An experimental investigation of rock wettability alteration, asphaltene molecular stability, and enhanced oil recovery using a new nanofluid

Nanotechnology was proposed as a new Enhanced Oil Recovery (EOR) technique for its great potential of increasing oil recovery either in secondary or tertiary recovery stage. Several types of nanoparticles have been used for different applications in the EOR. The recovery mechanisms of such improvement of these nano particles are still need more research to be interpreted. From these suspected parameter the rock wettability and relative permeability alteration. Moreover, these nanoparticles can be used in different concentration and different sizes in the EOR project. Consequently, it is very important to study the effect of these factors on the incremental oil recovery in order to create a successful EOR operations. To achieve some of these concerns, a series of core flooding experiments was conducted to study the effect of Alumina nanofluid concentration in the displacing brine on the relative permeability curves, rock wettability and finally the ultimate recovery factor. During core flooding experiments, a sandstone core was used and all pertinent and required parameters are monitored and recorded. The relative permeability to oil and water were calculated, and the contact angle was measured to check the degree of the rock wettability while using this nanofluid as an additive to the displacing water. The base run was performed using water to be used as a secondary recovery base run. The ultimate recovery factor by water flooding was found to be 60.38 % of the OOIP. Then a flooding process using Alumina nanofluid, as an additive to the displacing water, has been conducted with five different concentrations (3, 5, 7, 10, and 15 g/L). The ultimate recovery factor was calculated for all concentrations and has been found to be74.38%, 75.09%, 76.13%, 81.13%, and 61.70% respectively. The drawback in the ultimate recovery of 15 g/L run has been addressed and explained while the best concentration was the 10 g/L Alumina nanofluid which led to a 20.75 % oil recovery over that of water flooding. The main recovery mechanisms are addressed and expected. The relative permeability curves for all of these experimental runs were measured at different nano alumina concentrations and compared to each other. The contact angle (as a mean to evaluate the wettability alteration) was measured in order to investigate the effect of this nano fluid on the rock wettability. It was found that those rocks became more water wet after using Alumina nanofluid. This work investigates and analyzes the new outcomes from implementing Alumina nanofluid for EOR. Ultimately, the knowledge gained from this work can be used as a guide to interpret and define the Nanofluids improvement mechanisms and help in drawing a road map for ongoing and future work.

Fracture treatment performance in Bakken shale reservoirs can be improved by altering rock wettability, as measured with contact angle (CA), from oil-wet to water-wet. The use of chemical additives for altering wettability also results in alteration of the interfacial tension (IFT). The Young-Laplace equation relates the capillary pressure to IFT and contact angle. Thus, it follows that capillarity is significant in nano-pores associated with unconventional liquid reservoirs (ULR) and complex as the CA and IFT varies simultaneously. We carefully evaluate these interactive variables to improve oil recovery by alteration of capillary pressure by understanding the wetting state of siliceous and carbonate Bakken cores with and without chemical additives. We have observed that wettability can be altered from the ULR natural state of oil-wet to systems favoring frac fluid imbibition. Surfactants can be added to completion fluids, in proper concentrations, to alter wettability while hydraulic fracturing the formation. This experimental study evaluates and compares the efficiency of anionic, nonionic and blended surfactants as well as complex nanofluids (CNF) on recovering liquid hydrocarbons from Bakken shale cores by analyzing the effect of wettability and IFT alteration and their impact on spontaneous imbibition. The original wettability of Bakken cores is determined by CA measurements. Then, three surfactant types, anionic nonionic and nonionic-cationic, and CNF are evaluated to gauge their effectiveness in altering wettability. The results show that all surfactants and CNF are able to shift core wettability from oil-wet to water-wet. However, chemical additives efficacy strongly depends on rock lithology, surfactant, and CNF type. Moreover, to evaluate further wettability alteration, stability of surfactant and CNF solution films on the shale rock surface is determined by zeta potential measurements. Surfactants and CNF show higher zeta potential magnitudes than water without additives, as an indication of better stability and water-wetness, which agrees with CA results. In addition, the effect of IFT alteration is studied in solutions with surfactants and CNF, and Bakken crude oil. Higher IFT reduction is achieved by anionic surfactants, but all surfactants and CNF perform better than water alone. Surfactants and CNF potential for improving oil recovery in ultralow permeability Bakken cores is investigated by spontaneous imbibition experiments using modified Amott cells in an environmental chamber. Using computed tomography (CT) scan methods, water imbibition as penetration magnitude is measured in real time. In addition, oil recovery is recorded with time to compare the performance of surfactants, CNF, and completion fluid alone. The results suggest that surfactants and CNF are better on recovering oil from shale core displacing more oil and having higher penetration magnitudes than water without additives. In addition, oil recovery depends on surfactant and CNF type and rock mineral composition. These findings are consistent with CA, zeta potential, and IFT measurements. From the results obtained, it can be concluded that altering wettability and reducing IFT when surfactants and CNF additives are added to completion fluids can improve oil recovery in Bakken cores.

Wettability of a carbonate reservoir is one of the key points concerning oil recovery. Most carbonate reservoirs tend to be oil-wet. An oil-wet wettability generates significant problems in oil recovery since the formation has a stronger ability to keep oil attached in its pores, and it also decreases the efficiency of water flooding leading to faster water breakthrough. Wettability alteration in oil wet carbonate reservoirs have demonstrated to be a successful method in enhancing oil recovery through chemical water flooding of such formations. Wettability, IFT (Interfacial tension), and temperature, are all parameters that have a significant effect on the recovery process. Different processes and chemicals have been tested to study the alteration of wettability through contact angle and its effect on oil recovery. It is essential to understand the correlation between the IFT value of the brine injected with the degree of wettability alteration, in order to assemble an optimized brine solution for enhancing oil recovery by finding an optimized contact angle and an IFT value. In this paper, carbonate outcrop samples from Jabal Fuwayrit in Qatar (considered to be a similar and representative to the North Field formation) were used to make a comparative study of wettability alteration effect followed by recovery. Spontaneous imbibition and flooding of brine with different chemical composition were employed. We also studied the effect of non-ionic and cationic surfactants in sea water from Qatar to further enhance oil recovery. Comparison of the results obtained leads to a better understanding of wettability alteration and the appropriate selection of injection brine for optimal recovery. The significance of such study can be easily demonstrated. Wettability understanding and alteration at will is of a great importance and can be expanded in all type of reservoirs, giving a cost-effective, fast and functional process.

The Field Z Gas Cap Blow Down (GCBD) project focuses on boosting oil production and securing a reliable gas supply for Field A's Enhanced Oil Recovery (EOR). By optimizing gas cap utilization with targeted well interventions—such as plug setting, perforation addition, and advanced sand control—the project ensures consistent gas injection rates and long-term field stability. This paper outlines field performance, process efficiency, and anticipated results, providing a comprehensive blueprint for sustainable production enhancement. The Field Z Gas Cap Blow Down (GCBD) project utilizes a structured approach to optimize gas cap utilization and support Field A's Enhanced Oil Recovery (EOR). The strategy includes well-specific interventions on Z-B01, Z-B02, and Z-B11, such as setting plugs for zonal isolation, adding perforations to enhance gas flow, and installing Erosion Resistant Thru-Tubing Sand Screens (ER-TTSS) for effective sand control. A thorough process adequacy analysis ensures the alignment of surface facilities with project objectives. These initiatives work in tandem to optimize gas production, maintain injection rates, and maximize oil recovery. The Field Z Gas Cap Blow Down (GCBD) project has yielded remarkable results, proving its effectiveness in optimizing resource utilization and supporting Field A's Enhanced Oil Recovery (EOR). Targeted interventions on wells Z-B01, Z-B02, and Z-B11 led to an immediate gas production increase of 18 MMscf/d, adding 24 Bscf in reserves and contributing an estimated 2.2 MMstb in additional oil recovery. Key accomplishments include successful zonal isolation, enhanced gas mobility through perforations, and sustained well integrity with Erosion Resistant Thru-Tubing Sand Screens (ER-TTSS), which addressed sand production challenges. The project also met infrastructure adequacy standards, ensuring alignment with the gas compressor's Turn Down Rate (TDR) of 21 MMscfd through 2029, ensuring stable gas injection for Field A. These efforts optimized gas cap productivity while prolonging field life and boosting profitability. In conclusion, the GCBD project represents a strategic approach to resource management, delivering significant gains in production, reservoir health, and operational sustainability. It highlights the value of innovative methods and thorough planning in advancing production enhancement strategies, setting a benchmark for similar projects in gas cap utilization and EOR support. This paper presents innovative methodologies for maximizing gas cap utilization through zonal isolation, perforation optimization, and Erosion Resistant Thru-Tubing Sand Screens (ER-TTSS). It includes a thorough process adequacy analysis designed for non-routine operations, providing valuable insights into addressing high-stress production challenges. Engineers will gain from detailed case studies, technological advancements, and risk mitigation strategies, offering practical, field-tested solutions to enhance reservoir performance and ensure sustainable resource management over the long term.

Recently, Enhanced Oil Recovery (EOR) application in offshore oil fields is receiving significant attention. The size of targeted offshore oil fields is generally large, because their Original-Oil-In-Place (OOIP) should be sufficiently large to overcome the high cost of offshore oil field development. Therefore, the amount of recoverable oil using EOR may be enormous. The risks of applying EOR are lower than the exploration for deep-water oil, because EOR except for thermal EOR is usually applied to the already producing oil fields. Because of the above reasons, offshore EOR application has been considered as a highly acceptable option. However, application conditions for offshore oil fields are more complex than onshore oil fields due to the unique parameters present in offshore fields. Therefore, successful EOR application in an offshore oil field requires screening criteria that are different from the conventional onshore screening criteria. A comprehensive database for onshore applications of EOR processes, together with a limited offshore EOR application database, are analyzed in this paper; and the important parameters for successful offshore application are incorporated into the new EOR screening criteria. In this paper, screening criteria for highly acceptable EOR processes in offshore fields including hydrocarbon (HC) gas miscible, CO2 miscible and polymer are presented. Gas EOR using produced hydrocarbon gas has high potential for light oil recovery in offshore fields because of high availability of injectant and its reduced handling cost. For medium oil and even heavier oil recovery, polymer process is highly acceptable because it is a well proven technology by the earlier onshore and even offshore applications. CO2 miscible process has been proven as a successful technology worldwide, mainly in onshore fields. In many cases, minimum miscibility pressure of CO2 is lower than hydrocarbon gas; hence, the CO2 miscible process has a wider range of field candidates. In view of the current active interests in seeking synergy between CO2 storage and the high efficiency of the CO2-based oil recovery, this process has high potential for offshore EOR application if CO2 can be available economically. Suggested screening criteria for these EOR processes comprise quantitative boundary and qualitative considerations. Quantitative screening criteria are mostly based on quantifiable data including oil and reservoir properties. Most screening criteria suggested in this paper are generally similar to those previously suggested. Due to the recent significant polymer development efforts and their active applications, however, the difference for oil viscosity criteria in the polymer process is relatively large. There is a high potential for further criteria extension in the polymer process. Qualitative screening considerations mainly focuses on operational issues present in offshore including limited space on the platform, limited disposal option, injectant availability and flow assurance matters (mainly hydrate formation and difficulty in emulsion separation). These considerations are very hard to be quantified and highly depend on operational limitation of each EOR process in specific fields. However, it is found that economical availability of injectant is most critical parameter in early stage of EOR screening.

Injection of chemically tuned brines into carbonate reservoirs has been reported to enhance oil recovery by 5% to 30% OOIP in core flooding experiments and field tests. One proposed mechanism for this improved oil recovery (IOR) is wettability alteration of rock from oil wet or mixed-wet to more water wet conditions. Modeling of wettability alteration experiments, however, are challenging due to the complex interactions among ions in the brine and crude oil on the solid surface. In this research, we developed a multiphase multicomponent reactive transport model that explicitly takes into account wettability alteration from these geochemical interactions in carbonate reservoirs. Published experimental data suggests that desorption of acidic oil components from rock surfaces make carbonate rocks more water wet. One widely accepted mechanism is that sulfate (SO42−) replaces the adsorbed carboxylic group from the rock surface while cations (Ca2+, Mg2+) decrease the oil surface potential. In the proposed mechanistic model, we used a reaction network that captures the competitive surface reactions among carboxylic groups, cations, and sulfate. These reactions control the wetting fractions and contact angles, which subsequently determine the capillary pressure, relative permeabilities, and residual oil saturations. The developed model was first tuned with experimental data from the Stevns Klint chalk and then used to predict oil recovery for additional un-tuned experiments under a variety of conditions where IOR increased by as much as 30% OOIP, depending on salinity and oil acidity. The numerical results showed that an increase in sulfate concentration can lead to an IOR of over 40% OOIP, while cations such as Ca2+ have a relatively minor effect on recovery (about 5% OOIP). Other physical parameters, including the total surface area of the rock and the diffusion coefficient, control the rate of recovery, however not the final oil recovery. The simulation results further demonstrate that the optimum brine formulation for chalk are those with relatively abundant SO42− (0.096 mol/kg water), moderate concentrations of cations, and low salinity (total ionic strength less than 0.2 mol/kg water). These findings are consistent with the experimental data reported in the literature. The new model provides a powerful tool to predict the IOR potential of chemically tuned waterflooding in carbonate reservoirs under different scenarios.

Summary Injection of chemically tuned brines into carbonate reservoirs has been reported to enhance oil recovery by 5–30% original oil in place (OOIP) in coreflooding experiments and field tests. One proposed mechanism for this improved oil recovery (IOR) is wettability alteration of rock from oil-wet or mixed-wet to more-water-wet conditions. Modeling of wettability-alteration experiments, however, is challenging because of the complex interactions among ions in the brine and crude oil on the solid surface. In this research, we developed a multiphase and multicomponent reactive transport model that explicitly takes into account wettability alteration from these geochemical interactions in carbonate reservoirs. Published experimental data suggest that desorption of acidic-oil components from rock surfaces make carbonate rocks more water-wet. One widely accepted mechanism is that sulfate (SO42−) replaces the adsorbed carboxylic group from the rock surface, whereas cations (Ca2+, Mg2+) decrease the oil-surface potential. In the proposed mechanistic model, we used a reaction network that captures the competitive surface reactions among carboxylic groups, cations, and sulfate. These reactions control the wetting fractions and contact angles, which subsequently determine the capillary pressure, relative permeabilities, and residual oil saturations. The developed model was first tuned with experimental data from the Stevns Klint chalk and then used to predict oil recovery for additional untuned experiments under a variety of conditions where IOR increased by as much as 30% OOIP, depending on salinity and oil acidity. The numerical results showed that an increase in sulfate concentration can lead to an IOR of more than 40% OOIP, whereas cations such as Ca2+ have a relatively minor effect on recovery (approximately 5% OOIP). Physical parameters, including the total surface area of the rock and the diffusion coefficients, control the rate of recovery, but not the final oil recovery. The simulation results further demonstrate that the optimum brine formulations for chalk are those with relatively abundant SO42− (0.096 mol/kg water), moderate concentrations of cations, and low salinity (total ionic strength of less than 0.2 mol/kg water). These findings are consistent with the experimental data reported in the literature. The new model provides a powerful tool to predict the IOR potential of chemically tuned waterflooding in carbonate reservoirs under different scenarios. To the best of our knowledge, this is the first model that explicitly and mechanistically couples multiphase flow and multicomponent surface complexation with wettability alteration and oil recovery for carbonate rocks specifically.

Summary This study focuses on the mechanisms responsible for enhanced oil recovery (EOR) from fractured carbonate reservoirs by surfactant solutions, and methods to screen for effective chemical formulations quickly. One key to this EOR process is the surfactant solution reversing the wettability of the carbonate surfaces from less water-wet to more water-wet conditions. This effect allows the aqueous phase to imbibe into the matrix spontaneously and expel oil bypassed by a waterflood. This study used different naphthenic acids (NA) dissolved in decane as a model oil to render calcite surfaces less water-wet. Because pure compounds are used, trends in wetting behavior can be related to NA molecular structure as measured by solid adsorption; contact angle; and a novel, simple flotation test with calcite powder. Experiments with different surfactants and NA-treated calcite powder provide information about mechanisms responsible for sought-after reversal to a more water-wet state. Results indicate this flotation test is a useful rapid screening tool to identify better EOR surfactants for carbonates. The study considers the application of surfactants for EOR from carbonate reservoirs. This technology provides a new opportunity for EOR, especially for fractured carbonate, where waterflood response typically is poor and the matrix is a high oil-saturation target. Introduction Typically only approximately a third of the original oil in place (OOIP) is recovered by primary and secondary recovery processes, leaving two-thirds trapped in reservoirs as residual oil. Approximately half of world's discovered oil reserves are in carbonate reservoirs and many of these reservoirs are naturally fractured (Roehl and Choquette 1985). According to a recent review of 100 fractured reservoirs (Allan and Sun 2003), carbonate fractured reservoirs with high matrix porosity and low matrix permeability especially could use EOR processes. The oil recovery from these reservoirs is typically very low by conventional waterflooding, due in part to fractured carbonate reservoirs (about 80%) being originally less water-wet. Injected water will not penetrate easily into a less water-wetting porous matrix and so cannot displace that oil in place. Wettability of carbonate reservoirs has been widely recognized an important parameter in oil recovery by flooding technology (Tong et al. 2002; Morrow and Mason 2001; Zhou et al. 2000; Hirasaki and Zhang 2004). Because altering the wettability of a rock surface to preferentially more water-wet conditions is critical to oil recovery, alteration of reservoir wettability by surfactants has been intensively studied, and many research papers have been published (Spinler and Baldwin 2000). Vijapurapu and Rao (2004) studied the capability of certain ethoxy alcohol surfactants to alter wettability of the Yates reservoir rock to water-wet conditions. Seethepali et al. (2004) reported that several anionic surfactants in the presence of Na2CO3 can change a calcite surface wetted by a West Texas crude oil to intermediate/water-wet conditions as well as, or even better than, an efficient cationic surfactant. Zhang et al. (2004) investigated also the effect of electrolyte concentration, surfactant concentration, and water/oil ratio on wettability alteration. They reported that wettability of calcite surface can be altered to approximately intermediate water-wet to preferentially water-wet conditions with alkaline/anionic surfactant systems. Adsorption of anionic surfactants on a dolomite surface can be significantly reduced in the presence of sodium carbonate.

North Kuwait has vision to increase oil production from its major reservoir and it is planned to be achieved by covering the major reservoirs under the umbrella of enhanced oil recovery (EOR). Sabiriyah Lower Burgan (SALB) is the biggest sandstone reservoir in Sabiriyah field with high permeability and strong aquifer support. Paper describes steps planned from present development strategy of simply infill drilling to EOR to improve the production scenario in future.Primary recovery from reservoirs like SALB are expected to be good. Performance of the reservoir especially rise in water cut of SALB was analyzed which suggested that though primary recovery would be good but will take longer time to achieve. EOR screening was performed and suitable EOR methods were evaluated using mechanistic model. Screening considered target oil, water quality, permeability, oil viscosity, temperature, aquifer and injection capacity. Lab experiments were performed for the identified EOR processes and most suitable method was selected. EOR pilot area and pilot design performed to take it forward from concept stage towards reality.SALB Layered part is an acceptable candidate for EOR process due to favorable mobility ratio which reduces the need for mobility control agents, reservoir being mixed wet system which is encouraging for improving unit displacement efficiency and reservoir rock properties are conducive to most forms of EOR. Low salinity water, CO2, N2 and Chemical EOR methods were evaluated. Mechanistic model based Estimated Recovery factor range for these EOR methods indicated Chemical EOR, (A) SP as most effective EOR method. Lab experiments were performed for CO2, N2 and ASP. In Lab, miscible N2 flooding was not found feasible whereas CO2 flooding was feasible for either as CO2 or a blend of CO2/NGL. Coreflood experiments suggested surfactant-polymer or alkaline-surfactant-polymer pilot flood as promising EOR methods for SALB. KOC has planned to proceed with Chemical EOR with its further evaluation through single well chemical tracer test (SWCTT) as first step. A multi-well pilot was also recommended assuming a successful single wells tracer test which would provide a better understanding of chemical solution injectivity, oil recovery potential, chemical retention by the reservoir, effect of the water drive on alkaline-surfactant-polymer flood potential and operational issues. Target layer and likely area was identified for EOR pilot.EOR in a reservoir with strong aquifer drive has its own challenges but merits of SALB for enhancement of recovery are encouraging. The paper provides an insight of applicability of Chemical EOR in a large reservoir with strong aquifer that will pave the way for similar reservoirs in Kuwait and worldwide.

This paper presents an enhanced oil recovery (EOR) evaluation for two heavy-oil fields in Africa. The objective of the evaluation is to identify the technically and economically viable EOR techniques for the fields. A total of thirteen established and emerging EOR techniques were evaluated in this study. The study included the first degree approximation of the oil recovery for the viable EOR techniques and the stand-alone project economics estimation. The data required for the study include: 1) fluids and rock properties; 2) driving mechanism; 3) production data; 4) OOIP and recoverable reserves; and 5) relative permeability curves. Various EOR technique screening criteria, consisting of a list of reservoir parameters and their ranges which are likely to lead to a success, were applied to match the parameters of the study fields. The oil recovery predictions were estimated utilizing general reservoir parameters and developed correlations1. The economic feasibility of the potential EOR techniques was then evaluated based on the stand-alone project economics that accounted for the revenue from the incremental oil and the associated operating and capital costs. The evaluation results showed that the thermal EOR techniques: steam flooding and in-situ combustion are technically the most viable EOR techniques for the fields. It was then followed by the chemical EOR techniques. The performances of steam flooding and in-situ combustion are both very promising, with oil recovery of up to 49% OOIP. Comparing to the oil recovery of water flooding, a significant incremental oil recovery of 24% OOIP was obtained. However, the in-situ combustion process is able to accelerate the oil production, which significantly impacts the economic viability assessment, rendering the in-situ combustion process as the most technically, and economically feasible EOR process for the fields. Based on the EOR evaluation, the oil recovery predictions and economic assessments of the thirteen EOR techniques, including the chemical, gas, thermal and microbial EOR techniques, served as a guideline to develop the long term corporate strategy regarding the EOR potential of the fields.

Recent progresses of microemulsions-based nanofluids as a potential tool for enhanced oil recovery

Technology Focus In spite of continued investment and advances in exploiting alternative-energy sources, oil and natural gas will continue to be a significant portion of US and global energy portfolios for decades. Enhanced oil recovery (EOR) uses unconventional hydrocarbon-recovery methods that target the approximately two-thirds of the oil volume remaining in reservoirs after conventional-recovery methods have been exhausted. Though limited by high capital and operating costs, EOR techniques will have a substantial effect on the future supply of oil. In 2011, SPE hosted an EOR conference in Kuala Lumpur, and three workshops to address EOR technologies in Malaysia, Kuwait, and the Syrian Arab Republic. The Malaysia workshop focused on chemical-EOR methods, the Kuwait workshop addressed opportunities and for challenges of EOR methods in the Middle East, and the Syrian Arab Republic workshop discussed EOR in carbonate reservoirs. More than 300 EOR papers were published in SPE conferences, with many additional presentations in EOR workshops. These papers address important issues related to practical application of conventional EOR methods and the development of novel EOR technologies. The topics cover experience with, opportunities for, and challenges of EOR technologies; fundamental study of EOR mechanisms for different methods; feasibility study and improvement of an EOR method for a specific reservoir; EOR-screening criteria; reservoir surveillance, monitoring, and evaluation technologies; reservoir simulation and modeling; lessons learned from EOR pilot and field trials; and some novel EOR methods. Polymer flooding has been proved the most cost-effective chemical-EOR method in the laboratory and in the field. A recent focus on polymer flooding evaluated associative polymers because of their advantage over traditional hydrolyzed polyacrylamide (HPAM) polymers; thus, one paper about comparing the flow behavior of associative polymer and HPAM in porous media was selected for this feature. CO2 injection is a win/win strategy because it can enhance oil recovery and be used for CO2 storage in reservoirs to reduce greenhouse-gas levels in the atmosphere. However, CO2 EOR targets maximum oil recovery while CO2 sequestration targets maximum storage capacity without leakage. One paper featured here provides some guidance to balance the two technologies. Steamflooding has been applied successfully in heavy-oil reservoirs. However, one paper synopsized in this feature will describe successful steamflooding in a light-oil reservoir. Recommended additional reading at OnePetro: www.onepetro.org. SPE 142668 Enhanced Waterflood for Middle East Carbonate Cores—Impact of Injection-Water Composition. By Robin Gupta, ExxonMobil Upstream Research, et al. SPE 142105 A Simplified Model for Simulations of Alkaline/Surfactant/Polymer Floods. By Mojdeh Delshad, SPE, University of Texas at Austin, et al. SPE 144294 Large-Scale High-Viscous-Elastic-Fluid Flooding in the Field Achieves High Recoveries. By Wang Demin, SPE, Daqing Oil Company, et al. \ SPE 144599 A Combined Experimental and Simulation Workflow To Improve Predictability of In-Situ Combustion. By M. Bazargan, Stanford University, et al. SPE 147858 In-situ Combustion Using Sugar Dust, ‘Sweet Reservoirs’—A Smart and Better Alternative by Panchamlal, SPE, Maharashtra Institute of Technology, et al. SPE 147999 Lessons Learned From Nine Years of Immiscible-Gas-Injection Performance and Sector-Modeling Study of Two Pilots in a Heterogeneous Carbonate Reservoir by Lakshi Konwar, SPE, Zakum Development Company, et al.

The majority of enhanced oil recovery (EOR) projects are being executed in the the U.S., Canada, Venezuela, Indonesia and China. The volume of oil produced by EOR methods increased considerably from 1.2 MMBD in 1990 to 2.5 MMBD in 2006 (Sandrea and Sandrea 2007). Current total world oil production from EOR is approaching 3 MMBD representing about 3.5% of the daily global oil production (Sandrea and Sandrea 2007). Thermal and CO2 methods are the major contributors to EOR production, followed by hydrocarbon gas injection and chemical EOR. Other more esoteric methods, e.g., microbial, have only been field tested, without any significant quantities being produced on a commercial scale. In recent years, the number of EOR projects has increased with escalating oil prices. The number of EOR projects in the Middle East (ME) has also increased over the past decade. In some countries like Oman, there has been no choice but to implement EOR projects aggressively due to dwindling "easy oil." Other countries in the region have also started to think EOR, and are including them in their strategic short-, medium- and long-term development plans. Furthermore, there are many projects on the drawing board and appropriate screening studies and EOR pilots are being pursued region-wide. This paper reviews the current ME EOR projects from full-field development to field trials, including those on the drawing board. The option of advanced secondary recovery (ASR) — also known as improved oil recovery (IOR) — technologies before full-field deployment of EOR is also discussed. A case is made that they are a better first option before deployment of capital-intensive EOR projects. The ME’s general drive towards "ultimate" oil recovery — instead of immediate oil recovery — is highlighted in the context of EOR. Some of the enablers for EOR in the ME are also discussed in the paper. It highlights the opportunities and challenges of EOR specific to the region.

Low salinity water (LSW) is reported to improve oil recovery (IOR) significantly in sandstone and carbonate core experiments. The IOR is because of the specific composition of the injection water, in particular the concentrations of SO42-, Ca2 , and Mg2 . Ranges of IOR vary significantly depending on the brine, oil and cores used. We previously developed a process-based and predictive model that explicitly includes the chemical interactions between crude oil, brine, and the carbonate surface that alter rock wettability. In this research, we use the developed model to optimize the IOR considering the brine, oil and mineral compositions. The wettability alteration is predicted by the relative change of the surface adsorbed carboxylic acids, which is coupled with a set of aqueous and surface reactions. The total concentrations of aqueous and surface species are varied individually and together over a large range while precipitation and dissolution reactions are also included. The wettability is mapped in the space spanned by the species concentrations. The IOR depend strongly on the concentration of Ca2 , Mg2 and SO42-, as well as the total ionic strength. CaSO4 and MgSO4 precipitation are found to reduce the extent of the wettability alteration to a more water wet state. Ca2 and Mg2 can replace each other at low concentration, while less Ca2 and more Mg2 leads to more wettability alteration because MgSO4 has a higher solubility in water than CaSO4. The injection water “recipes” that maximize IOR depends strongly on a suite of reservoir properties, including the initial formation water, and available water source, as well as the reservoir mineralogy and crude oil composition. Our results demonstrate for specific cases how to select the best injection water chemistry to maximize oil wettability alteration.

Whilst the incremental oil potentially recoverable by the application of enhanced oil recovery (EOR) processes can only be reliably estimated by a detailed study of each reservoir, in order to provide an early guide to the scope for EOR in Malaysia, a preliminary survey has been carried out. The approach in this preliminary survey was to develop a set of screening criteria for the various processes being developed and to use these criteria to identify possible candidate reservoirs. The potential for incremental oil recovery was then determined by applying factors obtained from the assessment studies referred to above or from published sources. The review of EOR potential within Malaysia has suggested that only a small number of reservoirs are unsuitable for EOR and there is substantial scope for increasing the yield from known light oil and gas condensate reservoirs. The possible contribution that could be made by individual processes is fairly evenly distributed between polymer floods, surfactants, carbon dioxide and nitrogen or hydrocarbon gas. The enforcement of strict conservation measures and depletion control had change the development strategy by integrating EOR into conventional method of production with an early implementation of EOR in order to maintain the viability of EOR projects.