Incremental Oil Production Research Articles

A multidisciplinary approach for chemical EOR screening: Understanding alkali-oil interaction by the use of petroleum geochemistry

Alkali-based chemical enhanced oil recovery is used to increase the incremental oil production and relies on the interaction of alkali lye with crude oil. Optimizing the chemical formulation depends on screening multiple alkali concentration ranges to maximize the generated emulsion volume. However, the strong chemical variation of the crude oil, caused by biodegradation within the reservoirs, and its influence on generating in-situ soaps has never been studied in detail. In this paper, organic geochemical oil characterization was combined with phase screening data. Thereby, differences in terms of initial crude oil composition (slightly degraded, moderate degraded, and heavy degraded oils), but also regarding the excess alkali-equilibrated oil phase, and the hydrocarbons which are included in the in-situ soap (emulsion phase) were worked out.Different alkalis, concentration ranges, and water-oil-ratios were studied, to understand the control mechanism for the in-situ soap generation. The formed emulsions were observed over time (emulsion stability) and classified into possible emulsion types. Alterations caused by the alkali-oil interaction were quantified by the use of organic geochemistry.The degree of biodegradation seems to be an important control mechanism. Slightly degraded oils do not interact with the alkali lye due to a high content of non-polar compounds such as alkanes and isoprenoids. Moderately and heavily degraded oils show varying interactions with the alkali solution. The degree of interaction depends on the used degradation type, the alkali type as well as on the used concentration. Moderately degraded oils interact in a lower concentration range compared to heavily degraded oils, which show an increased non-soap forming acid content. Phase experiments conducted over a long period of time (100 days) were used to determine which emulsion types (micro or macro) were formed. Stable micro emulsions were preferably generated over time in formulations prepared with potassium carbonate (K2CO3). In contrast, formulations containing sodium carbonate (Na2CO3) hardly did not generate stable micro emulsions.The composition of alkali-equilibrated oil differs from the initial oil composition and shows a strong dependency of the used alkali type. Potassium carbonate caused mild alterations of the moderately and heavily degraded oils, whereas the impact of sodium carbonate was more severe. In addition, dissolution of naphthalenes, steranes, hopanes, and parts of the generated in-situ soap into the aqueous phase, was observed during the performed phase experiments of the moderately degraded oils (at the elevated pH values).

An integrated technical-economic model for evaluating CO2 enhanced oil recovery development

Carbon dioxide enhanced oil recovery (EOR) has been proved to effectively reduce CO2 emissions by storing industrial CO2 underground while increasing oil production. An integrated assessment model was developed to evaluate the technical and economic performance of CO2-EOR based on data from more than 40 historical field projects. Unlike previous models, the model comprehensively assesses economic potential and greenhouse gases (GHG) emission of CO2-EOR together and is based on a large amount of field data. The technical model estimates incremental oil production based on CO2 injection. The model also estimates the net CO2 emissions by considering the emissions from oil production and CO2 utilization. The economic model simulated the net present value (NPV) of six scenarios under different design requirements. The breakeven oil price for small scale CO2 pipeline project was $46.4/barrel. The porosity, net pay, CO2 injection, depth, oil formation factor, and oil saturation are the critical parameters affecting the economic performance based on the sensitivity analysis. The breakeven price of carbon tax scenario was $64.10/barrel, of which CO2 injection and carbon tax contributed 52% of the NPV variations. The study provides operators, investors, and even policymakers the sufficient and important information to fully understand CO2-EOR developments with various external and internal parameters before making the right decisions.

A Review of Field Oil-Production Response of Injection-Well Gel Treatments

SummaryAs life-span extenders, bulk gels have been widely applied to rejuvenate oil production from uneconomic producers in mature oil fields by improving the sweep efficiency of improved-oil-recovery (IOR)/enhanced-oil-recovery (EOR) floods. This paper presents a comprehensive review of the responses of injection-well gel treatments implemented between 1985 and 2014. The survey includes 61 field projects compiled from SPE papers and US Department of Energy reports. Seven parameters related to the oil-production response were evaluated according to the reservoir lithology, formation type, and recovery process, using univariate analysis and stacked histograms. The interquartile-range (IQR) method was used to detect the underperforming and overperforming gel projects. Scatterplots were used to identify the effects of the injected-gel volume and the treatment timing on the treatment response. Pretreatment water cut, recovery factor, and flood life were used as indicators for the treatment timing.Results indicated that gel treatments have very wide ranges of response for injection and production wells and for oil and water rates and profiles. When successfully applied, they, on average, respond after 3.5 months, increase the oil-production rate by 32%, and additionally recover 116,000 STBO per treatment, 15 STBO per gel barrel, or 10 STBO per polymer pound. We identified that gel treatments perform more efficiently in carbonate (CB) than in sandstone (SS) reservoirs and in naturally fractured (NF) formations than in other formation types. In addition, the incremental oil production considerably increases with the channeling strength and the injected-gel volume for all formation types, not just for the matrix-rock (MR) reservoirs. Moreover, gel treatments applied in NF formations have lower productivities in SS than in CB reservoirs using normalized performance parameters.Declining trends were identified for all parameters of the oil-production response with the treatment-timing indicators. The sooner the gel treatment is applied, the faster the response, and the larger the incremental oil production and its rate. It is recommended to allow longer evaluation times for gel treatments applied in MR formations because their response times might extend to several months. Gel treatments will perform more efficiently if they are conducted at water cuts of less than 70%, flood lives of fewer than 20 years, or recovery factors of less than 35%. For different application environments, the present review provides reservoir engineers with updated ideas regarding the low, typical, and high performances of gel treatments when successfully applied, as well as how other treatment aspects affect performance.

PROSPECT FOR CO2 EOR TO OFFSET THE COST OF CCS AT COAL POWER PLANTS

Carbon Capture Storage (CCS) technology has gained confidence in its ability to yield dramatic reductions of CO2 emissions from large stationary emissions sources such as coal-fired power plants. However, the pace of CCS projects has suffered from a less supportive business case. Utilization of CO2 for enhanced oil recovery (CO2 EOR) offers commercial opportunities owing to its economic profitability from incremental oil production offsetting the cost of CCS. This paper describes the prospect of CO2 EOR offsetting the cost of CCS at a coal-fired power plant. A coal-firedpower plant assumed to be commissioned in 2022 is selected as the basis of this study. The Levelized Cost of Electricity (LCOE) of this plant without CCS is estimated at US$ 6.4 cents/kWh and emits around 4.1 MtCO2/year. Integrating CCS to the selected coal power plant imposed additional costs associated with CO2 capture, transportation, and storage systems. The incremental costs are evaluated based on separation of 90%, 45%, and 22.5% of CO2 from the power plant flue gas. Under the 90% capture scenario, the LCOE raised more than double to 15.5 US cents/kWh which is primarily attributed to the energy penalty. A minimal reduction of 0.9 cents/kWh could bring the LCOE down below the ceiling price for geothermal. Reducing the CO2 capture percentage from 90% to 45% could reduce the LCOE to 11.2 US cents/kWh. Lowering the cost to 0.6 cents/kWh or more for this case would result in the LCOE below the state-owned electricity companys average cost of combined cycle gas turbine in 2012. Selling the captured CO2 under US$ 10 per tonne at the plant gate could help offset the cost. With numbers of new coal-fired power plants expected to be constructed in the near term, integrated coal CCS power plant with EOR is relevant for Indonesia.

Effectiveness of In-Situ Microbial Enhanced Oil Recovery in a Post-Polymer Flooded Reservoir

This study investigated the effectiveness of In-situ microbial enhanced oil recovery (IMEOR) in a post-polymer flooded oil reservoir located in SaNan oilfield, Northeast China. Two rounds of injection of nutrient medium were intermittently injected into the producing block and then monitored. The main results showed that the dominant bacteria of 4 production wells, Thauera of Beta-proteobacteria, Pseudomonas and Acinetobacter of Gamma-proteobacteria were directional activation, which showed a consistent enhancement. The abundance of Methanosaeta and Methanolinea increased, and showed a regular alternation with an increase of oil production. It contributed to production of bio-gas, leading to increasing of the injection pressure from 11.3 MPa to 13.9 MPa before the experiment which increased by more than 2.0 MPa. The contents of CO2 and CH4 varied alternately, and the variation was consistent with the order of injection of each activator. H2 was detected in the reservoir associated with the gas in the observation area. A large amount of enriched bio-gas was dissolved into and mixed with crude oil, which brought increasing of the proportion of light components in the whole hydrocarbon of the recovered oil. The other effect was activated microbial metabolites productions formed bio-plugs, which benefits for improving of the absorption profile and the production profile. A total of 6,243 t of incremental oil production was achieved, and an oil recovery rate increased by 3.93% (OOIP) to the end of 2015. Our trial suggested that IMEOR can be implemented for effective enhancement of further oil recovery from polymer flooded oil reservoirs.

Simultaneous production of bioactive compounds for application in enhanced oil recovery

This research investigated the use of produced water (PW) and raw glycerine, waste products from the oil and biodiesel industry, respectively, as a growth medium and source of nutrients in a bioprocess employing Xanthomonas and Pseudomonas strains, in order to simultaneously produce xanthan gum and rhamnolipids, products already used in enhanced oil recovery (EOR) applications. The xanthan gum and rhamnolipid produced exhibited excellent viscosity and emulsifying activity characteristics, and better pseudoplasic rheological behaviour than conventional chemical EOR compounds. EOR benefits of incremental oil production, coupled with the use of waste products to produce the compounds employed, minimize the environmental impact of EOR methods employing such compounds.

CO2-EOR mechanisms in huff-n-puff operations in shale oil reservoirs based on history matching results

Improved Oil Recovery (IOR) techniques in Unconventional Liquids Rich Reservoirs (ULR) are still a new concept because there is no commercial project for any IOR technique so far. Carbon dioxide (CO2) based EOR technique has been effectively applied to improve oil recovery in the tight formations of conventional reservoirs. Extending this approach to unconventional formations has been extensively investigated over the last decade because CO2 has unique properties which make it the first option of EOR methods to be tried. However, the applications and mechanisms for CO2-EOR in unconventional reservoirs would not necessarily be the same as in conventional reservoirs due to the complex and poor-quality properties of these plays.Since the first CO2-EOR huff-n-puff project was conducted in conventional reservoirs in Trinidad and Tobago in 1984, more than 130 additional projects have been put in operation around the world, mainly located in USA, Turkey, and Trinidad and Tobago. In this study, we combined Production Data Analysis (PDA) for the production data of these projects with numerical simulation methods to produce one typical graph accounts for the main mechanisms controlling CO2-EOR performance in conventional reservoirs. On the other hand, we have couple of CO2-EOR huff-n-puff pilot tests conducted in Bakken formation between 2008 and 2016. Two engineering-reversed approaches have been integrated to produce a unique type curve for the performance of CO2-EOR huff-n-puff process in shale oil reservoirs. Firstly, a numerical simulation study was conducted to upscale the reported experimental-studies outcomes to the field conditions. As a result, different forward diagnostic plots have been generated from different combinations for CO2 physical mechanisms with different shale-reservoirs conditions. Secondly, different backward diagnostic plots have been produced from the history match with CO2 performances in fields’ pilots performed in some portions of Bakken formation located in North Dakota and Montana. Finally, fitting the backward with the forward diagnostic plots was used to produce another unique type curve to represent CO2-EOR performance in shale oil reservoirs. This study found that the delayed response in the incremental oil production resulted from CO2 injection in shale reservoirs is mainly function of CO2 molecular diffusion mechanism. On the other hand, the CO2 diffusion mechanism has approximately no effect on CO2-EOR performance in conventional reservoirs which have a quick response to CO2 injection. This finding is very well consistent with the experimental reports regarding the role of diffusion in conventional cores versus shale cores. In addition, this study found that kinetics of oil recovery process in productive areas and CO2-diffusivity level are the keys to perform a successful CO2-EOR project in shale formations. This paper provides a thorough idea about how CO2-EOR performance is different in the field scale of conventional reservoirs versus shale formations.

Good wells make better stimulation candidates: An evidence-based analysis

Effective candidate selection is an important consideration in planning successful stimulation campaigns. Identifying “high potential” wells—those that would provide the largest incremental production—has been the subject of several studies, some of which have suggested that stimulation of better producers is a good practice to maximize stimulation benefits. An evidence-based investigation of this idea is lacking and is the subject of this study. This paper hypothesizes that a positive correlation exists between a well's oil production performance and its stimulation incremental oil production. We tested this hypothesis by investigating three independent methods: (1) analysis of aggregate results of case studies in the literature, (2) analysis of production and workover data from four mature Permian Basin San Andres leases, and (3) analysis of the simulation results from a tuned reservoir model. The results confirmed the existence and statistical significance of a positive correlation between pre-stimulation oil rate and stimulation incremental oil production. In our field-scale reservoir simulation model, we used pre-stimulation oil rate to rank stimulation candidates, which identified more than 80% of the top candidates. We recommend prioritizing wells that exhibit high oil production for stimulation in order to statistically increase the likelihood of maximized workover benefits.

Statistical and analytical review of worldwide CO2 immiscible field applications

CO2 immiscible flooding is an important enhanced oil recovery (EOR) technology that has demonstrated great potential under varying reservoir and fluid conditions. This paper provides a comprehensive review of worldwide CO2 immiscible experiences by collecting and analyzing data of 41 field applications from more than 60 publications, including books, DOE reports, AAPG databases, Oil and Gas Journal surveys, field reports, and SPE publications. About 100 papers have been reviewed. Two major parts are included in this paper. The first part explores where CO2 immiscible could be applied, in which screening guidelines have been established and updated by applying statistical methods. Boxplots and histograms were used to detect special cases and to interpret the main distributions of reservoir/fluid properties. The second part discusses the influences of operation to the productions, the performances of each field, and the existing operational problems by using analytical methods, which include injection strategies, gas injection compositions, CO2 utilization, CO2 injection efficiency, incremental oil recovery, and incremental oil production rate per well. Results show that CO2 immiscible flooding could produce an additional 4.7%–12.5% of oil with 10.07 Mscf/stb average CO2 injection efficiency.

Core-Based Evaluation of Associative Polymers as Enhanced Oil Recovery Agents in Oil-Wet Formations

Linear coreflood experiments are performed at 60 °C to test the effectiveness of a low molecular weight associative polymer as a displacing agent, and its ability to enhance oil recovery on chemically treated oil-wet Berea cores. Polymer injection tests revealed high mobility reductions (resistance factor (RF)) and reduced remaining oil saturations. Results obtained suggest that the incremental oil production is due to the high mobility reduction, as reported previously for water-wet porous media. The reduced remaining oil saturation is a function of the injected associative polymer treatment volume. Polymer mobility reduction is highly affected by the injected polymer velocity; this reduction is observed to be more significant at the lower velocity spectrum. Therefore, the established incremental oil production, even at reduced polymer injection rates (lower capillary numbers), could be explained by the increased mobility reduction. A correlation for the velocity-dependent mobility reduction is developed. Results are in agreement with previously reported ones in water-wet media and related to the enhanced oil recovery (EOR) nature of the injected associative polymer as opposed to the traditional mobility control of other polymer types. During injection, a column of oil-polymer emulsion is formed gradually in the separator causing operational difficulties and introducing produced fluid measurement (and core fluid saturations) uncertainties. Produced oil/water emulsion polymer volume content is used to correct overestimated oil production attributed to measurement uncertainties. Real-time resistivity measurements could also be a valuable tool for both fluids saturation monitoring and improved core fluids saturation evaluation in flooded porous media.

Comparing the effects of CH4, CO2, and N2 injection on asphaltene precipitation and deposition at reservoir condition: A visual and modeling study

Enhanced Oil Recovery (EOR) through various methodologies has been an active research for many years seeking efficient methods to increase the crude oil recovery efficiency from oil reservoirs. Among different gas injection scenarios, carbon dioxide (CO2), natural gas (mainly methane (CH4)) and nitrogen (N2) injection are considered as promising EOR agents. Asphaltene precipitation and deposition during EOR methods cause severe problems, which affect the recovery efficiency and increase the cost of the incremental oil production. This study is aimed to investigate the effects of CH4 and N2 injection compared with CO2 injection on asphaltene precipitation and deposition. The different mole percent of the mentioned gases were introduced into the high-pressure cell, then the amount of precipitated asphaltene was measured at the reservoir condition. The evolution of asphaltene deposition was monitored through a high-resolution microscope. Moreover, Image processing software was utilized to check the amount of deposited asphaltene and its size distribution under different conditions. The most apparent finding to emerge from this study is that both CO2 and natural gas increase the amount of precipitated asphaltene whereas the nitrogen as an inert gas has no considerable effect on the amount of precipitated asphaltene. According to the results, the increment of precipitated asphaltene by CO2 is much higher than natural gas. Further, the thermodynamic solid model used in this study reasonably predicted the trend of asphaltene precipitation process for the mentioned EOR scenarios.

Detailed Characterization of the Remaining Oil in Matured Water Drive Reservoir

Most of the water-drive oil reservoirs in the western South China Sea had stepped in the middle and high water-cut stage. By the influence of reservoir heterogeneity, fault distribution, well pattern deployment and variation of reservoir flow parameters during long-term natural water drive and water flooding, the remaining oil distribution forecast is not accurate enough, increasing the difficulty of making effective adjustment and potential tapping measures. Through years of tackling key technical problems and field practice, the detailed characterization technique of the remaining oil in matured water drive reservoir was presented. Based on water displacement mechanism, variation of relative permeability curves are derived from Zhang’s water-drive characteristic curve during long-term water displacement. In addition, dynamic monitoring data matching was adopted to improve the forecast accuracy of the remaining oil distribution in water flooding oil reservoirs. By combination of flow field, remaining oil saturation field, and remaining oil reserves abundance, comprehensive characterization of water drive dynamic state was realized. The remaining oil enriched areas were quantitatively classified into four levels of potential regions, and corresponding adjustment and potential tapping measures were proposed. This technique had been successfully applied in the middle and high water-cut oilfields in the western South China Sea, with remarkable estimated incremental oil production of approximately 204,000 m³.

Enhanced oil recovery and natural bitumen production through the use of sinusoidal wells and solar thermal method

Thermal enhanced oil recovery is known to be the most effective way of heavy oil production. This article discusses the application of sinusoidal wells to improve the efficiency of thermal enhanced oil recovery methods. As a result of numerical simulation of steam-assisted gravity drainage (SAGD) process, it has been shown that the application of sinusoidal wells allowed 8990 m3 of the incremental oil production during 10 years simulation period. However, the high cost of hot water and steam generation, as well as significant environmental impact, limit the application of thermal oil recovery methods. The article presents the concept of year-round generation of desalinated hot water and steam from sea and reservoir brine at low cost by the newly developed solar collector. The collector can be placed in the vicinity of injection wells to provide constant hot water, steam, and electrical power supply.

Pilot Scale CO2 EOR in Mississippian Carbonate Reservoir at Wellington Field in South-central Kansas

CO2 EOR effectiveness and CO2 retention and storage efficiencies in application to Mississippian carbonate reservoirs in Kansas were successfully tested with this small scale field project. Total of 1,101 truckloads, 19,803 metric tons, average of 120 tonnes per day were delivered over the course of injection that lasted from January 9 to June 21, 2016. Current incremental average oil production rate is 34 bbls/day and a total of incremental 6,300 bbls of oil were produced as a result of CO2 injection. Only 12% of injected CO2 was produced back currently (3 months since injection stopped CO2).

Forecasting Incremental Oil Production of a Polymer-Pilot Extension in the Matzen Field Including Quantitative Uncertainty Assessment

Summary The polymer-pilot project performed in the 8 TH reservoir of the Matzen field showed encouraging incremental oil production. To improve further the understanding of recovery effects resulting from polymer injection, an extension of the pilot is planned by adding a second polymer injector. Forecasting of the incremental oil production needs to take the uncertainty of the geological models and dynamic parameters into account. We propose a work flow that is composed of a geological sensitivity and clustering step followed by a dynamic-calibration step for decreasing the objective function (OF) to improve the reliability of a probabilistic forecast of the incremental oil recovery. For the geological sensitivity, hundreds of geological realizations were generated by taking the uncertainty in the correlation of the sand and shale layers, logs, cores, and geological facies into account. The simulated tracer response was used as dissimilarity distance to classify the geological realizations. Clustering was then applied to select 70 representative realizations (centroids) from a total of 800 to use in the full-physics dynamic simulation. In the dynamic simulation, an OF composed of liquid rate and tracer concentration of the produced fluids was introduced. To improve the calibration further, the P50 value of incremental oil production as derived from simulation was compared with the incremental oil production determined from decline-curve analysis (DCA) from the wells surrounding the polymer-injection well. The mismatch between the P50 and the DCA was improved by adjusting polymer viscosity. The calibrated models were then used for both a probabilistic forecast of incremental oil caused by an additional polymer injector and an estimate of the expected polymer concentration at the producing wells.

Performance assessment of CO2-enhanced oil recovery and storage in the Morrow reservoir

This paper presents a performance assessment methodology for CO2 enhanced oil recovery (EOR) in partially depleted reservoirs. A three dimensional heterogeneous reservoir model was developed for evaluating the CO2-EOR performance of in the Farnsworth Field Unit (FWU), Ochiltree County, Texas. The model aided in improved characterization of prominent rock properties within the Pennsylvanian-aged Morrow sandstone reservoir. Seismic attributes illuminated previously unknown faults and structural elements within the field. A laboratory fluid analysis was tuned to an equation of state and subsequently used to predict the thermodynamic minimum miscible pressure. Datasets including net-to-gross ratio, volume of shale, permeability, and burial history were used to model initial fault transmissibility based on Sperrevik model. An improved history match of primary and secondary recovery was performed to set the basis for a CO2 flood study. The performance of the current CO2 miscible flood patterns were subsequently calibrated to historical production and injection data. Several prediction models were constructed to study the effect of recycling, addition of wells and/or new patterns, water alternating gas cycles and optimum amount of CO2 purchase on incremental oil production and CO2 storage in the FWU. The history matching study successfully validated the presence of the previously-undetected faults within FWU that were seen in the seismic survey. The analysis of the various prediction scenarios showed that recycling a high percentage of produced gas, addition of new wells and a gradual reduction in CO2 purchase after several years of operation would be the best approach to ensure a high percentage of recoverable incremental oil and sequestration of anthropogenic CO2 within the Morrow reservoir.

Descriptive statistical analysis for the PPG field applications in China: Screening guidelines, design considerations, and performances

Preformed particle gels (PPGs) have been widely applied in waterflooded mature oilfields to improve reservoir sweep efficiency and control water production. Successful PPG applications in oilfields require comprehensive guidelines on where and how PPG treatments can be best applied. To establish such guidelines, a data set is first constructed by collecting 678 successful PPG treatment data from SPE technical papers, papers published in Chinese, and field applications reports from 2001 to 2015. Critical information regarding reservoir characteristics, injection well conditions, injection parameters, and treatment performances, is included in the data set. Descriptive statistical analysis methods including histograms, and scatterplots are used to interpret of the main features of the amount of data. Histograms display the distribution of each parameter and can provide guidance on where PPGs can be best applied; scatterplots uncover relationships between two variables and can aid in interpreting how to design injection parameters and find out the critical factors affecting the treatment performances. After comprehensive data analysis, the first application guidelines for PPG treatments are established. Results show that PPGs can generate large volumes of incremental oil production and significantly reduce excess water production. Successful PPG treatments require a large volume of PPG injection with a low suspension concentration. The injection volume highly depends on the daily water production rate. Incremental oil production increases with the increase of injected PPGs. PPG treatment efficiency is defined herein as incremental oil production per ton PPGs injected. Although reservoir type can affect the treatment efficiency, the better efficiency always comes from the injection wells which have production wells with a higher liquid production rate. Treatment timing should be considered as a critical factor affecting the effect of water reduction. This paper provides instructional guidelines for project design from which the success rate of PPG treatments in injection wells can be improved.

Multiobjective design and optimization of polymer flood performance

The design and optimization of polymer flood projects have traditionally focused on increasing oil production only. For economic viability, the optimization strategy should maximize oil production while minimizing polymer usage. However, these two objectives can be conflicting. The challenge is how to optimize polymer flood design considering the trade-off between these conflicting objectives.In this work, we utilize the concept of Pareto optimality to generate a set of Pareto optimal solutions that represent a trade-off relation between the conflicting objectives viz. polymer utility factor and incremental oil gain. The Pareto optimal solutions can be searched by a non-domination based genetic algorithm (NSGA-II). The algorithm evaluates fitness by a dominance relationship instead of fitness measures as in the ordinary single-objective genetic algorithm. The dominance concept defines levels of optimality by assigning several ranks to each population. The algorithm iteratively minimizes ranks until all members of the population become rank one which implies that the Pareto optimality condition is reached.The application of our proposed method is demonstrated by a 2D synthetic example and a 3D field-scale application. The Pareto-based approach is implemented to simultaneously optimize two objectives: (1) polymer utility factor (UF) which is the amount of polymer required per barrel of incremental oil and (2) cumulative incremental oil production (Np). The results demonstrate that beyond the optimal design, relatively minor increase in oil production requires significantly more polymer injection and the polymer UF is increased substantially.To optimize both oil production and polymer utility, the Pareto optimal solutions provide the best compromise that enables maximizing oil production while maintaining the efficiency of polymer usage.

An innovative air assisted cyclic steam stimulation technique for enhanced heavy oil recovery

Air assisted cyclic steam stimulation (AACSS) is an innovative technique for enhanced heavy oil recovery, in which air is injected along with steam injection during a conventional CSS process. It can be applied for heavy or ultra heavy oil reservoirs in the late stage of CSS process to increase the performance of steam injection and mitigate the problems of low reservoir pressure, poor steam sweep efficiency and high water cut. In this study, the application of the AACSS technique in a typical ultra heavy oil reservoir of Liaohe oilfield (China) was described and its field performances were analyzed along with a numerical reservoir simulation study to reveal its mechanism. The field data shows that the AACSS can significantly increase oil production, reduce water cut and prolong the effective production period. A reaction model for the oxidation of heavy oil components with oxygen in the temperature range of 50–300°C was established, based on the experimental results of thermogravimetric analysis (TGA), to simulate the conversion of air into flue gas and its thermal effect. The performance of AACSS was investigated and the contribution of thermal effect induced by LTO reactions was analyzed through numerical simulation. The simulation results indicate that air injection can improve oil recovery on the basis of CSS, in which over 11% of the incremental oil production can be attributed to the thermal effect, and the rest is accounted for a complex effect of flue gas driving.

Расчет типовых кривых дополнительной добычи нефти от реализации смешивающегося вытеснения на основе композиционного моделирования

Расчет типовых кривых дополнительной добычи нефти от реализации смешивающегося вытеснения на основе композиционного моделирования