $24 U.S. per bbl. It is estimated that 541 million to 1 billion bbls of new reserves are economically producible at these prices. The reserves estimates pertain to future horizontal wells in known fields only and are in addition to the reserves for the existing wells as of 1 January 1998. Potential production is substantial, ranging from 50 million to 85 million bbl per year by 2004 and then declining at a rate of 8 per cent per year in the following

  2. Potential for horizontal well technology in the U.S.

    Energy Technology Data Exchange (ETDEWEB)

    Biglarbigi, K.; Mohan, H. [Intek Inc., Fairfax, VA (United States); Ray, R.M. [USDOE, National Petroleum Technology Office, Tulsa, OK (United States); Meehan, D.N. [Union Pacific Resources Inc., Fort Worth, TX (United States)

    2000-11-01

    In the past decade, the use of horizontal well technology has increased significantly in the U.S., contributing to the drilling of 600 to 1000 horizontal oil wells annually. A total of 86 per cent of the existing horizontal wells have been drilled in three formations, the Austin chalk in Texas, the Bakken shale in North Dakota, and the Niobrara in Colorado and Wyoming. A unique analytical system has been developed by the United States Department of Energy, National Petroleum Technology Office (USDOE/NPTO) to assess the potential for greater use of horizontal well technology for other oil resources in other geological formations. The analytical system is designed to be used in association with other enhanced recovery methods that make up the DOE's Total Oil Recovery Information System (TORIS). The DOE/NPTO collaborated with industry to identify the target resource for horizontal well technology and to evaluate its future recovery potential under different economic and technological conditions. This paper provides a national summary of the potential for additional production and reserves with more diverse application of horizontal wells in various types of U.S. oil resources, including the rest of the fractured reservoirs in the Austin chalk, other fractured reservoirs in the north and northwestern states, thin-bed reservoirs, and mature waterflood field. The results were presented in terms of production, reserves and national economic benefits with a full cash-flow analysis at oil prices in the range of $16 to $24 U.S. per bbl. It is estimated that 541 million to 1 billion bbls of new reserves are economically producible at these prices. The reserves estimates pertain to future horizontal wells in known fields only and are in addition to the reserves for the existing wells as of 1 January 1998. Potential production is substantial, ranging from 50 million to 85 million bbl per year by 2004 and then declining at a rate of 8 per cent per year in the following

  3. 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

  4. The effect of wettability on capillary trapping in carbonates

    Science.gov (United States)

    Alyafei, Nayef; Blunt, Martin J.

    2016-04-01

    We use an organic acid (cyclohexanepentanoic acid) to alter the wettability of three carbonates: Estaillades, Ketton and Portland limestones, and observe the relationship between the initial oil saturation and the residual saturation. We take cores containing oil and a specified initial water saturation and waterflood until 10 pore volumes have been injected. We record the remaining oil saturation as a function of the amount of water injected. In the water-wet case, with no wettability alteration, we observe, as expected, a monotonic increase in the remaining oil saturation with initial saturation. However, when the wettability is altered, we observe an increase, then a decrease, and finally an increase in the trapping curve for Estaillades limestone with a small, but continued, decrease in the remaining saturation as more water is injected. This behavior is indicative of mixed-wet or intermediate-wet conditions, as there is no spontaneous imbibition of oil and water. In contrast, Ketton did not show indications of a significant wettability alteration with a similar observed trapping profile to that observed in the water-wet case. Portland limestone also showed a monotonic increasing trend in remaining saturation with initial saturation but with a higher recovery, and less trapping, than the water-wet case. Again, this is intermediate-wet behavior with no spontaneous imbibition of either oil or water, and slow production of oil after water breakthrough. Finally, we repeat the same experiments but instead we age the three carbonates with a high asphaltenic content and high viscosity crude oil at 70 °C mimicking reservoir conditions. The results show a monotonic increase in residual saturation as a function of initial saturation but with higher recovery than the water-wet cases for Estaillades and Portland, with again no indication of wettability alteration for Ketton. We discuss the results in terms of pore-scale recovery process and contact angle hysteresis. In

  5. 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

  6. Fluid Substitution Modeling to Determine Sensitivity of 3D Vertical Seismic Profile Data to Injected CO­2­ at an active Carbon Capture, Utilization and Storage Project, Farnsworth field, TX.

    Science.gov (United States)

    Haar, K. K.; Balch, R. S.

    2015-12-01

    The Southwest Regional Partnership on Carbon Sequestration monitors a CO2 capture, utilization and storage project at Farnsworth field, TX. The reservoir interval is a Morrowan age fluvial sand deposited in an incised valley. The sands are between 10 to 25m thick and located about 2800m below the surface. Primary oil recovery began in 1958 and by the late 1960's secondary recovery through waterflooding was underway. In 2009, Chaparral Energy began tertiary recovery using 100% anthropogenic CO2 sourced from an ethanol and a fertilizer plant. This constitutes carbon sequestration and fulfills the DOE's initiative to determine the best approach to permanent carbon storage. One purpose of the study is to understand CO­2 migration from injection wells. CO2­ plume spatial distribution for this project is analyzed with the use of time-lapse 3D vertical seismic profiles centered on CO2 injection wells. They monitor raypaths traveling in a single direction compared to surface seismic surveys with raypaths traveling in both directions. 3D VSP surveys can image up to 1.5km away from the well of interest, exceeding regulatory requirements for maximum plume extent by a factor of two. To optimize the timing of repeat VSP acquisition, the sensitivity of the 3D VSP surveys to CO2 injection was analyzed to determine at what injection volumes a seismic response to the injected CO­2 will be observable. Static geologic models were generated for pre-CO2 and post-CO2 reservoir states through construction of fine scale seismic based geologic models, which were then history matched via flow simulations. These generated static states of the model, where CO2­ replaces oil and brine in pore spaces, allow for generation of impedance volumes which when convolved with a representative wavelet generate synthetic seismic volumes used in the sensitivity analysis. Funding for the project is provided by DOE's National Energy Technology Laboratory (NETL) under Award No. DE-FC26-05NT42591.

  7. A New Screening Methodology for Improved Oil Recovery Processes Using Soft-Computing Techniques

    Science.gov (United States)

    Parada, Claudia; Ertekin, Turgay

    2010-05-01

    The first stage of production of any oil reservoir involves oil displacement by natural drive mechanisms such as solution gas drive, gas cap drive and gravity drainage. Typically, improved oil recovery (IOR) methods are applied to oil reservoirs that have been depleted naturally. In more recent years, IOR techniques are applied to reservoirs even before their natural energy drive is exhausted by primary depletion. Descriptive screening criteria for IOR methods are used to select the appropriate recovery technique according to the fluid and rock properties. This methodology helps in assessing the most suitable recovery process for field deployment of a candidate reservoir. However, the already published screening guidelines neither provide information about the expected reservoir performance nor suggest a set of project design parameters, which can be used towards the optimization of the process. In this study, artificial neural networks (ANN) are used to build a high-performance neuro-simulation tool for screening different improved oil recovery techniques: miscible injection (CO2 and N2), waterflooding and steam injection processes. The simulation tool consists of proxy models that implement a multilayer cascade feedforward back propagation network algorithm. The tool is intended to narrow the ranges of possible scenarios to be modeled using conventional simulation, reducing the extensive time and energy spent in dynamic reservoir modeling. A commercial reservoir simulator is used to generate the data to train and validate the artificial neural networks. The proxy models are built considering four different well patterns with different well operating conditions as the field design parameters. Different expert systems are developed for each well pattern. The screening networks predict oil production rate and cumulative oil production profiles for a given set of rock and fluid properties, and design parameters. The results of this study show that the networks are

  8. The effect of deformation on two-phase flow through proppant-packed fractured shale samples: A micro-scale experimental investigation

    Science.gov (United States)

    Arshadi, Maziar; Zolfaghari, Arsalan; Piri, Mohammad; Al-Muntasheri, Ghaithan A.; Sayed, Mohammed

    2017-07-01

    then entrained by the flow and partially blocked pore-throat connections within the proppant pack. Deformation of proppant packs resulted in significant changes in waterflood residual oil saturation. In-situ contact angles measured using micro-CT images showed that proppant grains had experienced a drastic alteration of wettability (from strong water-wet to weakly oil-wet) after the medium had been subjected to flow of oil and brine for multiple weeks. Nanometer resolution SEM images captured nano-fractures induced in the shale surfaces during the experiments with mono-layer proppant packing. These fractures improved the effective permeability of the medium and shale/fracture interactions.

  9. APPLIED PHYTO-REMEDIATION TECHNIQUES USING HALOPHYTES FOR OIL AND BRINE SPILL SCARS

    Energy Technology Data Exchange (ETDEWEB)

    M.L. Korphage; Bruce G. Langhus; Scott Campbell

    2003-03-01

    Produced salt water from historical oil and gas production was often managed with inadequate care and unfortunate consequences. In Kansas, the production practices in the 1930's and 1940's--before statewide anti-pollution laws--were such that fluids were often produced to surface impoundments where the oil would segregate from the salt water. The oil was pumped off the pits and the salt water was able to infiltrate into the subsurface soil zones and underlying bedrock. Over the years, oil producing practices were changed so that segregation of fluids was accomplished in steel tanks and salt water was isolated from the natural environment. But before that could happen, significant areas of the state were scarred by salt water. These areas are now in need of economical remediation. Remediation of salt scarred land can be facilitated with soil amendments, land management, and selection of appropriate salt tolerant plants. Current research on the salt scars around the old Leon Waterflood, in Butler County, Kansas show the relative efficiency of remediation options. Based upon these research findings, it is possible to recommend cost efficient remediation techniques for slight, medium, and heavy salt water damaged soil. Slight salt damage includes soils with Electrical Conductivity (EC) values of 4.0 mS/cm or less. Operators can treat these soils with sufficient amounts of gypsum, install irrigation systems, and till the soil. Appropriate plants can be introduced via transplants or seeded. Medium salt damage includes soils with EC values between 4.0 and 16 mS/cm. Operators will add amendments of gypsum, till the soil, and arrange for irrigation. Some particularly salt tolerant plants can be added but most planting ought to be reserved until the second season of remediation. Severe salt damage includes soil with EC values in excess of 16 mS/cm. Operators will add at least part of the gypsum required, till the soil, and arrange for irrigation. The following

  10. 姬黄37区提高单井产量对策研究

    Institute of Scientific and Technical Information of China (English)

    李娅; 谭成仟; 马世东; 周小平; 郭京哲

    2012-01-01

    姬黄37区长6油藏属于低孔、低渗、低产的油藏,针对其开发过程中出现的含水上升快、高含水油井增多、单井产量递减严重的情况,从地质、开发两方面分析产生的原因有储层物性差、非均质性强、注水时机不当、单砂层注采关系不完善、个别井区注入水单向突进严重及地层堵塞等,对此提出针对性的治理措施有压裂改变渗流方式、超前注水增加地层能量、精细注水改善水驱、化学堵水治理裂缝、改善注水水质防止污染、化堵调剖进行解堵等,达到了降低产量递减的目的.措施井平均单井日增油达1.35 t.%By analyzing the geology and development status of Chang-6 reservoir in Jihuang 37 area, it is held that the causes leading to the high rising rate of water cut,the increase of high water-cut wells and high decline rate of single-well production of the low-porosity, low-permeability and low-production reservoir include poor reservoir property, serious heterogeneity, improper water injection timing , not perfect single sand layer injection-production relationship, serious injection water breakthrough in some well blocks, formation plugging,etc. For these reason,a series of countenneasures are put forward,including hydraulic fracturing for changing seepage manner, advanced water injection for increasing formation energy,fine water injection for improving waterflooding effect,chemical plugging for controlling formation fractures, improving injected water quality for preventing formation pollution, chemical profile control for formation plugging removal,etc. The application of the measures has a certain effect; the single well production is increased by 1. 35 t/d.

  11. 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

  12. Bio-Engineering High Performance Microbial Strains for MEOR

    Energy Technology Data Exchange (ETDEWEB)

    Xiangdong Fang; Qinghong Wang; Patrick Shuler

    2007-12-30

    substrates gave different performance. Those rhamnolipids with plant oil as substrate showed as low an IFT as 0.05mN/m in the buffer solution with pH5.0 and 2% NaCl. Core flooding tests showed that rhamnolipids produced by our engineered bacteria are effective agents for EOR. At 250ppm rhamnolipid concentration from P. aeruginosa PEER02, 42% of the remaining oil after waterflood was recovered. These results were therefore significant towards considering the exploration of the studied rhamnolipids as EOR agents.

  13. Advanced reservoir characterization and evaluation of CO{sub 2} gravity drainage in the naturally fractured Spraberry Trend Area. Annual report, September 1, 1996--August 31, 1997

    Energy Technology Data Exchange (ETDEWEB)

    Schechter, D.S.

    1998-07-01

    The overall goal of this project is to assess the economic feasibility of CO{sub 2} flooding the naturally fractured Spraberry Trend Area in West Texas. This objective is being accomplished by conducting research in four areas: (1) extensive characterization of the reservoirs, (2) experimental studies of crude oil/brine/rock (COBR) interaction in the reservoirs, (3) reservoir performance analysis, and (4) experimental investigations on CO{sub 2} gravity drainage in Spraberry whole cores. This report provides results of the second year of the five-year project for each of the four areas. In the first area, the author has completed the reservoir characterization, which includes matrix description and detection (from core-log integration) and fracture characterization. This information is found in Section 1. In the second area, the author has completed extensive inhibition experiments that strongly indicate that the weakly water-wet behavior of the reservoir rock may be responsible for poor waterflood response observed in many Spraberry fields. In the third area, the author has made significant progress in analytical and numerical simulation of performance in Spraberry reservoirs as seen in Section 3. In the fourth area, the author has completed several suites of CO{sub 2} gravity drainage in Spraberry and Berea whole cores at reservoir conditions and reported in Section 4. The results of these experiments have been useful in developing a model for free-fall gravity drainage and have validated the premise that CO{sub 2} will recover oil from tight, unconfined Spraberry matrix. The final three years of this project involves implementation of the CO{sub 2} pilot. Up to twelve new wells are planned in the pilot area; water injection wells to contain the CO{sub 2}, three production wells to monitor performance of CO{sub 2}, CO{sub 2} injection wells including one horizontal injection well and logging observation wells to monitor CO{sub 2} flood fronts. Results of drilling

  14. Design and Application of Box in Box in Oilfield Industry%浮筑隔声房在油田工业场所的设计与应用

    Institute of Scientific and Technical Information of China (English)

    王熙伟; 于晓蕾

    2013-01-01

      浮筑隔声房通常应用于对背景噪声要求较严格的技术用房,如消声室、广播录音室、琴房等.选择某油田注水泵房值班室为例,通过噪声实测及频谱分析,设计出浮筑隔声房的降噪方案.对浮筑隔声房的声学结构,如浮筑地板、隔声墙体、吸隔声吊顶、隔声门窗等,进行了系统的阐述.通过采用浮筑隔声房的技术措施,室内声压级由53.1 dB(A)降至38.7 dB(A),中低频声压级得到有效控制,达到降噪标准.同时,对降噪设计、房屋结构及功能工艺的有机结合,浮筑隔声房成功地应用到值班室改造中,取得良好的降噪效果,可为此类工业场所的降噪设计提供参考和借鉴.%The rooms which require lower background noise, such as anechoic room, recording room, piano room and so on, usually use box-in-box structure. However, this structure is rarely used in oilfield industrial sites. Taking the duty room of the water-flooding pump station of an oilfield as an example, the denoising plan of the box-in-box structure was worked out through noise measurement and frequency analysis. The acoustic components of the box-in-box structures, such as floating concrete slab, sound insulating wall, absorbing and sound insulating ceiling, sound insulation doors and windows and so on, were introduced systematically. After adopting the technical means for the structure, the sound pressure level has been reduced to 38.7 dB(A) from 53.1 dB(A) and the medium and low frequency noise was controlled effectively. Combining the denoising design with building structure and function process, the box-in-box structure was applied to the duty room reformation successfully. This work provides a reference for denoising design of similar engineering structures.

  15. Application of Wireless Intelligent Separate Layer Injection Technology in Toothbrush-shape Reservoir%无线智能分注技术在牙刷状油藏上的应用∗

    Institute of Scientific and Technical Information of China (English)

    雷创; 马永忠; 安淑凯; 王桂林; 郭栋; 李小永

    2016-01-01

    为提高牙刷状油藏的分注效果,应用了无线智能分注技术。该技术通过采集存储井下分层流量和压力等数据,测试资料准确性高。根据需要设定时间自动验封测调,下井前配水器设定打开时间,坐封安装井口后即可注水,无需单独下电缆开水嘴,同时应用无线通信功能,提高了测试成功率和分注合格率。在4口注水井上进行了现场试验,措施后4口井均正常投注,测试成功率100%,分注合格率100%,对应9口油井中7口油井见效,当年累计增油2658 t。无线智能分注技术对于同类型牙刷状油藏的分层注水开发具有很好的增产效果。%To improve the water injection performance of the toothbrush⁃shaped reservoir, wireless intelligent separate layer water injection technology has been taken to acquire and store each layer’ s flow and pressure data, thus results in high⁃accuracy test data. Seal test, testing and adjustment could be automatically done according to the pre⁃set time. Water regulator opening time is set before run⁃in⁃hole. Water injection could begin once the packer is set and the wellhead is installed, eliminating the need of run⁃in cable to open the water nozzle. The application of wireless communication improves the success rate of testing and separate layer water injection. In field application, four water injection wells were all normally put into injection with the testing success rate of 100% and the separate layer water injection pass rate of 100%. 7 wells of the 9 corresponding wells have been observed enhanced oil recov⁃ery with cumulative oil of 2 658 t. Wireless intelligent separate layer water injection technology has a good effect for the separate layer waterflooding development of similar type of toothbrush⁃shape reservoir.

  16. Visualization and Imaging of Crude Oil Mobilization on the Pore Network Scale by Low Salinity Flooding

    Science.gov (United States)

    Bartels, W. B.; Rucker, M.; Mahani, H.; Berg, S.; Hassanizadeh, S. M.

    2016-12-01

    Conventional oil recovery techniques leave about 60-70% of the original oil in place in reservoirs. To improve efficiency, enhanced or improved oil recovery (EOR/IOR) techniques are employed. The principle of all EOR/IOR techniques is the (re)formation of an oil bank with reduced trapping probability and/or increased connectivity of the oil phase compared to conventional water flooding. One of these techniques is low salinity waterflooding (LSF) where the injected brine is of reduced salinity and/or modified ionic composition. Research covering LSF predominantly discusses Darcy scale experiments and incremental recovery on the one hand and pore scale experiments looking at wettability alteration in model systems on the other. Attempts have been made on finding correlations between properties of the crude oil-brine-rock (COBR) system and incremental recovery. However, predictive capability of both the occurrence and magnitude of the low salinity effect (LSE) has not been achieved. Therefore, we suggest a different approach where we study the length scale in between the pore and Darcy scale at which the actual transport of crude oil occurs. More specifically, we study prerequisites deemed important for the occurrence of the LSE and try to define relevant physics. Relevance is defined here as physics that potentially contributes to oil bank formation, which is a necessary requirement if any (additional) oil is to be recovered. In this work we use micro-models and micro-CT technique to study this length scale. We will show how microscopy in combination with micro-models, and micro-CT in combination with COBR systems provide insight in the relevant length-scale consistent physics for LSF. We show that the presence of clay and the initial wettability state seem to have little influence on the occurrence of the LSE whereas the presence of crude oil is required. This leads us to believe that it is necessary to have charged surfaces (solid and crude oil) present for the LSE

  17. Dimensionless groups for three-phase gravity drainage flow in porous media

    Energy Technology Data Exchange (ETDEWEB)

    Grattoni, C.A.; Jing, X.D. [T.H. Huxley School, Imperial College, Prince Consort Road, SW7 2AZ London (United Kingdom); Dawe, R.A. [Chemical Engineering Department, University of West Indies, St. Augustine (Trinidad and Tobago)

    2001-01-01

    The downward displacement of oil by gas (either through gas cap expansion or by gas injection) at the crest of the reservoir is an attractive method of oil recovery. The drainage of oil under gravity forces is a potentially efficient method as it can reduce the remaining oil saturation to below that obtained after waterflooding. This paper describes a series of experiments of gas invasion under gravity-dominated conditions with special attention to the effects of wettability and water saturation on three-phase flow. The experiments were performed in bead-pack models by spontaneous gas invasion at both low and high water saturations with a spreading oil. Different oil recovery rates were observed depending on the wettability of the beads and initial water saturation. At irreducible water saturation, the process appeared to be less efficient for the oil-wet conditions, while similar oil recoveries are observed for both oil-wet and water-wet media at residual oil saturation. Different recovery rates occur with different fluid morphology, which depend on the matrix wettability and the balance between gravity, viscous and capillary forces. The results have been analysed using dimensionless groups. The Bond (N{sub B}) and capillary numbers (N{sub C}) were modified to include the 3-phase effects of gas, oil and water. However, for these cases the Bond and capillary numbers alone were insufficient to fully describe the dynamics of oil recovery by gravity drainage. Therefore, a new dimensionless group combining the effects of gravity and viscous forces to capillary forces was defined as: N=N{sub B}+A({mu}{sub d}/{mu}{sub g})N{sub C}, where A is a scaling factor (in all our experiments A=-17225) and ({mu}{sub d}/{mu}{sub g}) is the viscosity ratio between the displaced and displacing phase. A linear relationship was found between this new group and the total recovery for all the scenarios tested. The slope was approximately 40 for three cases, i.e., water-wet case at

  18. Study on Interpretation Method of Magnetism-stress Log Data%磁测应力资料的测井解释方法研究

    Institute of Scientific and Technical Information of China (English)

    王忠义; 李自平; 杨雪冰; 马文中; 周志彬; 齐向阳

    2012-01-01

    磁测应力方法是一种可以直接测得钢套管内壁应力分布的新技术.磁测应力信息能够解释套损危险程度和水驱力的方向;套损危险程度与应力检测仪器的信号幅度和发生信号异常的极板数量成正比;应力信号的极性代表套管被挤压或拉伸方向,应力值与信号幅度成正比;由6个极板测量的数据信息构成的平面矢量图对解释分析套管受力方向及其相对大小具有实际意义.根据工程需要提出了视应力值的概念,应当从理论和实验2个方面探索磁测应力仪器的刻度方法,这对该项技术发展完善很重要.%Magnetism-stress logging is a new technology which can directly measure stress-distribution of steel casing. The log data can be used to estimate degree of casing damages and direction of waterflood pressure. The degree of casing damage is in direct proportion to the signal amplitude of the MST- Ⅱ casing stress detector and numbers of polar plates with abnormal signals. The polarity of the stress signal indicates the extruded or stretched direction of the casings. The stress value is directy proportional to the signal amplitude. The plane vector chart with 6 polar plate measuring data may be used to interprete the degree of the casing damages. Imaging processing of the magnetism-stress logs is a new trend. Calibration methods will be studied in theories and with experiments. A new concept of apparent stress is suggested here.

  19. Study on deep fluid diversion in Daqing Oilfield at high water-cut stage%大庆油田高含水期深部液流转向试验研究

    Institute of Scientific and Technical Information of China (English)

    李承龙; 吴文祥

    2015-01-01

    At present,Daqing Oilfield has entered the extra high water-cut stage.With the increasing recovery percent of reserve,the effect of waterflooding becomes worse and worse because of high scattered remaining oil distribution,more watered-out wells,and serious interlay interference.Now,the conventional chemical conformance control technologies can not be used to plug deep parts in high permeability layer or large channel.Taking SⅡ1+2b formation in the western of Bei 3 block as an example,we studied the deep fluid diversion technology.A new technology for improving effect of wateflood-ing was proposed,which includes plugging water breakthrough channel and increasing the utilization of medium to low per-meability formations.The technology can provide a new way for further improving the development effect of water flooding oilfield at high water-cut stage.%大庆油田目前已进入特高含水期。随着区块采出程度的日益提高,剩余油高度分散,水淹普遍,层间矛盾较为突出,水驱效果变差。目前,常规的化学调剖方法还很不完善,不能够对高渗层或大孔道深部进行封堵。以北三区西部SⅡ1+2b层为例,对深部液流转向技术进行研究,并且提出封堵水窜通道,增加中低渗透层利用率,改善水驱效果的新技术,为高含水油田进一步改善水驱开发效果提供新的途径。

  20. Entraînement de globules d'huile par un tensio-actif. Etude de la formation du banc Mobilization of Oil Ganglia by a Surfactant Analysis of Bank Formation

    Directory of Open Access Journals (Sweden)

    Moulu J. C.

    2006-11-01

    Full Text Available Lors de l'injection d'une solution de tensio-actif dans un gisement déjà balayé par de l'eau, l'huile résiduelle, piégée sous la forme de globules discontinus, est remise en mouvement et se regroupe éventuellement sous la forme d'un banc d'huile. Le but de la présente étude est d'expliquer la formation de ce banc au cours d'un tel déplacement. Les résultats d'expériences réalisées en micromodèles de billes de verre permettent de constater que : - la récupération globale est corrélable avec le nombre capillaire Nc= uVdf/O, u et Vdf étant la viscosité et la vitesse de Darcy du fluide injecté, O la tension interfaciale avec l'huile en place ; - la vitesse des globules varie différemment avec u, Vdf, O et tend vers la même limite plus grande que la vitesse du fluide injecté pour de grandes valeurs du nombre capillaire Nc ; - le banc d'huile ne se forme que dans le cas où la vitesse des globules atteint celle du fluide injecté. L'huile déplacée reste alors groupée avec une saturation importante au niveau du front de tensio-actif. When a surfactant solution is injected into a reservoir previously waterflooded, the residual oil trapped as discontinuous ganglia is mobilized and eventually bunched together forming an oil bank. The aim of this study is to explain the formation of this bank during such a drive. The results of experiments performed in micromodels of glass beads show that: a Overall recovery can be correlated with the capillary number, Nc = uVfd/O, in which u and Vfd are the viscosity a and Darcy velocity of the injected fluid and O is the interfacial tension with the oil in place. b Ganglia velocity varies differently with u, Vfd and O, and it tends towards the same limit faster than the velocity of the injected fluid for high values of the capillary number Nc. c The oil bank is formed only in the case where globule velocity attaints that of injected fluid. the dispaced oil then remains bunched, with high

  1. Acute sedimentation response to rainfall following the explosive phase of the 2008-2009 eruption of Chaitén volcano, Chile

    Science.gov (United States)

    Pierson, Thomas C.; Major, Jon J.; Amigo, Álvaro; Moreno, Hugo

    2013-01-01

    The 10-day explosive phase at the start of the 2008–2009 eruption of Chaitén volcano in southern Chile (42.83°S, 72.65°W) blanketed the steep, rain-forest-cloaked, 77-km2 Chaitén River drainage basin with 3 to >100 cm of tephra; predominantly fine to extremely fine rhyolitic ash fell during the latter half of the explosive phase. Rain falling on this ash blanket within days of cessation of major explosive activity generated a hyperconcentrated-flow lahar, followed closely by a complex, multi-day, muddy flood (streamflow bordering on dilute hyperconcentrated flow). Sediment mobilized in this lahar-flood event filled the Chaitén River channel with up to 7 m of sediment, buried the town of Chaitén (10 km downstream of the volcano) in up to 3 m of sediment, and caused the lower 3 km of the channel to avulse through the town. Although neither the nature nor rate of the sedimentation response is unprecedented, they are unusual in several ways: (1) Nearly 70 percent of the aggradation (almost 5 m) in the 50–70-m-wide Chaitén River channel was caused by a lahar, triggered by an estimated 20 mm of rainfall over a span of about 24 h. An additional 2 m of aggradation occurred in the next 24–36 h. (2) Direct damage to the town was accomplished by the sediment-laden water-flood phase of the lahar-flood event, not the lahar phase. (3) The volume of sediment eroded from hillslopes and delivered to the Chaitén River channel was at least 3–8 × 106 m3—roughly 15–40 % of the minimum tephra volume that mantled the Chaitén River drainage basin. (4) The acute sedimentation response to rainfall appears to have been due to the thickness and fineness of the ash blanket (inhibiting infiltration of rain) and the steepness of the basin’s hillslopes. Other possible factors such as the prior formation of an ash crust, development of a hydrophobic surface layer, or large-scale destruction of rain-intercepting vegetation did not play a role.

  2. IEA GHG Weyburn CO{sub 2} monitoring and storage project : summary report 2000-2004

    Energy Technology Data Exchange (ETDEWEB)

    Wilson, M. (ed.) [Regina Univ., SK (Canada); Monea, M. (ed.) [Petroleum Technology Research Centre, Regina, SK (Canada); Whittaker, S. [Saskatchewan Industry and Resources, Regina, SK (Canada); White, D. [Geological Survey of Canada, Ottawa, ON (Canada); Law, D. [Alberta Research Council, Edmonton, AB (Canada); Chalaturnyk, R. [Alberta Univ., Edmonton, AB (Canada)

    2004-07-01

    The Weyburn CO{sub 2} Monitoring and Storage Project is a multi-million dollar Canadian research project launched in July 2000 to determine the feasibility of geological storage of carbon dioxide (CO{sub 2}) at EnCana's enhanced oil recovery project at its Weyburn Unit in Saskatchewan. This book reviews the operating status of the project and provides a new understanding of the geological storage of greenhouse gases, particularly carbon dioxide. The project aims to predict and verify the ability of an oil reservoir to securely and economically store CO{sub 2}. Various mechanisms for geological storage were examined along with the degree to which CO{sub 2} can be permanently stored in geological formations. The Weyburn field has been subjected to waterflooding since 1964 and extensive use of horizontal wells since 1991. The first phase of the CO{sub 2} enhanced oil recovery scheme began in September 2000 in 18 inverted 9-spot patterns. The flood will be expanded over the next 15 years to a total of 75 patterns. A total of 20 million tonnes of CO{sub 2} is expected to be injected into the reservoir over the life of the project. The CO{sub 2} is a purchased by-product from the Dakota Gasification Company's synthetic fuel plant in Beulah, North Dakota. The carbon dioxide is transported via a 320 km pipeline to Weyburn. The project has been monitored and evaluated since its launch. This study involved an assessment of geochemical reactions from the action of CO{sub 2} on reservoir rock and the impact that it might have on geomechanical integrity and CO{sub 2} sequestration. A geoscience model of the storage medium was developed to identify potential migration pathways for CO{sub 2}. Risk assessments were conducted to predict long-term fate of CO{sub 2} within the storage sites. An economic model was also developed to define the limits of economic storage during and after enhanced oil recovery operations. refs., tabs., figs.

  3. 基于非抽样提升小波包及奇异值分解的液阀故障诊断%Diagnosis of Liquid Valve Based on Undecimated Lifting Scheme Packet, and Singular Value Decomposition

    Institute of Scientific and Technical Information of China (English)

    陈敬龙; 张来斌; 段礼祥; 胡超

    2011-01-01

    Aiming at the extraction of failure character signal for liquid valve, a novel method to combine undecimated lifting scheme packet (ULSP) with singular value decomposition (SVD) is developed.Initial operators are calculated by using Lagrange interpolation formula after determining decomposition level and the lengths of initial operators, and then the original signal is decomposed by using undecimated algorithm.All frequency bands signals of the last layer are denoised by using SVD thresholding, a reasonable order for noise reduction is selected according to the singular entropy of singular spectrum.Then signal is reconstructed by using reconstruction algorithm, and the denoised signal is decomposed by using ULSP again in order to extract fault feature.Simulative signal and engineering results confirm the better noise reduction of ULSP-SVD.The weak fault signal of the spring on the drain valve of a reciprocating water-flood pump is extracted from the strong vibration background.%针对液阀故障微弱信号特征识别问题,提出一种结合非抽样提升小波包(Undecimated lifting scheme packet,ULSP)及奇异值分解(Singular value decomposition,SVD)的降噪方法.确定信号的分解层次及各层初始算子的长度后,通过拉格朗日插值公式算出初始算子,用非抽样算法对原始信号进行分解.对最后一层各频带信号进行奇异值分解降噪处理,根据奇异熵增量曲线确定降噪阶次.用非抽样提升小波包的重构算法对信号进行重构,最终获得降噪后的信号.对降噪后的信号再进行非抽样提升小波包分解,以提取故障特征.对仿真信号的降噪表明,所提方法降噪获得较高的信噪比及较低的均方差,且能保留信号中应有的高频成分.提出的方法成功提取某往复式注水泵排水阀弹簧失效的微弱故障特征.

  4. Study on EOR by carbon Dioxide Injection Process in R11 Carbonate Reservoir%任11碳酸盐岩油藏注CO2提高采收率研究

    Institute of Scientific and Technical Information of China (English)

    郭平; 周耐强; 张茂林; 张晓辉

    2012-01-01

    许多碳酸盐岩油藏进入高含水开发期,如何挖潜,进一步提高采收率是目前的主要工作方向.目前任11碳酸盐岩油藏存在单井产油量低,注入水利用系数低,水驱效率越来越差的问题.因此需要探索新途径,以便进一步发挥油藏生产潜力.分析了任11油藏注CO2提高采收率的机理,开展了任11油藏注CO2提高采收率的数值模拟研究.针对研究区块的地质及开发特点,建立了相应的三维数值模型,在水驱历史拟合的基础上,应用数值模拟技术从注气强度、注气方式、注气部位,生产气油比控制等方面进行了优化研究.油藏注CO2方案模拟计算20年,产油量显著上升,采用注CO2可比目前开发方式提高采收率3.5%左右.%Many carbonate reservoir have been into high water-cut development stage. How to dig the remaining oil potential and enhancing oil recovery further is dominant work target now. There are many problems in carbonate reservoir of Rl 1, such as low oil production of single well, inefficient utilization of injected water, and worsening of the water-flood efficiency. Therefore it is necessary to find a new way to dig reservoir production potential. The EOR mechanism by Carbon dioxide injection process in Rl 1 is analyzed and the numerical simulation research on EQR by Carbon dioxide injection process in Rl 1 reservoir is completed. Aimed at reservoir properties and development characteristic the three-dimensional numerical model is setup. Based on the fitting history of water flooding, the gas injection rate, gas injection mode, gas injection position and the gas-oil ratio control are optimized. The plan of Carbon dioxide injection is predicted for 20 years and the result shows that oil production rise obviously and it can enhance oil recovery about 3.5% more than the current exploitation mode.

  5. Numerical simulation of intelligent well feedback control production strategies%智能井反馈控制生产策略数值模拟

    Institute of Scientific and Technical Information of China (English)

    周峰; 刘均荣; 胡祥云

    2014-01-01

    在传统油藏数值模型基础上建立具有井下监测和控制功能模块的储层数值模型,提出一种智能井PrOactive和Reactive反馈控制算法。基于此模型和控制算法并以水平井生产为例,开展PrOactive控制、Reactive控制以及两者结合的混合式控制的生产策略研究。结果表明:相对传统井生产,基于Reactive和PrOactive的反馈控制策略可以减少产水量、增加产油量,提高净产值;PrOactive控制在生产前期优势较大,而Reactive控制在生产后期优势较为明显,两者结合的混合式生产控制策略优于单独的PrOactive和Reactive生产策略。%A numerical mOdel Of reservOir prOductiOn with the functiOnalities Of real-time mOnitOring and cOntrOl was estab-lished based On traditiOnal reservOir numerical mOdel and a set Of prOactive and reactive feedback cOntrOl algOrithms were prO-pOsed. Three intelligent well prOductiOn strategies ( i. e. , reactive cOntrOl, prOactive cOntrOl and the cOmbined cOntrOl) were investigated in a scenariO Of water-flOOding driven hOrizOntal prOductiOn wells. The results shOw that cOmpared with the cOn-ventiOnal well prOductiOn, the feedback cOntrOled prOductiOn strategies can increase Oil prOductiOn, decrease water prOduc-tiOn, and thus imprOve the net present value. The prOactive cOntrOl displays advantages in the early prOductiOn stage while the reactive cOntrOl OutperfOrms in the late stage, and the prOductiOn strategy with cOmbined reactive and prOactive cOntrOls has the mOst advantage in ecOnOmic return aspect.

  6. Coupling the Alkaline-Surfactant-Polymer Technology and the Gelation Technology to Maximize Oil Production

    Energy Technology Data Exchange (ETDEWEB)

    Malcolm Pitts; Jie Qi; Dan Wilson; Phil Dowling; David Stewart; Bill Jones

    2005-12-01

    Gelation technologies have been developed to provide more efficient vertical sweep efficiencies for flooding naturally fractured oil reservoirs or reservoirs with different sand lenses with high permeability contrast. The field proven alkaline-surfactant-polymer technology economically recovers 15% to 25% OOIP more crude oil than waterflooding froin swept pore space of an oil reservoir. However, alkaline-surfactant-polymer technology is not amenable to naturally fractured reservoirs or reservoirs with high permeability contrast zones because much of injected solution bypasses target pore space containing oil. This work investigates whether combining these two technologies could broaden applicability of alkaline-surfactant-polymer flooding into these reservoirs. Fluid-fluid interaction with different gel chemical compositions and alkaline-surfactant-polymer solution with pH values ranging from 9.2 to 12.9 have been tested. Aluminum-polyacrylamide gels are not stable to alkaline-surfactant-polymer solutions at any pH. Chromium-polyacrylamide gels with polymer to chromium ion ratios of 25 or greater were stable to alkaline-surfactant-polymer solutions if solution pH was 10.6 or less. When the polymer to chromium ion was 15 or less, chromium-polyacrylamide gels were stable to alkaline-surfactant-polymer solutions with pH values up to 12.9. Chromium-xanthan gum gels were stable to alkaline-surfactant-polymer solutions with pH values of 12.9 at the polymer to chromium ion ratios tested. Silicate-polyacrylamide, resorcinol-formaldehyde, and sulfomethylated resorcinol-formaldehyde gels were also stable to alkaline-surfactant-polymer solutions with pH values ranging from 9.2 to 12.9. Iron-polyacrylamide gels were immediately destroyed when contacted with any of the alkaline-surfactant-polymer solutions with pH values ranging from 9.2 to 12.9. Gel solutions under dynamic conditions of linear corefloods showed similar stability to alkaline-surfactant-polymer solutions as in

  7. Coupling the Alkaline-Surfactant-Polymer Technology and The Gelation Technology to Maximize Oil Production

    Energy Technology Data Exchange (ETDEWEB)

    Malcolm Pitts; Jie Qi; Dan Wilson; Phil Dowling; David Stewart; Bill Jones

    2005-12-01

    Gelation technologies have been developed to provide more efficient vertical sweep efficiencies for flooding naturally fractured oil reservoirs or reservoirs with different sand lenses with high permeability contrast. The field proven alkaline-surfactant-polymer technology economically recovers 15% to 25% OOIP more crude oil than waterflooding from swept pore space of an oil reservoir. However, alkaline-surfactant-polymer technology is not amenable to naturally fractured reservoirs or reservoirs with high permeability contrast zones because much of injected solution bypasses target pore space containing oil. This work investigates whether combining these two technologies could broaden applicability of alkaline-surfactant-polymer flooding into these reservoirs. Fluid-fluid interaction with different gel chemical compositions and alkaline-surfactant-polymer solution with pH values ranging from 9.2 to 12.9 have been tested. Aluminum-polyacrylamide gels are not stable to alkaline-surfactant-polymer solutions at any pH. Chromium-polyacrylamide gels with polymer to chromium ion ratios of 25 or greater were stable to alkaline-surfactant-polymer solutions if solution pH was 10.6 or less. When the polymer to chromium ion was 15 or less, chromium-polyacrylamide gels were stable to alkaline-surfactant-polymer solutions with pH values up to 12.9. Chromium-xanthan gum gels were stable to alkaline-surfactant-polymer solutions with pH values of 12.9 at the polymer to chromium ion ratios tested. Silicate-polyacrylamide, resorcinol-formaldehyde, and sulfomethylated resorcinol-formaldehyde gels were also stable to alkaline-surfactant-polymer solutions with pH values ranging from 9.2 to 12.9. Iron-polyacrylamide gels were immediately destroyed when contacted with any of the alkaline-surfactant-polymer solutions with pH values ranging from 9.2 to 12.9. Gel solutions under dynamic conditions of linear corefloods showed similar stability to alkaline-surfactant-polymer solutions as in

  8. Electric Power Generation from Low to Intermediate Temperature Resources

    Energy Technology Data Exchange (ETDEWEB)

    Gosnold, William D. [Univ. of North Dakota, Grand Forks, ND (United States)

    2015-06-18

    This project was designed to test the concept on the Eland-Lodgepole Field near Dickinson, North Dakota in the Williston Basin. The field is in secondary-recovery water-flood and consists of 12 producing oil wells, 5 water injection wells and one disposal well. Water production at the site averages approximately 320 gallons per minute (20.2 l s-1) and the temperature is 100 ⁰C. Engineers at Ormat estimated power production potential with the existing resource to be approximately 350 kWh. Unfortunately, ownership of the field was transferred from Encore, Inc., to Denbury, Inc., within the first week of the project. After two years of discussion and planning, Denbury decided not to pursue this project due to complications with the site location and its proximity to Patterson Lake. Attempts to find other partners operating in the Williston Basin were unsuccessful. Consequently, we were unable to pursue the primary objective of the project. However, during negations with Denbury and subsequent time spent contacting other potential partners, we focused on objectives 2 and 3 and developed a clear understanding of the potential for co-produced production in the Williston Basin and the best practices for developing similar projects. At least nine water bearing formations with temperatures greater than 90 ⁰C extend over areas of several 10s of km2. The total energy contained in the rock volume of those geothermal aquifers is 283.6 EJ (1 EJ = 1018 J). The total energy contained in the water volume, determined from porosities which range from 2 percent to 8 percent, is 6.8 EJ. The aquifers grouped by 10 ⁰C temperature bins (Table 1) include one or more formations due to the bowl-shape structure of the basin. Table 1. Summary of energy available in geothermal aquifers in the Williston Basin Analysis of overall fluid production from active wells, units, fields and formations in North Dakota showed that few sites co-produce sufficient fluid for significant power production

  9. 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

    The Preferred Upstream Management Practices (PUMP) project, a two-year study sponsored by the United States Department of Energy (USDOE), had three primary objectives: (1) the identification of problems, problematic issues, potential solutions and preferred practices related to oil production; (2) the creation of an Appalachian Regional Council to oversee and continue this investigation beyond the end of the project; and (3) the dissemination of investigative results to the widest possible audience, primarily by means of an interactive website. Investigation and identification of oil production problems and preferred management practices began with a Problem Identification Workshop in January of 2002. Three general issues were selected by participants for discussion: Data Management; Reservoir Engineering; and Drilling Practices. At the same meeting, the concept of the creation of an oversight organization to evaluate and disseminated preferred management practices (PMP's) after the end of the project was put forth and volunteers were solicited. In-depth interviews were arranged with oil producers to gain more insight into problems and potential solutions. Project members encountered considerable reticence on the part of interviewees when it came to revealing company-specific production problems or company-specific solutions. This was the case even though interviewees were assured that all responses would be held in confidence. Nevertheless, the following production issues were identified and ranked in order of decreasing importance: Water production including brine disposal; Management of production and business data; Oil field power costs; Paraffin accumulation; Production practices including cementing. An number of secondary issues were also noted: Problems associated with Enhanced Oil Recovery (EOR) and Waterflooding; Reservoir characterization; Employee availability, training, and safety; and Sale and Purchase problems. One item was mentioned both in

  10. Electric Power Generation from Low to Intermediate Temperature Resources

    Energy Technology Data Exchange (ETDEWEB)

    Gosnold, William D. [Univ. of North Dakota, Grand Forks, ND (United States)

    2015-06-18

    This project was designed to test the concept on the Eland-Lodgepole Field near Dickinson, North Dakota in the Williston Basin. The field is in secondary-recovery water-flood and consists of 12 producing oil wells, 5 water injection wells and one disposal well. Water production at the site averages approximately 320 gallons per minute (20.2 l s-1) and the temperature is 100 ⁰C. Engineers at Ormat estimated power production potential with the existing resource to be approximately 350 kWh. Unfortunately, ownership of the field was transferred from Encore, Inc., to Denbury, Inc., within the first week of the project. After two years of discussion and planning, Denbury decided not to pursue this project due to complications with the site location and its proximity to Patterson Lake. Attempts to find other partners operating in the Williston Basin were unsuccessful. Consequently, we were unable to pursue the primary objective of the project. However, during negations with Denbury and subsequent time spent contacting other potential partners, we focused on objectives 2 and 3 and developed a clear understanding of the potential for co-produced production in the Williston Basin and the best practices for developing similar projects. At least nine water bearing formations with temperatures greater than 90 ⁰C extend over areas of several 10s of km2. The total energy contained in the rock volume of those geothermal aquifers is 283.6 EJ (1 EJ = 1018 J). The total energy contained in the water volume, determined from porosities which range from 2 percent to 8 percent, is 6.8 EJ. The aquifers grouped by 10 ⁰C temperature bins (Table 1) include one or more formations due to the bowl-shape structure of the basin. Table 1. Summary of energy available in geothermal aquifers in the Williston Basin Analysis of overall fluid production from active wells, units, fields and formations in North Dakota showed that few sites co-produce sufficient fluid for significant power production

  11. MISTRALE: Soil moisture mapping service based on a UAV-embedded GNSS-Reflectometry sensor

    Science.gov (United States)

    Van de Vyvere, Laura; Desenfans, Olivier

    2016-04-01

    Around 70 percent of worldwide freshwater is used by agriculture. To be able to feed an additional 2 billion people by 2030, water demand is expected to increase tremendously in the next decades. Farmers are challenged to produce "more crop per drop". In order to optimize water resource management, it is crucial to improve soil moisture situation awareness, which implies both a better temporal and spatial resolution. To this end, the objective of the MISTRALE project (Monitoring soIl moiSture and waTeR-flooded Areas for agricuLture and Environment) is to provide UAV-based soil moisture maps that could complement satellite-based and field measurements. In addition to helping farmers make more efficient decisions about where and when to irrigate, MISTRALE moisture maps are an invaluable tool for risk management and damage evaluation, as they provide highly relevant information for wetland and flood-prone area monitoring. In order to measure soil water content, a prototype of a new sensor, called GNSS-Reflectometry (GNSS-R), is being developed in MISTRALE. This approach consists in comparing the direct signal, i.e. the signal travelling directly from satellite to receiver (in this case, embedded in the UAV), with its ground-reflected equivalent. Since soil dielectric properties vary with moisture content, the reflected signal's peak power is affected by soil moisture, unlike the direct one. In order to mitigate the effect of soil surface roughness on measurements, both left-hand and right-hand circular polarization reflected signals have to be recorded and processed. When it comes to soil moisture, using GNSS signals instead of traditional visible/NIR imagery has many advantages: it is operational under cloud cover, during the night, and also under vegetation (bushes, grass, trees). In addition, compared to microwaves, GNSS signal (which lies in L-band, between 1.4 and 1.8 GHz) is less influenced by variation on thermal background. GNSS frequencies are then ideal

  12. 高分辨率层序地层划分在陆相油藏剩余油分布研究中的应用——以克拉玛依油田一东区克拉玛依组为例%Application of high resolution sequence stratigraphy on remaining oil distribution of continental reservoirs: case of Karamay formation of east Karamay oilfield

    Institute of Scientific and Technical Information of China (English)

    刘岩; 丁晓琪; 李学伟

    2013-01-01

    Because China has some of the most water-flooded oilfield in world, stable oil production relies on controlling water injection and increasing oil recovery. The sandstone stacked styles, heterogeneity, geometry of reservoirs can be studied by high resolution sequence stratigraphy with a kind of new vision, which closely links remaining oil distribution and extends new method for studying remaining oil distribution. This paper studies base level changing laws of different cycles based on detailed research of sedimentary mi-cro-facies of Karamay formation, then the short base level cycles of Karamay formation can be divided into 2 main classes and 12 small classes. The middle base level cycles control the development of short base level cycles, so the Karamay formation can be divided into 3 middle cycles and 14 short cycles, then the isochronous stratigraphic framework are built. The short base level cycles which are located in the middle base level cycles have different remaining oil distribution in isochronous stratigraphic framework. The result shows that the detailed sedimentary work is the base for studying sequence stratigraphy. The reservoirs that are deposited in the high accommodation can have good isochronous and low intraformational heterogeneity, so, the remaining oil distribute in thin, small, nonproduc-ing or low degree of water flooded area. Meanwhile, the reservoir that is distributed in low accommodation can have poor isochronous and high intraformational heterogeneity, and which are composed of noncontemporaneous deposit, so, the remaining oil is distributed in low permeable reservoirs in form of lens.%克拉玛依油田经过半个世纪注水开发,已进入开发后期,提高采收率的关键是明确剩余油的分布规律.在对研究区克拉玛依组沉积相研究的基础上,分析了不同类型剖面结构代表的基准面变化规律,将该组的短期基准面旋回划分为2大类12个小类.短期基准面旋回的规律性变化

  13. Optimization of Multilayer Water Injection String for Two-step Horizontal Well%双台阶水平井分层注水管柱设计及优化

    Institute of Scientific and Technical Information of China (English)

    张立义; 黄新业; 王金龙; 田志宏; 郭长永; 焦吾达

    2016-01-01

    Several two⁃step horizontal water injection wells have been drilled to waterflood thin sand reservoirs in Tarim Oilfield, and all were operated with general water injection, which could not meet the requirements of multilayer water injection, resulting in serious water injection regulation problem�To address the issue, taking multilayer water injection in the Well × × 1 in Tarim Oilfield as objective, a multilayer water injection string and supporting tools for two⁃step horizontal well has been designed�The forces on the upper and lower packer under wa⁃ter injection in upper or lower layer have been calculated by using Wellcat�The telescoping tube length and packer shear pin have been optimized�The upper and lower telescopic tube should has telescopic length of 3 m and 1 m re⁃spectively�The upper and lower packer should have releasing force of 108 kN and 81 kN respectively�The devel⁃oped string could meet the multilayer water injection in the two⁃step horizontal wells under the injection rate of 200 m3/d and pressure of 25 MPa�The application results showed that the designed multilayer water injection string for two⁃step horizontal well is rational and could meet the requirements for multilayer water injection in two⁃step hori⁃zontal well with slickline operation for replacing nozzle.%塔里木油田双台阶水平井的分注工艺无法满足分层注水要求,区块欠注问题严重。为此,设计了双台阶水平井分层注水管柱及其配套工具,并采用Wellcat软件模拟计算出单独注停上层、注停下层时上、下封隔器的受力情况,对伸缩管长度和封隔器剪钉进行配比优化,即上伸缩管控制伸缩距3 m,下伸缩管控制伸缩距1 m,上封隔器解封力108 kN,下封隔器解封力81 kN,满足该区块双台阶水平井200 m3/d、25 MPa条件下的分层注水。实际应用结果表明,注水管柱及配套工具设计合理,配合钢丝投捞并更换水嘴

  14. Écoulement polyphasique dans un milieu poreux stratifié. Résultats expérimentaux et interprétation par la méthode de prise de moyenne à grande échelle Multiphase Flow in Stratified Porous Media Experimental Results and Interpretation by the Large-Scale Averaging Method

    Directory of Open Access Journals (Sweden)

    Bertin H.

    2006-11-01

    problem explained in the quasi-static case (capillary effects dominants. The second part of our work deals with the experimental study of the waterflooding of a stratified porous medium made of two regions with different physical characteristics. During the imbibition process the two-dimensional saturation fields were measured by absorption of a gamma-ray. The experimental results, evolution of the volume fraction in a section as a function of time, are compared to the results obtained by numerical simulation of the transport equations where the coefficients were calculated by the large-scale averaging method.

  15. Chemical Method to Improve CO{sub 2} Flooding Sweep Efficiency for Oil Recovery Using SPI-CO{sub 2} Gels

    Energy Technology Data Exchange (ETDEWEB)

    Burns, Lyle D.

    2009-04-14

    hydrocarbon combustion for energy, chemical and fertilizer plants. For example, coal fired power plants emit large amounts of CO{sub 2} in order to produce electrical energy. Carbon dioxide sequestration is gaining attention as concerns mount over possible global climate change caused by rising emissions of greenhouse gases. Removing the CO{sub 2} from the energy generation process would make these plants more environmentally friendly. In addition, CO{sub 2} flooding is an attractive means to enhance oil and natural gas recovery. Capture and use of the CO{sub 2} from these plants for recycling into CO{sub 2} flooding of marginal reservoirs provides a “dual use” opportunity prior to final CO{sub 2} sequestration in the depleted reservoir. Under the right pressure, temperature and oil composition conditions, CO{sub 2} can act as a solvent, cleaning oil trapped in the microscopic pores of the reservoir rock. This miscible process greatly increases the recovery of crude oil from a reservoir compared to recovery normally seen by waterflooding. An Enhanced Oil Recovery (EOR) project that uses an industrial source of CO{sub 2} that otherwise would be vented to the atmosphere has the added environmental benefit of sequestering the greenhouse gas.

  16. 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

    the oil displaced efficiency and oil saturation are weakened; polymer flooding technique can enhance the oil displaced efficiencies of the oil reservoirs with different physical properties, water flooding technique can enhance oil displaced efficiencies of the oil layers with high, middle and low permeabilites, but in extra-high permeability oil layer, there exists" futile cycle" and moreover the increasing tend of the permeability can be reduced; the method to enhance the displaced efficiency of waterflooded oil reservoir is to reduce the oil viscosity and increase the viscosity of water flooding solution, that is adding viscous chemical agents; the similar method for the polymer flooded oil reservoirs is to reduce the remained oil viscosity, increase the polymer-flooding solution viscosity and improve the physical properties of the oil reservoirs.

  17. CO2 Enhanced Oil Recovery from the Residual Zone - A Sustainable Vision for North Sea Oil Production

    Science.gov (United States)

    Stewart, Jamie; Haszeldine, Stuart; Wilkinson, Mark; Johnson, Gareth

    2014-05-01

    This paper presents a 'new vision for North Sea oil production' where previously unattainable residual oil can be produced with the injection of CO2 that has been captured at power stations or other large industrial emitters. Not only could this process produce incremental oil from a maturing basin, reducing imports, it also has the capability to store large volumes of CO2 which can offset the emissions of additional carbon produced. Around the world oil production from mature basins is in decline and production from UK oil fields peaked in 1998. Other basins around the world have a similar story. Although in the UK a number of tax regimes, such as 'brown field allowances' and 'new field allowances' have been put in place to re-encourage investment, it is recognised that the majority of large discoveries have already been made. However, as a nation our demand for oil remains high and in the last decade imports of crude oil have been steadily increasing. The UK is dependent on crude oil for transport and feedstock for chemical and plastics production. Combined with the necessity to provide energy security, there is a demand to re-assess the potential for CO2 Enhanced Oil Recovery (CO2-EOR) in the UK offshore. Residual oil zones (ROZ) exist where one of a number of natural conditions beyond normal capillary forces have caused the geometry of a field's oil column to be altered after filling [1]. When this re-structuring happens the primary interest to the hydrocarbon industry has in the past been in where the mobile oil has migrated to. However it is now considered that significant oil resource may exist in the residual zone play where the main oil column has been displaced. Saturations within this play are predominantly close to residual saturation (Sr) and would be similar to that of a water-flooded field [2]. Evidence from a number of hydrocarbon fairways shows that, under certain circumstances, these residual zones in US fields are comparable in thickness to the

  18. MAJOR OIL PLAYS IN UTAH AND VICINITY

    Energy Technology Data Exchange (ETDEWEB)

    Thomas C. Chidsey, Jr.

    2003-01-01

    Utah oil fields have produced a total of 1.2 billion barrels (191 million m{sup 3}). However, the 15 million barrels (2.4 million m{sup 3}) of production in 2000 was the lowest level in over 40 years and continued the steady decline that began in the mid-1980s. The Utah Geological Survey believes this trend can be reversed by providing play portfolios for the major oil producing provinces (Paradox Basin, Uinta Basin, and thrust belt) in Utah and adjacent areas in Colorado and Wyoming. Oil plays are geographic areas with petroleum potential caused by favorable combinations of source rock, migration paths, reservoir rock characteristics, and other factors. The play portfolios will include: descriptions and maps of the major oil plays by reservoir; production and reservoir data; case-study field evaluations; summaries of the state-of-the-art drilling, completion, and secondary/tertiary techniques for each play; locations of major oil pipelines; descriptions of reservoir outcrop analogs; and identification and discussion of land use constraints. All play maps, reports, databases, and so forth, produced for the project will be published in interactive, menu-driven digital (web-based and compact disc) and hard-copy formats. This report covers research activities for the first quarter of the first project year (July 1 through September 30, 2002). This work included producing general descriptions of Utah's major petroleum provinces, gathering field data, and analyzing best practices in the Utah Wyoming thrust belt. Major Utah oil reservoirs and/or source rocks are found in Devonian through Permian, Jurassic, Cretaceous, and Tertiary rocks. Stratigraphic traps include carbonate buildups and fluvial-deltaic pinchouts, and structural traps include basement-involved and detached faulted anticlines. Best practices used in Utah's oil fields consist of waterflood, carbon-dioxide flood, gas-injection, and horizontal drilling programs. Nitrogen injection and horizontal

  19. 亚临界蒸汽驱技术在低渗透油藏中的应用%Near-critical point steam-flooding technology application in low-permeability reservoir

    Institute of Scientific and Technical Information of China (English)

    吴永彬; 赵欣

    2011-01-01

    大庆朝阳沟低渗透油藏普遍存在启动压力高、高含蜡引起常规水驱开采冷伤害严重、注入能力差、产液水平低,天然裂缝及人工压裂裂缝广泛发育导致局部暴性水淹严重、水驱波及体积小等突出问题.为提高该油藏开发效果和采收率,采用室内机理实验与热采数值模拟相结合的方法,剖析水驱冷伤害、裂缝窜流机理及高压亚临界蒸汽驱降低启动压力梯度、熔蜡解堵、蒸馏等提高采收率机理;在精细地质建模及水驱生产动态历史拟合基础上,依据裂缝发育特征及剩余油分布特征,设计出适合该裂缝性低渗透油藏蒸汽驱的矢量井网,并优化出最佳汽驱参数.矿场3个井组试验结果表明,亚临界蒸汽驱可大幅提高水驱裂缝性低渗透油藏开发效果,转汽驱后平均产量是水驱的4倍,预期提高采收率10%以上.%According to problems such as deep cool damage, low capacity of injection and fluid production due to high start-up pressure and high wax content in the process of water-flooding, and serious flooded and low water sweep volume caused by widespread natural and artificial fractures in Chaoyanggou Daqing low-permeability oil field, in order to massively enhance the oil recovery factor so as to realize the high efficient development, approaches of in-house laboratory experiments, reservoir engineering analysis and numerical simulation are utilized to study the mechanisms of enhanced oil recovery by fracture steam-flooding and decreasing start-up pressure gradient, blocking remove by melting wax and distillation. Based on fined geological modeling and production dynamic history fitting, combining with fracture development characteristic and residual oil distribution, the injection capacity of the fluid with different characteristics, effect of fracture system on the sweep efficiency of steam, the optimum well pattern, well spacing and key parameters of injection and production in

  20. Reservoir Characterization of Bridgeport and Cypress Sandstones in Lawrence Field Illinois to Improve Petroleum Recovery by Alkaline-Surfactant-Polymer Flood

    Energy Technology Data Exchange (ETDEWEB)

    Seyler, Beverly; Grube, John; Huff, Bryan; Webb, Nathan; Damico, James; Blakley, Curt; Madhavan, Vineeth; Johanek, Philip; Frailey, Scott

    2012-12-21

    Within the Illinois Basin, most of the oilfields are mature and have been extensively waterflooded with water cuts that range up to 99% in many of the larger fields. In order to maximize production of significant remaining mobile oil from these fields, new recovery techniques need to be researched and applied. The purpose of this project was to conduct reservoir characterization studies supporting Alkaline-Surfactant-Polymer Floods in two distinct sandstone reservoirs in Lawrence Field, Lawrence County, Illinois. A project using alkaline-surfactantpolymer (ASP) has been established in the century old Lawrence Field in southeastern Illinois where original oil in place (OOIP) is estimated at over a billion barrels and 400 million barrels have been recovered leaving more than 600 million barrels as an EOR target. Radial core flood analysis using core from the field demonstrated recoveries greater than 20% of OOIP. While the lab results are likely optimistic to actual field performance, the ASP tests indicate that substantial reserves could be recovered even if the field results are 5 to 10% of OOIP. Reservoir characterization is a key factor in the success of any EOR application. Reservoirs within the Illinois Basin are frequently characterized as being highly compartmentalized resulting in multiple flow unit configurations. The research conducted on Lawrence Field focused on characteristics that define reservoir compartmentalization in order to delineate preferred target areas so that the chemical flood can be designed and implemented for the greatest recovery potential. Along with traditional facies mapping, core analyses and petrographic analyses, conceptual geological models were constructed and used to develop 3D geocellular models, a valuable tool for visualizing reservoir architecture and also a prerequisite for reservoir simulation modeling. Cores were described and potential permeability barriers were correlated using geophysical logs. Petrographic analyses

  1. Altering Reservoir Wettability to Improve Production from Single Wells

    Energy Technology Data Exchange (ETDEWEB)

    W. W. Weiss

    2006-09-30

    Many carbonate reservoirs are naturally fractured and typically produce less than 10% original oil in place during primary recovery. Spontaneous imbibition has proven an important mechanism for oil recovery from fractured reservoirs, which are usually weak waterflood candidates. In some situations, chemical stimulation can promote imbibition of water to alter the reservoir wettability toward water-wetness such that oil is produced at an economic rate from the rock matrix into fractures. In this project, cores and fluids from five reservoirs were used in laboratory tests: the San Andres formation (Fuhrman Masho and Eagle Creek fields) in the Permian Basin of Texas and New Mexico; and the Interlake, Stony Mountain, and Red River formations from the Cedar Creek Anticline in Montana and South Dakota. Solutions of nonionic, anionic, and amphoteric surfactants with formation water were used to promote waterwetness. Some Fuhrman Masho cores soaked in surfactant solution had improved oil recovery up to 38%. Most Eagle Creek cores did not respond to any of the tested surfactants. Some Cedar Creek anticline cores had good response to two anionic surfactants (CD 128 and A246L). The results indicate that cores with higher permeability responded better to the surfactants. The increased recovery is mainly ascribed to increased water-wetness. It is suspected that rock mineralogy is also an important factor. The laboratory work generated three field tests of the surfactant soak process in the West Fuhrman Masho San Andres Unit. The flawlessly designed tests included mechanical well clean out, installation of new pumps, and daily well tests before and after the treatments. Treatments were designed using artificial intelligence (AI) correlations developed from 23 previous surfactant soak treatments. The treatments were conducted during the last quarter of 2006. One of the wells produced a marginal volume of incremental oil through October. It is interesting to note that the field

  2. Etude fondamentale de l'imbibition dans un réservoir fissuré Basic Research on Inbibition in a Fractured Reservoir

    Directory of Open Access Journals (Sweden)

    Iffly R.

    2006-11-01

    Full Text Available L'efficacité du balayage d'un gisement fissuré par de l'eau d'injection dépend étroitement de l'importance et de la vitesse d'imbibition de l'eau par les blocs matriciels. De nombreuses expériences de laboratoire, réalisées sur des échantillons de roche et avec les fluides provenant d'un gisement exploité par Elf, ont permis de préciser l'influence, sur la récupération de l'huile, de la hauteur et de la perméabilité des blocs, ainsi que des conditions régnant à leurs limites (certaines fissures peuvent contenir, soit de l'eau, soit de l'huile, soit encore être étanches. Les résultats mettent en évidence le rôle essentiel des liaisons physico-chimiques entre l'eau de gisement, l'eau injectée, l'huile et la roche, à tout moment de l'imbibition. De légers écarts dans la composition lithologique de la roche peuvent modifier considérablement les lois de récupération. Par ailleurs, la présence dans les fluides de certaines molécules organiques peut influencer la récupération de l'huile beaucoup plus que ce que l'on pourrait attendre a priori des seules variations du terme a cos 6,. Comme ces liaisons physico-chimiques sont encore mal connues, donc non modélisables, il n'est en général pas légitime de procéder à des expériences d'imbibition avec des fluides et/ou des échantillons de roche ne provenant pas du gisement étudié. Dans ces conditions, les résultats de cette étude sont nécessairement spécifiques du champ considéré. Toutefois, les méthodes utilisées, l'analyse des résultats qui est faite, ainsi que l'influence des principaux paramètres sur ces résultats, présentent un degré de généralité évident. Les mesures de laboratoire, complétées par des simulations numériques, ont conduit à un ensemble cohérent de résultats permettant de comprendre le rôle respectif de la gravité, de la capillarité, des conditions aux limites et des effets d'extrémité, entre autres. Waterflood

  3. 油水井双向堵调控水挖潜技术室内研究%Experimental study on potential tapping treatments with bidirectional profile control and water shutoff in oil and water wells

    Institute of Scientific and Technical Information of China (English)

    吴柏志; 张宁; 苏伟明; 吕秀芹; 李宜强

    2012-01-01

    大庆油田老油层进入高含水期后,通常采用堵水调剖技术来改善注水开发效果.为优化堵调控水挖潜技术方案,利用三维非均质模型分别模拟油井堵水、水井调剖和双向堵调3种控水挖潜方式,研究不同调堵顺序、堵水半径对采收率的影响.结果表明:先调后堵和先堵后调的驱油效果基本一致,但先调后堵比先堵后调见效早;同时调堵的驱油效果优于先调后堵和先堵后调;同时调堵实验结果表明封堵半径越大,封堵效果越好,当封堵距离达到井距的1/10时,再增加堵水半径驱油效果增加不明显,所以推荐最佳堵水半径为井距1/20-1/10倍.%Profile control and water shutoff technology is used to improve the development effects of water-flooding in Daqing high water cut stage of early formations. In order to optimize the technical scheme of potential tapping treatments with profile control and water shutoff, three dimensional heterogeneous models is established to simulate the measures of water shutoff in oil wells, profile control in water wells and bidirectional water shutoff and profile control in oil & water wells. A series of laboratory physical simulation experiments are conducted to study the influence of water shutoff and profile control succession and block radius on the recovery. The results show that displacement effect is the essentially same with profile control first and water shutoff first, but profile control first is effective early; and the effect treated by bidirectional water shutoff and profile control is better than that of the other two measures with which the recovery rate is 2% higher than these two measures; meanwhile, the profile control experiment results show that the effect of blocking is better with the increasing of block radius, but when the plugging distance is more than 10% of well spacing, the oil displacement effect of plugging radius increase is not that obvious. So it is suggested that the

  4. Impacts on oil recovery from capillary pressure and capillary heterogeneities

    Energy Technology Data Exchange (ETDEWEB)

    Bognoe, Thomas

    2008-07-01

    phase bridges is observed. The water may pass the capillary discontinuity before inlet core is at endpoint for spontaneous imbibition. The observations of the water flood experiments have been validated using numerical simulators Eclipse and Sensor. Experimentally measured capillary pressure and relative permeability curves have been used to history match the observed production of the waterfloods. The observed variations in production mechanisms at wettability change are confirmed. Direct measurement of saturation methods for measuring capillary pressure scanning curves have been investigated and compared to conventional centrifuge techniques. The same trends are observed for curves measured at different wettabilities, and the capillary pressure curves measured using DMS methods have also been validated in numerical simulations of type Eclipse and Sensor. A feasibility study to develop a new method of measuring capillary pressure at various wettabilities has been performed with encouraging results. The conclusion is that the work should be further developed. The method has potential to enable capillary pressure measurements using live crude oil at reservoir conditions. All in all, several experimental methods applicable in future SCAL synthesis have been presented. The observations are consistent and underline the production mechanisms of fractured chalk reservoirs, and will serve as inspiration in the future evaluations of tertiary oil recovery processes. An innovative approach to the measurement of capillary pressure is suggested.

  5. Characteristics of NMR Water Displacing Oil and Influencing Factors in Extra-low Permeable Sandstones:Taking the Yanchang Group in Ordos Basin as an Example%特低渗透砂岩的核磁共振水驱油特征及其影响因素--以鄂尔多斯盆地延长组为例

    Institute of Scientific and Technical Information of China (English)

    2013-01-01

    Samples of Yanchang group in Ordos Basin were tested using the NMR technique before and after the water-looding experiments in order to analyze the characteristics of water displacing oil and to reveal the dominant factors for extra-low permeable sandstones. The results show that oil phase T2 patterns present double peaks in an irreducible water condition with crossing points at about 16.68 ms and movable oil parameters are sensitive to permeability. The right peak decreases to different extents after water-flooding; while the drop of left peak is related to the imbibition of capillary. If the imbibition of capillary can be utilized effectively, recovery can be enhanced. Average value of movable oil percentage is 57.62 and displacement efficiency is 37.33. There is about 20.29% movable oil that has not been flooded out and the development potential is still great after water displacing oil for extra-low permeable sandstones. Physical property, matching relationship of pore throat, degrees of microcrack development, occurrence forms of clay mineral are the main factors affecting displacement efficiency. Correlation between displacement efficiency and movable oil percentage confirms that movable oil percentage of NMR is the upper limit of displacement efficiency.%  为分析特低渗透砂岩的水驱油特征,揭示影响水驱油效果的主要因素,利用核磁共振技术对鄂尔多斯盆地延长组样品进行了水驱油前后的T2谱测试。结果表明,实验样品束缚水状态下的油相T2谱呈双峰形态,两峰之间的交点在16.68 ms左右,可动油参数对渗透率变化敏感;水驱油后T2谱右峰下降程度不同,左峰的下降与毛细管的自吸作用有关,发挥好毛细管的自吸作用,有助于提高采收率。38块样品的平均可动油百分数达到了57.62%,驱油效率为37.33%,还有约20.29%的可动油没有被驱出,水驱油后的开发潜力仍然较大。物性、孔喉匹配关系、

  6. 二连盆地阿南低渗透火山碎屑砂岩油藏储层特征及其对开发的影响%Reservoir characteristics of low-permeability pyroclastic sandstones and their influences on petroleum development in A'nan oilfield of Erlian Basin

    Institute of Scientific and Technical Information of China (English)

    梁官忠; 姜振学; 刘忠; 尹志军; 申保华; 马俊恒

    2013-01-01

    The reservoir rocks of A' nan sandstone oilfield are dominated by feldspar lithic sandstone, and are proximal subaqueous fan deposits with prominent influences of volcanic activity.They feature in high content of pyroclastic debris and tufaceous cements,low composition maturity and structure maturity.Although their burial depth is shallow, epidiagenesis such as compaction and cementation are intense, leading to the poor development of primary porosity.As the major secondary pores,the dissolution pores feature in micro-pore throat and poor sorting of pore throat, resulting in poor storage capacity and permeability.Therefore, A' nan oil reservoir is typical low permeable pyroclastic sandstone reservoir.The pore structure deteriorates during water flooding due to various factors such as water sensitivity and velocity sensitivity.As a result,the displacement-pressure increases, while water-free oil recovery and ultimate oil displacement efficiency decrease.During waterflooding, water injection pressure increases continuously, and pressure buildup is significant, but well deliverability is commonly low.Several measures such as layer-subdivision and infill drilling are carried out to improve oilfield development.%阿南砂岩油藏储集岩以长石岩屑砂岩为主,属近源快速沉积的水下扇砂体,且沉积时受火山活动影响明显.岩石中火山成因岩屑及凝灰质胶结物含量高,岩石成分成熟度和结构成熟度均较低,储集体具有埋藏浅但压实作用、胶结作用等成岩后生作用强烈的特点,导致油层原生孔隙不发育,主要发育次生溶孔.孔喉以微喉为主,吼道分选差、储渗能力较弱,油藏具有典型的低渗火山碎屑砂岩油藏特征.油藏注水开发后,由于水敏和速敏等因素的影响,孔隙结构进一步变差,油层驱替压力上升,无水采收率和最终驱油效率下降,油藏注水开发表现出注水压力不断上升、地层憋压现象明显但油井供液能力普

  7. 美国低产油井产量变化规律与中国提高单井产量的实践

    Institute of Scientific and Technical Information of China (English)

    胡文瑞; 何欣; 鲍敬伟; 张洋

    2014-01-01

    production of single well of low grade reservoirs,such as heav-y oil reservoirs and shallow-sea oil.(2 )The special control project for water-flooding development and secondary development of mature oilfields are implemented to raise the output of a high water cut well (3 )The production of single well in low perme-ability oilfields is increased though large-scale application of horizontal wells and a breakthrough in reservoir stimulation tech-nologies.

  8. 浅层稠油油藏CO2吞吐控水增油机理研究%Mechanism Study on Water Control and Enhanced Oil Recovery by CO2 Huff-puff for Shallow Heavy Oil Reservoir

    Institute of Scientific and Technical Information of China (English)

    孙雷; 庞辉; 孙扬; 侯大力; 潘毅

    2014-01-01

    To solve the problems of rapidly increase water cut and low oil recovery in the later water-flooding of low heavy oil and heavy oil reservoirs,we conducted laboratory physical simulation experiments and single well numerical simulation of CO2 huff and puff in water control and oil enhancement. To find out the mechanism and feasibility,CO2 and reservoir oil/water compatibility experiment and long core experiment of CO2 huff and puff are carried out respectively. The former has shown that CO2 has capacity expansion and viscosity reduction effects on the heavy oil. At a certain temperature,as the pressure decreases, the volume of reservoir water saturated with CO2 expands and the solubility of CO2 in reservoir water declines which indicates that in CO2 huff and puff,water is trapped by the small core thus causing Jamine Effect,and preventing the water from being produced. The long core experiment has also shown that CO2 huff and puff has a significant effect on controlling the water and enhancing the oil recovery. This has also been demonstrated by single well numerical simulation of CO2 huff and puff.%针对低稠油油藏和稠油油藏注水开发中后期含水上升快、原油采收率的低等问题,开展了CO2吞吐控水增油的室内物理模拟实验和单井CO2吞吐控水增油的数值模拟。为了研究CO2吞吐控水增油的机理及可行性,在室内分别开展了CO2与地层原油/地层水配伍性实验和CO2吞吐控水增油长岩芯实验。CO2与地层原油/地层水配伍性实验结果表明:CO2对原油有增容膨胀和降黏作用;一定温度下,随着压力的降低,饱和CO2的地层水的体积膨胀,CO2在地层水中的溶解度降低,CO2吞吐过程中,地层水遇到狭小孔隙受阻,产生贾敏效应,控制水的产出。长岩芯实验也表明,CO2吞吐有明显的控水增油的作用。单井CO2吞吐控水增油的数值模拟结果同样证实了CO2吞吐具有良好的控水增油显著。

  9. The Research of Profile Control Effect of New Chemical Profile Control Agent%新型化学调剖剂调剖效果研究

    Institute of Scientific and Technical Information of China (English)

    王威

    2011-01-01

    Since Sazhong oilfield has accessed the stage of high containing water,the distribution of subsoil water and oil are getting more and more complicated. On the effect of inherent formation heterogeneity and secondary heterogeneity caused by the development of many years, intrabed and intraformational contradiction prominent increasingly, it causes injection darting of high permeability zone and containing water raised speeds up. Producing condition of poor reservoir is bad, which makes waterflood efficiency, conformance factor and final recovery efficiency low,and the development effect is bad. The technology used in this text can solve the problem,this technology can provide a strong measure for excavating the remaining oil in high water-cut stage and raising the development effect. But the initial viscosity of shallow profile modification is high, the proportion entering purpose layer is relatively low, these cause the effective radius of profile control small, and term of validity is about one year, so some injection wells need to repeat shallow profile modification, connected oil well can not produce the desired result in a long period, and it influents and restricts the effect of shallow profile modification. So the main reasons affecting the term of validity of adjusting profile and solve it are need to research. New chemical shallow profile control agent is used to optimize laboratory experiments, and triturate the profile control agent that has low initial viscosity and assorted injection technology. It makes response stage up to two years, integral development effect gains improvement obviously.%萨中油田进入高含水期开发以来,地下油水分布状况日趋复杂,受地层固有的非均质性及多年开发造成次生非均质性加剧的影响,油层的层间、层内矛盾日渐突出,造成高渗透部位注水突进,油井含水上升加快.差油层动用状况较差,导致油田水驱效率和波及系数较低,最终采收率低,开发

  10. The Influence of Modified Injectant on Improvement of Percolation Ability in Super-low Permeability Reservoirs:Experimental Study and Application%改性注入剂对改善特低渗储层渗流能力的实验研究及应用

    Institute of Scientific and Technical Information of China (English)

    郑可; 徐怀民; 陈建文

    2013-01-01

    Based on indoor waterflooding results of 28 core samples from two super-low permeability reservoirs with different lithology of sandy gravels,fine siltstone and the results of conventional displacement experiment,and contrast test and immersion test using casting thin sections,the improvement of displacing phase permeability and displacement efficiency brought by modified injectant OR and DA in different rock samples was evaluated,the mechanism of percolation ability enhancement brought by modified injectant was analyzed,then the optimization of injection concentration of modified injectant was conducted and the better one went into field test.The study shows that OR is better suited with fine siltstone super-low permeability reservoirs,while DA is better suited with sandy gravels super-low permeability reservoirs.Both of them can improve the displacing phase permeability and displacement efficiency,while reduce oil-water interracial tension to some extent.The immersion test shows that both modified injectants can corrode the interstitial material filling the rock pores,and the reasonable injection concentration of modified injectant OR and DA are 3000mg/L and 2000mg/L respectively.While the field test shows that modified injectants can actually reduce water injection pressure by 2.76MPa on average,increase the daily water-injection rate by 4m3 and the water-injection situation is also improved.Both indoor experiments and field tests show good results.%在对砂质砾岩、细粉砂岩这2种不同岩性的典型特低渗储层共计28块岩心样品进行室内常规驱替实验、对比实验和铸体薄片浸泡实验的基础上,评价OR和DA这2种不同类型的改性注入剂对各岩样驱替相渗透率和驱油效率的改善情况,分析其改善渗流能力的机理,再对2类改性注入剂的注入浓度进行优选,最后进行现场试验.研究表明,改性注入剂OR在细粉砂岩类特低渗储层中适用性较好,改性注入剂DA在砂质砾

  11. Determination of Three-Phase Relative Permeabilities under Reservoir Conditions by Hot Water and Steamflood Experiments Détermination de perméabilités relatives tri-phasiques en conditions de réservoir, à partir d'expériences de balayages à l'eau chaude et à la vapeur

    Directory of Open Access Journals (Sweden)

    Quettier L.

    2006-11-01

    Full Text Available In order to help the physical and numerical interpretation of Emeraude's steam pilot, two-phase waterfloods at four temperatures (between 30 and 240°C and a steamflood were performed in the laboratory using the same porous medium (compacted silt and under reservoir conditions. Dynamic isothermal displacements were interpreted with a thermal simulator taking into account capillary end effects. The corresponding oil-water relative permeability curves were obtained by matching observed pressure drop and oil production. Results show that temperature influences the end-point saturations but not the shape of the curves. The steamflood experiment was carried out in an adiabatic core holder. Oil stripping and production of a large amount of CO2 caused by dissolution of carbonates were pointed out. The numerical interpretation of this experiment, by making use of the oil-water relative permeabilities, provided the three-phase oil relative permeability which is an essential datum for numerical interpretation of a steam drive pilot. Then a parameter study was used to quantify the influence of the different mechanisms involved in hot water and steam floods. Dans le but de faciliter l'interprétation physique et numérique du pilote vapeur d' Emeraude, des balayages eau-huile à quatre températures (entre 30 et 240°C et un balayage à la vapeur ont été réalisés au laboratoire. Toutes ces expériences ont été effectuées sur le même milieu poreux (silt compacté et en conditions de réservoir. Les déplacements bi-phasiques isothermes, en écoulement transitoire, ont été interprétés avec un modèle numérique thermique qui prend en compte les effets capillaires aux extrémités de l'échantillon. Les courbes de perméabilités relatives dynamiques eau-huile sont déterminées par calage, sur les courbes expérimentales, de la différence de pression et de la production d'huile simulées. Les résultats montrent que la température influe sur les

  12. POISON SPIDER FIELD CHEMICAL FLOOD PROJECT, WYOMING

    Energy Technology Data Exchange (ETDEWEB)

    Douglas Arnell; Malcolm Pitts; Jie Qi

    2004-11-01

    -rock compatibility, polymer injectivity, dynamic chemical retention by rock, and recommended injected polymer concentration. Average initial oil saturation was 0.796 Vp. Produced water injection recovered 53% OOIP leaving an average residual oil saturation of 0.375 Vp. Poison Spider rock was strongly water-wet with a mobility ratio for produced water displacing the 280 cp crude oil of 8.6. Core was not sensitive to either alkali or surfactant injection. Injectivity increased 60 to 80% with alkali plus surfactant injection. Low and medium molecular weight polyacrylamide polymers (Flopaam 3330S and Flopaam 3430S) dissolved in either an alkaline-surfactant solution or softened produced water injected and flowed through Poison Spider rock. Recommended injected polyacrylamide concentration is 2,100 mg/L for both polymers for a unit mobility ratio. Radial corefloods were performed to evaluate oil recovery efficiency of different chemical solutions. Waterflood oil recovery averaged 46.4 OOIP and alkaline-surfactant-polymer flood oil recovery averaged an additional 18.1% OIP for a total of 64.6% OOIP. Oil cut change due to injection of a 1.5 wt% Na{sub 2}CO{sub 3} plus 0.05 wt% Petrostep B-100 plus 0.05 wt% Stepantan AS1216 plus 2100 mg/L Flopaam 3430S was from 2% to a peak of 23.5%. Additional study might determine the impact on oil recovery of a lower polymer concentration. An alkaline-surfactant-polymer flood field implementation outline report was written.

  13. 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

  14. Possibilities of three-component geoacoustic logging at hydrocarbon deposits.

    Science.gov (United States)

    Trojanov, Alexandr; Astrakhantsev, Yurie; Nachapkin, Nikolay; Beloglasova, Nadejda; Bajenova, Evgenia; Vdovin, Alexey

    2013-04-01

    The geophysical method of oil-gas borehole investigation devised at the Institute of geophysics UB of RAS studies characteristics of geoacoustic emission (GAE) over the frequency range of 0.1÷5 kHz which displays peculiarities of fluid-gas dynamic processes in a volume of geological environment. More over: 1. The second displacement derivative (acceleration) of borehole walls' vibrations is recorded. 2. The three-component system of orthogonal transducers-accelerometers in a protecting casing of a borehole instrument with the diameter of 40-42 mm enabling to divide geoenvironment microvibrations into three directions is applied. 3. Frequency composition of recorded geoacoustic signals is analyzed. 4. Values of measured and calculated parameters representing distribution of signal amplitudes according to three components at four frequency bands are evaluated. Three-component geoacoustic logging at hydrocarbon deposits solves the following problems: · Estimation of fluid saturation character at a qualitative level; · Detection of fluid flow outside and inside the casing string with division into fluid types; · Detection of fluid flow position in chambers of a cement ring with division into fluid types; · Detection of non-sealed points of borehole equipment; · Location of gas-water, gas-oil ad water-oil contacts; · Study of inflow section in a perforated interval of casing string which determines the boundaries of efficient intervals; · Detection of sections with high absorption of drilling fluid in an open shaft; · Test for leaks of the column (together with thermometry); · Detection of intervals of fluid movement in horizontal direction outside a casing string within seams (it is impossible to determine them by other methods); · Detection of industrial deposits; · Revelation of water-flooded intervals of a hydrocarbon deposit. Transducers-accelerometers with relative coefficient of transverse conversion not more than 6% allow confident division of

  15. Evaluation of the Potential Application on the Wag Process in a North Sea Reservoir Evaluation de l'utilisation potentielle du procédé WAG dans un gisement de mer du Nord

    Directory of Open Access Journals (Sweden)

    Stensen J. A.

    2006-11-01

    Full Text Available The paper discusses the potential increase in oil recovery due to injection of water alternating gas (WAG. The WAG process is compared to waterflooding and gas injection. The mechanisms of the WAG process which makes the process interesting for a North Sea reservoir are discussed. The application of a WAG scheme is discussed with regard to the field restrictions and possibilities of Norwegian reservoirs. The WAG process is found to improve the oil recovery primarily due to improved vertical sweep efficiency. Cross-sectional models have been used to study the sensitivity to variations in vertical permeability. The paper also reports results of multi-phase displacement experiments using sequences of gas and water injections. The oil recovery by primary and secondary injection of both gas and water have been measured both on Berea sandstone cores and sandstone reservoir cores. The measurements include experiments at realistic reservoir conditions using reservoir fluids, and also series of experiments performed at reduced pressure and temperature utilising model fluids. Cette communication envisage l'accroissement potentiel de la récupération de pétrole par le procédé WAG d'injection alternée d'eau et de gaz. Le procédé WAG est comparé ici à l'injection de gaz et à l'injection d'eau. Les mécanismes qui rendent intéressant le procédé WAG pour un gisement de mer du Nord font l'objet d'une discussion. L'application du procédé WAG est envisagée en fonction des limitations et des possibilités des gisements norvégiens ; On constate que le procédé WAG améliore la récupération de pétrole, surtout du fait d'une meilleure efficacité verticale de balayage. Des modèles en coupe ont été utilisés pour étudier la sensibilité aux variations de la perméabilité verticale. Cette communication rapporte également les résultats d'expériences de déplacement multi-phases avec injections alternées d'eau et de gaz. La récupération de

  16. 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

  17. Improved Mobility Control for Carbon Dioxide (CO{sub 2}) Enhanced Oil Recovery Using Silica-Polymer-Initiator (SPI) Gels

    Energy Technology Data Exchange (ETDEWEB)

    Oglesby, Kenneth

    2014-01-31

    SPI gels are multi-component silicate based gels for improving (areal and vertical) conformance in oilfield enhanced recovery operations, including water-floods and carbon dioxide (CO{sub 2}) floods, as well as other applications. SPI mixtures are like-water when pumped, but form light up to very thick, paste-like gels in contact with CO{sub 2}. When formed they are 3 to 10 times stronger than any gelled polyacrylamide gel now available, however, they are not as strong as cement or epoxy, allowing them to be washed / jetted out of the wellbore without drilling. This DOE funded project allowed 8 SPI field treatments to be performed in 6 wells (5 injection wells and 1 production well) in 2 different fields with different operators, in 2 different basins (Gulf Coast and Permian) and in 2 different rock types (sandstone and dolomite). Field A was in a central Mississippi sandstone that injected CO{sub 2} as an immiscible process. Field B was in the west Texas San Andres dolomite formation with a mature water-alternating-gas miscible CO{sub 2} flood. Field A treatments are now over 1 year old while Field B treatments have only 4 months data available under variable WAG conditions. Both fields had other operational events and well work occurring before/ during / after the treatments making definitive evaluation difficult. Laboratory static beaker and dynamic sand pack tests were performed with Ottawa sand and both fields’ core material, brines and crude oils to improve SPI chemistry, optimize SPI formulations, ensure SPI mix compatibility with field rocks and fluids, optimize SPI treatment field treatment volumes and methods, and ensure that strong gels set in the reservoir. Field quality control procedures were designed and utilized. Pre-treatment well (surface) injectivities ranged from 0.39 to 7.9 MMCF/psi. The SPI treatment volumes ranged from 20.7 cubic meters (m{sup 3}, 5460 gallons/ 130 bbls) to 691 m{sup 3} (182,658 gallons/ 4349 bbls). Various size and types

  18. Dilute Surfactant Methods for Carbonate Formations

    Energy Technology Data Exchange (ETDEWEB)

    Kishore K. Mohanty

    2006-02-01

    There are many fractured carbonate reservoirs in US (and the world) with light oil. Waterflooding is effective in fractured reservoirs, if the formation is water-wet. Many fractured carbonate reservoirs, however, are mixed-wet and recoveries with conventional methods are low (less than 10%). The process of using dilute anionic surfactants in alkaline solutions has been investigated in this work for oil recovery from fractured oil-wet carbonate reservoirs both experimentally and numerically. This process is a surfactant-aided gravity drainage where surfactant diffuses into the matrix, lowers IFT and contact angle, which decrease capillary pressure and increase oil relative permeability enabling gravity to drain the oil up. Anionic surfactants have been identified which at dilute concentration of 0.05 wt% and optimal salinity can lower the interfacial tension and change the wettability of the calcite surface to intermediate/water-wet condition as well or better than the cationic surfactant DTAB with a West Texas crude oil. The force of adhesion in AFM of oil-wet regions changes after anionic surfactant treatment to values similar to those of water-wet regions. The AFM topography images showed that the oil-wetting material was removed from the surface by the anionic surfactant treatment. Adsorption studies indicate that the extent of adsorption for anionic surfactants on calcite minerals decreases with increase in pH and with decrease in salinity. Surfactant adsorption can be minimized in the presence of Na{sub 2}CO{sub 3}. Laboratory-scale surfactant brine imbibition experiments give high oil recovery (20-42% OOIP in 50 days; up to 60% in 200 days) for initially oil-wet cores through wettability alteration and IFT reduction. Small (<10%) initial gas saturation does not affect significantly the rate of oil recovery in the imbibition process, but larger gas saturation decreases the oil recovery rate. As the core permeability decreases, the rate of oil recovery reduces

  19. 对21世纪大庆油田开发前沿技术发展的初步思考%Preliminary Thinking on Leading Edge Technology Development of Daqing Oil Field in the 21st Century

    Institute of Scientific and Technical Information of China (English)

    巢华庆

    2001-01-01

    In the 21st century, Daqing oil field has to face new challenges mainly reflected in: (1)Unbalance in reserve-production ratio is tending to be serious after recovering cumulative productidon 70.32% of petroleum recoverable reserve; (2) Development difficulty increasing dramatically, with overall economic benefit getting poor;and (3) More strict requiements must be put forward in recognization and restructuring, due to the fact that market competition becomes more intense. From now on, the key work during development of Daqing oil field will be coverted from petroleum production rates to economic benefit, and overall targets will be coverted from continuous stable production to sustainable development, leading edge technology development in two levels will be accelerated. One level is about recent leading edge technology, focusing on increasing the employment percentage of and the total oil produced over the proved OOIP, which includes 3 sets of core techniques: (1)A complete set of techniques for improving waterflooding recovery factor at late high water cut stage; (2)Polymer flooding combined with ASP technique;and (3) Completion set of techniques for effective development of peripherial low permeability, low reserve richness and low single well productivity reservoirs. Another level is mainly about oil field long-term development requirements in the 21st century, focusing on new exploration and investigation in three directions: (1)Foam flooding, microbial flooding and other replacing new techniques after EOR; (2)Related techniques for effective development of newly incremental proved reserves in deep tight natural gas reservoir and complex fault-block oil and gas reservoirs;and (3)Related techniques required by market development for oil fields both at home and abroad. In the future, focus will be put on improving overall economic benefit of developing Daqing oil field through energetically developing and applying advanced hydrocarbon recovery techniques

  20. Research and Development Concerning Coalbed Natural Gas

    Energy Technology Data Exchange (ETDEWEB)

    William Ruckelshaus

    2008-09-30

    ) groundwater contamination of trace elements from CBNG disposal ponds; (4) use of environmental tracers in assessing water quality changes in ground and surface water systems; (5) development of a software toolbox to assess CBNG water treatment technologies; (6) potential value of CBNG water for enhanced oil recovery using low salinity waterflood; (7) evaluation of natural zeolites for low cost CBNG water treatment; (8) evaluation of aquatic toxicity testing methods required by regulatory agencies on some CBNG water discharges; (9) use of remote sensing to evaluate CBNG water discharges as habitat for West Nile Virus transmitting mosquitoes; and (10) a summary of lessons learned from historic CBNG management in Wyoming.

  1. 大庆地区地面变形对哈齐客专的影响研究%Study on Influence of Ground Deformation in Daqing Region on Harbin-Qiqihaer Passenger Dedicated Line

    Institute of Scientific and Technical Information of China (English)

    甄庆廷

    2013-01-01

    研究目的:哈尔滨至齐齐哈尔客运专线穿过的大庆油田由于高强度注水采油和工业、生活超量开采地下水,致使在油田采区及地下水下降漏斗区产生了不同程度的地面隆起和沉降变形,不均匀地面变形会对高速行驶的列车安全产生一定程度的影响,因此,查明和研究地面变形发生的范围、速率、变形量及对客运专线的影响程度,为设计采取必要的措施提供依据是非常必要的.研究结论:(1)为准确了解大庆地区地面变形规律,应建立地面变形动态监测系统,监测第四系沉降变形和白垩系隆起变形特征.(2)多采用化学驱油方式,控制注水压力,尽量保持压力场的平衡,并对靠近线路的采油井和注水井进行适当迁改.(3)在动态监测的基础上,建立地下水开采、采油注水、地面变形的耦合模型,预测地面变形发生、发展趋势,为铁路工程提供准确的预报预警.通过分析得出随着采油工艺的改进、地下水减采和动态监测系统的建立,大庆地区地面变形会得到有效控制和缓解,不会对哈齐客运专线工程造成较大影响.%Research purposes: The Harbin - Qiqihaer Passenger Dedicated Line passes through the Daqing oilfield in where the ground rises or settles in the oil extraction area and the underground water dropping area because of the high -pressure waterflooding for oil extraction and the over exploitation of groundwater for production and living. The uneven ground deformation maybe influences the safety of high -speed railway. Thus, it is necessary to find out and study the range, speed and deformation volume of the ground deformation and their influence on the passenger dedicated line for providing the reference to the railway design. Research conclusions: (1) For accurately knowing the regulation of the ground deformation of the Daqing area, the dynamic monitoring system for the ground deformation should be established to monitor

  2. Coupling the Alkaline-Surfactant-Polymer Technology and the Gelation Technology to Maximize Oil Production

    Energy Technology Data Exchange (ETDEWEB)

    Malcolm Pitts; Jie Qi; Dan Wilson; Phil Dowling; David Stewart; Bill Jones

    2005-12-01

    Gelation technologies have been developed to provide more efficient vertical sweep efficiencies for flooding naturally fractured oil reservoirs or reservoirs with different sand lenses with high permeability contrast. The field proven alkaline-surfactant-polymer technology economically recovers 15% to 25% OOIP more crude oil than waterflooding froin swept pore space of an oil reservoir. However, alkaline-surfactant-polymer technology is not amenable to naturally fractured reservoirs or reservoirs with high permeability contrast zones because much of injected solution bypasses target pore space containing oil. This work investigates whether combining these two technologies could broaden applicability of alkaline-surfactant-polymer flooding into these reservoirs. Fluid-fluid interaction with different gel chemical compositions and alkaline-surfactant-polymer solution with pH values ranging from 9.2 to 12.9 have been tested. Aluminum-polyacrylamide gels are not stable to alkaline-surfactant-polymer solutions at any pH. Chromium-polyacrylamide gels with polymer to chromium ion ratios of 25 or greater were stable to alkaline-surfactant-polymer solutions if solution pH was 10.6 or less. When the polymer to chromium ion was 15 or less, chromium-polyacrylamide gels were stable to alkaline-surfactant-polymer solutions with pH values up to 12.9. Chromium-xanthan gum gels were stable to alkaline-surfactant-polymer solutions with pH values of 12.9 at the polymer to chromium ion ratios tested. Silicate-polyacrylamide, resorcinol-formaldehyde, and sulfomethylated resorcinol-formaldehyde gels were also stable to alkaline-surfactant-polymer solutions with pH values ranging from 9.2 to 12.9. Iron-polyacrylamide gels were immediately destroyed when contacted with any of the alkaline-surfactant-polymer solutions with pH values ranging from 9.2 to 12.9. Gel solutions under dynamic conditions of linear corefloods showed similar stability to alkaline-surfactant-polymer solutions as in

  3. Coupling the Alkaline-Surfactant-Polymer Technology and The Gelation Technology to Maximize Oil Production

    Energy Technology Data Exchange (ETDEWEB)

    Malcolm Pitts; Jie Qi; Dan Wilson; Phil Dowling; David Stewart; Bill Jones

    2005-12-01

    Gelation technologies have been developed to provide more efficient vertical sweep efficiencies for flooding naturally fractured oil reservoirs or reservoirs with different sand lenses with high permeability contrast. The field proven alkaline-surfactant-polymer technology economically recovers 15% to 25% OOIP more crude oil than waterflooding from swept pore space of an oil reservoir. However, alkaline-surfactant-polymer technology is not amenable to naturally fractured reservoirs or reservoirs with high permeability contrast zones because much of injected solution bypasses target pore space containing oil. This work investigates whether combining these two technologies could broaden applicability of alkaline-surfactant-polymer flooding into these reservoirs. Fluid-fluid interaction with different gel chemical compositions and alkaline-surfactant-polymer solution with pH values ranging from 9.2 to 12.9 have been tested. Aluminum-polyacrylamide gels are not stable to alkaline-surfactant-polymer solutions at any pH. Chromium-polyacrylamide gels with polymer to chromium ion ratios of 25 or greater were stable to alkaline-surfactant-polymer solutions if solution pH was 10.6 or less. When the polymer to chromium ion was 15 or less, chromium-polyacrylamide gels were stable to alkaline-surfactant-polymer solutions with pH values up to 12.9. Chromium-xanthan gum gels were stable to alkaline-surfactant-polymer solutions with pH values of 12.9 at the polymer to chromium ion ratios tested. Silicate-polyacrylamide, resorcinol-formaldehyde, and sulfomethylated resorcinol-formaldehyde gels were also stable to alkaline-surfactant-polymer solutions with pH values ranging from 9.2 to 12.9. Iron-polyacrylamide gels were immediately destroyed when contacted with any of the alkaline-surfactant-polymer solutions with pH values ranging from 9.2 to 12.9. Gel solutions under dynamic conditions of linear corefloods showed similar stability to alkaline-surfactant-polymer solutions as in

  4. 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

  5. Axisymmetric Drainage in Hydrophobic Porous Media Micromodels Drainage en géométrie axisymétrique dans des milieux poreux hydrophobes à deux dimensions

    Directory of Open Access Journals (Sweden)

    Cuenca A.

    2013-01-01

    Full Text Available We present studies of axisymmetric drainage in two-dimensional micromodels of porous media using up to date microfabrication and image analysis methods. Drainage of model oil by aqueous solutions is studied at low capillary numbers (Ca typically encountered during oil recovery operations. We use two types of oil-wet micromodels: one is based on a deposition method for creating a random monolayer of micronic glass beads, while the other is made using computer generated random networks etched in glass using wet-lithography. Both models have a central injection scheme and a radial geometry, resulting in a continuous variation of the capillary number during the course of drainage. We first carry out an analysis of experiments at global micromodel scale using computer based image analysis coupled with flow rates and pressure drop measurements. Basic relevant parameters such as permeability, porosity of the micromodel and residual oil in place after waterflooding are extracted. We then take advantage of the ease of observation in transparent micromodels to investigate the drainage phenomenon at local scale. Local saturation and front width are measured as a function of the local capillary number. Interestingly, because of the radial flow geometry, our experiments allow a continuous plotting of the micromodels capillary desaturation curve on several decades. As expected but never precisely observed, all points of various experiments collapse on a single capillary desaturation curve for a given micromodel. However, we observe dissimilar behaviors between the two types of micromodels. We discuss this phenomenon in light of the pore scale geometrical differences between the two models. Nous présentons une étude de phénomènes de drainage dans des micromodèles bidimensionnels de milieu poreux s’appuyant sur des méthodes modernes de microfabrication et d’analyse. Le drainage d’huile par des solutions aqueuses est étudié à de faibles nombres

  6. Evaluation and Enhancement of Carbon Dioxide Flooding Through Sweep Improvement

    Energy Technology Data Exchange (ETDEWEB)

    Hughes, Richard

    2009-09-30

    of where the CO{sub 2} went or is going and how recovery might be improved. New data was also generated in this process. Production logs were run to understand where the CO{sub 2} was entering the reservoir related to core and log information and also to corroborate the simulation model. A methodology was developed and successfully tested for evaluating saturations in a cased-hole environment. Finally an experimental and theoretical program was initiated to relate laboratory work to field scale design and analysis of operations. This work found that an understanding of vertical and areal heterogeneity is crucial for understanding sweep processes as well as understanding appropriate mitigation techniques to improve the sweep. Production and injection logs can provide some understanding of that heterogeneity when core data is not available. The cased-hole saturation logs developed in the project will also be an important part of the evaluation of vertical heterogeneity. Evaluation of injection well/production well connectivities through statistical or numerical techniques were found to be as successful in evaluating CO{sub 2} floods as they are for waterfloods. These are likely to be the lowest cost techniques to evaluate areal sweep. Full field simulation and 4D seismic techniques are other possibilities but were beyond the scope of the project. Detailed simulation studies of pattern areas proved insightful both for doing a “post-mortem” analysis of the pilot area as well as a late-term, active portion of the Little Creek Field. This work also evaluated options for improving sweep in the current flood as well as evaluating options that could have been successful at recovering more oil. That simulation study was successful due to the integration of a large amount of data supplied by the operator as well as collected through the course of the project. While most projects would not have the abundance of data that Little Creek had, integration of the available data

  7. 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

  8. Reservoir Characterization of Bridgeport and Cypress Sandstones in Lawrence Field Illinois to Improve Petroleum Recovery by Alkaline-Surfactant-Polymer Flood

    Energy Technology Data Exchange (ETDEWEB)

    Seyler, Beverly; Grube, John; Huff, Bryan; Webb, Nathan; Damico, James; Blakley, Curt; Madhavan, Vineeth; Johanek, Philip; Frailey, Scott

    2012-12-21

    Within the Illinois Basin, most of the oilfields are mature and have been extensively waterflooded with water cuts that range up to 99% in many of the larger fields. In order to maximize production of significant remaining mobile oil from these fields, new recovery techniques need to be researched and applied. The purpose of this project was to conduct reservoir characterization studies supporting Alkaline-Surfactant-Polymer Floods in two distinct sandstone reservoirs in Lawrence Field, Lawrence County, Illinois. A project using alkaline-surfactantpolymer (ASP) has been established in the century old Lawrence Field in southeastern Illinois where original oil in place (OOIP) is estimated at over a billion barrels and 400 million barrels have been recovered leaving more than 600 million barrels as an EOR target. Radial core flood analysis using core from the field demonstrated recoveries greater than 20% of OOIP. While the lab results are likely optimistic to actual field performance, the ASP tests indicate that substantial reserves could be recovered even if the field results are 5 to 10% of OOIP. Reservoir characterization is a key factor in the success of any EOR application. Reservoirs within the Illinois Basin are frequently characterized as being highly compartmentalized resulting in multiple flow unit configurations. The research conducted on Lawrence Field focused on characteristics that define reservoir compartmentalization in order to delineate preferred target areas so that the chemical flood can be designed and implemented for the greatest recovery potential. Along with traditional facies mapping, core analyses and petrographic analyses, conceptual geological models were constructed and used to develop 3D geocellular models, a valuable tool for visualizing reservoir architecture and also a prerequisite for reservoir simulation modeling. Cores were described and potential permeability barriers were correlated using geophysical logs. Petrographic analyses

  9. The Alkali/Surfactant/ Polymer Process: Effects of Slug Size, Core Length and a Chase Polymer Le procédé alkali/surfactant/polymère : effets de la taille du bouchon, de la longueur de la carotte et d'un polymère de déplacement

    Directory of Open Access Journals (Sweden)

    Green K. A.

    2006-11-01

    Full Text Available An experimental study was conducted to examine the effects of slug size, core length, and a chase polymer on the effectiveness of the alkali/surfactant/polymer (A/S/P process in recovering waterflood residual oil. Core flood experiments were conducted with unfired linear Berea sandstone cores. The tertiary oil recovery, oil cut, pressure drop, and chemical propagation were measured for each flood. Tertiary oil recovery significantly increased with the slug size up to 0. 5 of a pore volume. Increasing the slug size further resulted in a smaller incremental increase in oil recovery. A slight increase in tertiary oil recovery was obtained when small size A/S/P slugs were followed with achase polymer having a viscosity higher than the slug. The lack of oil recovery with small A/S/P slugs was due to the consumption and dilution of the injected chemicals, especially the synthetic surfactant, due to adsorption and dispersion. Increasing the core length by a factor of 4. 5 (from 9 to 40. 6 cm had no significant effect on tertiary oil recovery. Chemical propagation was found to be a function of core length (i. e. , core Peclet number and the size of the chase polymer slug. Increasing core length and employing a chase polymer maintained the integrity of the A/S/P slug by decreasing the effect of dispersion and minimizing the influence of viscous fingering at the tail of the A/S/P slug. Une étude expérimentale a été effectuée pour examiner les effets de la taille du bouchon, de la longueur de la carotte et de l'emploi d'un polymère de déplacement sur l'efficacité du procédé A/S/P (alkali/surfactant/polymère dans la récupération d'huile résiduelle par injection d'eau. Les expériences d'injection ont été faites avec des carottes rectilignes en grès de Berea vert. La récupération tertiaire du pétrole, la présence d'eau, la perte de charge et la propagation chimique ont été mesurées pour chaque injection. La récupération tertiaire du