Improved Oil Recovery Methods Research Articles

Simulation study of affecting parameters during low salinity water injection in carbonate reservoirs: from core to field scale

Over the last decade, economic and environmental factors have led to low salinity water injection (LSWI) becoming one of the most important improved oil recovery methods. Although many results have been obtained from laboratory tests, only a few papers have been published regarding the modeling and simulating LSWI in carbonate reservoirs compared to sandstone reservoirs. This paper investigated the most affecting parameters on oil recovery during LSWI at the core and field scale. The published work focused more on the effective parameters related to ultimate oil recovery using LSWI. However, important parameters affecting the oil recovery rate were not investigated. We compared how important parameters affected the ultimate oil recovery factor and ultimate oil recovery rate. According to the results of this study, the salinity of injected water and curvature of oil relative permeability were the most important factors on the ultimate oil recovery factor. By reducing both of these parameters, more increment oil was recovered. By increasing the injection rate of water, the curvature of the water relative permeability, wettability, and the endpoint of oil relative permeability, the oil recovery rate also increased. Furthermore, threshold capillary pressure and the endpoint of relative permeability of water had inverse effects on oil recovery. Injecting low salinity water into the reservoir will change its wettability. As a result, it will change the properties of the reservoir and increase the production from the reservoir, resulting in more oil being produced. LSWI resulted in an increase of oil recovery factor of 5% and 11% respectively after 25 and 58 years in this case.

Grand Challenges for the Oil and Gas Industry for the Next Decade and Beyond

_ The oil and gas industry faces a rapidly changing world of multiple challenges and opportunities, especially with growing climate and sustainability concerns. About a decade ago, SPE conducted a series of workshops to define the grand challenges in technology and R&D for the upstream oil and gas industry for the following decade. It identified 5 + 1 grand challenges (Table 1). To define the set of grand challenges for the next decade, in a much more unpredictable environment, we held an SPE workshop in Austin, Texas, in January 2023. Panelists from IOCs, NOCs, and service companies, as well as environmental and financial stakeholders in the emerging energy system, surveyed the rapidly changing energy landscape. The workshop then facilitated sessions of the more than 120 thought leader participants to define grand challenges that are impactful for society and our industry and have a significant R&D/technology component that is aligned with the capabilities of the SPE membership. We arrived at a list of five technical grand challenges: improved recovery from tight/shale resources, net-zero operations, carbon capture, utilization, and storage (CCUS), geothermal energy, and digital transformation. Additionally, we identified a sixth “bonus” nontechnical challenge—education and advocacy, since we believe that more effective engagement with thought leaders outside our industry will be required to advance and deploy new technologies in all five of these areas. Table 2 summarizes the technical challenges and their impacts. We believe that this work will help the industry focus its R&D and technology efforts on the highest-value activities for both industry and society. We now summarize each of these new grand challenges. Improved Recovery From Tight/Shale Resources Notwithstanding the rapid growth of non-hydrocarbon energy sources and carriers, oil and natural gas demand are projected to continue rising through 2050 (EIA 2023). In the past 20 years, horizontal drilling and hydraulic fracturing were combined to extract hydrocarbons from unconventional shale resources, which helped us meet rising global oil demand. However, production from existing shale oil wells declines quickly, and ultimate recoveries are often less than 10%. To meet global demand, we must improve recovery with minimal environmental impact. Tight and shale oil reservoirs have unique challenges. For example, shale reservoirs are subject to clay swelling and formation damage. Permeabilities are ultra-low, often on the order of nano-Darcys, which leads to extremely low flow rates and to transport dominated by diffusion. Thus, hydraulic and natural fractures are necessary, and geomechanics/rock compaction plays an important role. Many traditional improved oil recovery (IOR) strategies are challenging in tight and shale reservoirs. The small pores make waterflooding techniques difficult, and the low permeability hampers well-to-well methods. Thus, single-well, huff-and-puff strategies are the most common IOR methods. Injectants include miscible and immiscible gases (CO2, CH4, and N2) and chemicals (surfactants, solvents, and nanoparticles). In addition, thermal methods may allow control of oil viscosity and pressurization of the reservoir.

Forecasting oil production for Oligocene C sequence, X field, Cuu Long basin using logistic growth model

Hydrocarbon production forecasting for the field lifetime in the short and long term is an important phase, the accuracy of this process plays a tremendous role in giving the decision of reasonable field management and development. In this article, the logistic growth models using the function MATLAB’s ‘nlinfit’ have been built to forecast oil production yield for the Oligocene C sequence, X field, Cuu Long basin. Thanks to the combination with the history matching process, the logistic growth model expressed high accuracy, the results of the model are very close to the actual production data with a relative error of 1,85%. The article analyzed and evaluated the production parameters of wells obtained when building logistic growth models such as the time at which half of the carrying capacity has been produced, the steepness of the decline of the rate, and the production rate of the wells at the forecast time. Without applying any improved oil recovery method, the decline of the rate of all wells approaches 100 bbl/d before reaching the validity period of the oil and gas contract. This is the basis for operators to establish and improve field development plans.

Assessing the Efficiency of Saturating Shale Oil Cores and Evaluating Hydrocarbon Gas Huff ‘n’ Puff Using Nuclear Magnetic Resonance

SummaryShale oil formations have a very low primary yield despite advances in multistage hydraulic fracturing and horizontal drilling. In so doing, gas huff ‘n’ puff (HnP), among other improved oil recovery methods, is implemented to recover more liquid hydrocarbons. Gas HnP has proven to be an effective recovery process in shales taking into account the fracture properties, fluid-fluid interactions, and gas diffusion controlled by matrix properties. However, a laboratory-scale understanding of the gas HnP mechanism proves challenging. At this scale, measuring saturation before and after HnP tests in a nonintrusive and nondestructive manner, and understanding rock properties that affect diffusion is essential. In addition to ascertaining how the multiscale pore systems and varying mineral composition of shales affect its evaluation. The nuclear magnetic resonance (NMR) is considered a suitable tool for estimating fluid content in shales and understanding rock/fluid interactions. Generally, synthetic oil samples are used on either outcrop core plugs or crushed reservoir samples for NMR measurements, which may not be representative of rock/fluid interactions in bulk shales.This study is focused on carrying out NMR tests with dead oil on reservoir core plugs at relatively different depths to determine an effective means of saturation and understand oil production due to gas HnP. Gas HnP experiments were performed at reservoir conditions (3,500 psi and 125°C) on representative rock types from the Lower Eagle Ford (LEF) interval. Low field NMR measurements were subsequently carried out on the LEF core plugs at different states: as-received, saturated, and after gas HnP. The results show that oil recovery due to gas HnP occurred mainly in the organic pores (OPs) and inorganic pores (IPs) and ranged from 48 to 56% of the oil-in-place with indications of adsorbed/trapped methane (CH4) and remaining heavier components. This plays a vital role in evaluating the HnP process to know the extent of invasion and remaining oil components.In saturating the core plugs, the optimum saturation period was found to be 2 weeks for the LEF shale at current conditions. This presents an idea of how long to saturate a shale oil core effectively before it is tested for gas HnP. On the basis of the impact of varying mineral composition on the recovery mechanism, we observed the LEF core plug with the highest clay content to have the least recovery. This is in line with a high T1/T2 ratio alluding to reduced mobility of fluids in the presence of clay minerals with relatively small sizes of clay porosity and adsorptive surfaces.

Experimental study of combined low salinity and surfactant flooding effect on oil recovery

A new generation improved oil recovery methods comes from combining techniques to make the overall process of oil recovery more efficient. One of the most promising methods is combined Low Salinity Surfactant (LSS) flooding. Low salinity brine injection has proven by numerous laboratory core flood experiments to give a moderate increase in oil recovery. Current research shows that this method may be further enhanced by introduction of surfactants optimized for lowsal environment by reducing the interfacial tension. Researchers have suggested different mechanisms in the literature such as pH variation, fines migration, multi-component ionic exchange, interfacial tension reduction and wettability alteration for improved oil recovery during lowsal injection. In this study, surfactant solubility in lowsal brine was examined by bottle test experiments. A series of core displacement experiments was conducted on nine crude oil aged Berea core plugs that were designed to determine the impact of brine composition, wettability alteration, Low Salinity Water (LSW) and LSS flooding on Enhancing Oil Recovery (EOR). Laboratory core flooding experiments were conducted on the samples in a heating cabinet at 60 °C using five different brine compositions with different concentrations of NaCl, CaCl2 and MgCl2. The samples were first reached to initial water saturation, Swi, by injecting connate water (high salinity water). LSW injection followed by LSS flooding performed on the samples to obtain the irreducible oil saturation. The results showed a significant potential of oil recovery with maximum additional recovery of 7% Original Oil in Place (OOIP) by injection of LS water (10% LS brine and 90% distilled water) into water-wet cores compared to high salinity waterflooding. It is also concluded that oil recovery increases as wettability changes from water-wet to neutral-wet regardless of the salinity compositions. A reduction in residual oil saturation, Sor, by 1.1–4.8% occurred for various brine compositions after LSS flooding in tertiary recovery mode. The absence of clay swelling and fine migration has been confirmed by the stable differential pressure recorded for both LSW and LSS flooding. Aging the samples at high temperature prevented the problem of fines production. Combined LSS flooding resulted in an additional oil recovery of 9.2% OOIP when applied after LSW flooding. Surfactants improved the oil recovery by reducing the oil-water interfacial tension. In addition, lowsal environment decreased the surfactant retention, thus led to successful LSS flooding. The results showed that combined LSS flooding may be one of the most promising methods in EOR. This hybrid improved oil recovery method is economically more attractive and feasible compared to separate low salinity waterflooding or surfactant flooding.

Optical measurements of oil release from calcite packed beds in microfluidic channels

To enable the study of improved oil recovery (IOR) from carbonate rock via laboratory experiments at the pore scale, we have developed a novel microfluidic chip containing a 3D packed bed of calcite particles. The utilization of fluorescently labeled water phase enabled visualization up to 1–2 particle layers with confocal laser scanning microscopy. Porosity and residual oil saturation (ROS) in this space are quantified from image stacks in the depth direction (Z). To obtain reliable average ROS values, Z stacks are captured at various XY locations and sampled over several time-steps in the steady state. All image stacks are binarized using Otsu’s method, subsequent to automated corrections for imperfect illumination and Z-drifts of the microscope stage. Low salinity IOR was mimicked using a packed bed that was initially saturated with water and then with mineral oil. Steady state ROS values showed no significant dependence on capillary number (Ca) in the range from 6 × 10–7 to 2 × 10–5. In contrast, chemical modification of the pore space via adsorption of water-extracted crude oil components yielded significantly higher ROS values, in agreement with a more oil-wet porous medium. These results indicate a good potential for using packed beds on a chip as an efficient screening tool for the optimization and development of different IOR methods.

Machine learning to reduce cycle time for time-lapse seismic data assimilation into reservoir management

Time-lapse (4D) seismic is widely deployed in offshore operations to monitor improved oil recovery methods including water flooding, yet its value for enhanced well and reservoir management is not fully realized due to the long cycle times required for quantitative 4D seismic data assimilation into dynamic reservoir models. To shorten the cycle, we have designed a simple inversion workflow to estimate reservoir property changes directly from 4D attribute maps using machine-learning (ML) methods. We generated tens of thousands of training samples by Monte Carlo sampling from the rock-physics model within reasonable ranges of the relevant parameters. Then, we applied ML methods to build the relationship between the reservoir property changes and the 4D attributes, and we used the learnings to estimate the reservoir property changes given the 4D attribute maps. The estimated reservoir property changes (e.g., water saturation changes) can be used to analyze injection efficiency, update dynamic reservoir models, and support reservoir management decisions. We can reduce the turnaround time from months to days, allowing early engagements with reservoir engineers to enhance integration. This accelerated data assimilation removes a deterrent for the acquisition of frequent 4D surveys.

The Feasibility of CO2 Injection for IOR in Shale Reservoirs

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 190277, “Mechanistic Study for the Applicability of CO2-EOR in Unconventional Liquids-Rich Reservoirs,” by Dheiaa Alfarge, SPE, Iraqi Ministry of Oil and Missouri University of Science and Technology, and Mingzhen Wei and Baojun Bai, Missouri University of Science and Technology, prepared for the 2018 SPE Improved Oil Recovery Conference, Tulsa, 14–18 April. The paper has not been peer reviewed. Improved oil recovery (IOR) methods for shale-oil reservoirs are considered relatively new concepts compared with IOR for conventional oil reservoirs. Different IOR methods—including CO2, surfactant, natural gas, and water injection—have been investigated for unconventional reservoirs using laboratory experiments, numerical simulation studies, and limited pilot tests. For a variety of reasons, CO2 injection is the most-investigated option. In this paper, numerical simulation methods of compositional models were incorporated with logarithmically spaced, locally refined, and dual-permeability reservoir models and local grid refinement (LGR) of hydraulic-fracture conditions to investigate the feasibility of CO2 injection in shale oil reservoirs. Introduction Advancements in horizontal drilling and hydraulic fracturing enabled unconventional liquids-rich reservoirs (ULRs), such as shale and source-rock formations and very tight reservoirs, to change the oil industry. ULRs are characterized by pore throats of micro- to nanomillimeters and an ultralow permeability. Although different studies re-ported that these ULRs contain billions of recoverable oil barrels in place, it is estimated that less than 7% of the original oil in place can be recovered during the primary depletion stage. Production sustainability is the main problem behind the low oil recovery in these unconventional reservoirs. Oil wells in ULRs typically start with a high production rate, but show a steep decline rate in the first 3–5 years of production life because of the rapid depletion in the natural fractures combined with a slow recharge from the rock matrix. The logical steps of academic research such as experimental investigation, simulation studies, and pilot tests for examining the applicability of different unconventional IOR methods have just begun in the past decade. Applying one of the feasible IOR methods in most oil and gas reservoirs should be mandatory to increase the oil-recovery factor. However, the mechanisms of IOR methods in unconventional reservoirs are not necessarily the same as those in conventional reservoirs. The primary characteristics of unconventional reservoirs that might impair performing IOR operations are low porosity and ultralow permeability. As a result, finding IOR methods that are insensitive to these very small pore throats is a priority.

Повышение эффективности методов интенсификации добычи нефти на основе учета глинистого фактора продуктивных пластов

Повышение эффективности методов интенсификации добычи нефти на основе учета глинистого фактора продуктивных пластов

Huff 'n' Puff Gas-Injection Pilot Improves Oil Recovery in the Eagle Ford

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 189816, “Huff ’n’ Puff Gas-Injection Pilot Projects in the Eagle Ford,” by B. Todd Hoffman, SPE, Montana Tech, prepared for the 2018 SPE Canada Unconventional Resources Conference, Calgary, 13–14 March. The paper has not been peer reviewed. The Eagle Ford formation has produced approximately 2 billion bbl of oil during the last 7 years, yet its potential may be even greater. Using improved oil-recovery (IOR) methods could result in billions of additional barrels of production. While a number of companies have field-tested an IOR method called huff ’n’ puff gas injection, most of the published results are from laboratory and modeling studies. This paper evaluates the results of these field tests and discusses the potential of the huff ’n’ puff method in the formation. Introduction The Eagle Ford formation, formed during the late Cretaceous, is a laminated calcareous organic rich shale. The shale was deposited in a low-energy anoxic marine shelf environment, which allowed for rapid deposition and burial of abundant organic material. The Eagle Ford is divided typically into two sections: the Upper, which was deposited during a regional marine regression, and the Lower, which was deposited during a transgressional period and tends to have more organic-rich black shale. The Eagle Ford is laterally continuous and spatially extensive throughout much of southern Texas. The matrix permeability of the reservoir is low enough that typical hydrocarbon migration is restricted, causing the oil-rich rocks to be stratigraphically higher than the gas-filled ones. Results of Previous Huff ’n’ Puff Pilot Projects The huff ’n’ puff process involves injecting a miscible gas into a well and then, after some time has passed, producing back from that same well. Data have been collected on seven pilot projects in the Eagle Ford that have been completed during the last 5 years. Data from four of these seven are discussed in this synopsis. All of the pilots used hydrocarbon gas, but the composition of the gas varied across the locations. In addition, all of the field trials used a huff ’n’ puff injection scheme. Pilot A. The first pilot was a single isolated well where the nearest offset producers were more than 2 miles away. This provided some assurance that the injected gas would not migrate to other wells. The oil rates for the well indicated a positive response to the process. Each cycle increased the production rate to approximately half of the well’s initial rate. Once the oil rate began to drop, another injection cycle was started. This is encouraging because not only the first cycle but also subsequent cycles were able to increase production.

Introducing a novel model and tool for design and performance forecasting of waterflood projects

Although the waterflood process as an improved oil recovery method for increasing production and pressure maintanence has been around and widely used for more than six decades, it still holds a significant portion of world oil production. In some giant international companies, e.x. BP, about half of their production is by waterflooding. On the other hand, forecasting the performance of waterflooding projects plays an important role in successful study, design and selection of the best candidates from company reservoir asset. A model which is fast, robus, easy to use and reasonably accurate with a few input data required is of great desire. In this paper we address this deficiency by presenting a novel analytical-base forecasting model/tool that does not rely on conventional numerical simulation.Using the concepts of material balance, momentum balance, segregated flow and fractional flux (F-C or F-Phi) we achieve an analytical approach for modeling waterflooding behavior in reservoir. We used a Koval flow-storage capacity (F-C) model in the current research because of its strength and wide applicability for both homogenous and heterogeneous permeable media. The validity of the forecasting model was investigated by matching numerous actual field, single well and also simulation results.History matching showed good agreement between field data and forecasting results. The forecasting model demonstrates a strong ability to forecast the oil saturation, recovery efficiency, cumulative oil recovery, oil cut and oil rate changes with time. In addition, predicting the recovery efficiency enables us to generate the volumetric efficiency change with time which is of great importance for studying and evaluating waterflood process. These valuable results are produced using a few input data required.

A Review of Improved-Oil-Recovery Methods in North American Unconventional Reservoirs

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 185640, “IOR Methods in Unconventional Reservoirs of North America: Comprehensive Review,” by Dheiaa Alfarge, Iraq Ministry of Oil and Missouri University of Science and Technology, and Mingzhen Wei and Baojun Bai, Missouri University of Science and Technology, prepared for the 2017 SPE Western Regional Meeting, Bakersfield, California, USA, 23–27 April. The paper has not been peer reviewed. In the complete paper, three stages of review have been combined to find out the applicability of the most-feasible improved-oil-recovery (IOR) methods in North American unconventional reservoirs. The study found that the integration of experimental, simulation, and pilot-test tools is the proper technique to accurately diagnose the most-feasible IOR methods in these reservoirs; these methods, as indicated by the research, include carbon dioxide (CO2), surfactant, and natural-gas injection. Review of Potential IOR Methods The ultratight matrix and high conductivity of natural fractures might be the two most important factors that impair success of conventional IOR methods. The authors conducted a critical review of more than 70 studies aiming to find applicability of different IOR methods in unconventional reservoirs. Chemical Methods. Generally, this category includes three methods: surfactant, polymer, and alkaline injection. Surfactant injection has the most-promising potential to improve oil recovery in North American unconventional reservoirs. These reservoirs are well-known as intermediate-wet to oil-wet; this type of rock affinity would prevent the aqueous phase from invading the matrix to displace the oil in place. Therefore, changing wettability and enhancing water imbibition through surfactant injection would be a good strategy to improve oil recovery. To the authors’ knowledge, there has been no study conducted to investigate the applicability of polymer- and alkaline-injection methods in these types of unconventional reservoirs. It is believed that injectivity problems are the primary reason that no investigation has been conducted on applying polymer in these reservoirs, although conformance problems are more dominant in the reported pilot tests. Also, injecting polymer into these reservoirs would plug the pore throats, which are very small in these plays. Investigation of alkaline potential in these reservoirs has also not been conducted by reported studies. This could be because there is no compatibility between this chemical agent and the mineral-composition complexity of these reservoirs. Smart-Waterflooding Technique. Recently, intensive studies have been conducted to investigate the effect on oil recovery of flooding with low-salinity water (LSW). It has been reported in different studies that maximum oil recovery can occur at optimal concentrations of salt for brine injected in cores (laboratory work) or in the field (simulation work). Wettability alteration and interfacial tension might be the main mechanisms behind the increment in oil recovery resulting from injection of LSW. However, the underlying mechanisms for wettability alteration are still controversial. Double-layer expansion and multicomponent ion exchange might be the main mechanisms behind wettability alteration because of the addition of salt. However, most of the reviewed studies focused on conventional reservoirs with high permeability.

Application of wettability alteration in the exploitation of unconventional liquid resources

Abstract This study investigates the wettability measurement methods suitable for unconventional reservoirs, summarizes the wettability characteristics of unconventional reservoir rocks, overviews the current state-of-the-art applications of wettability alteration in unconventional liquid resources, and recommends experimental procedures for evaluating effects of surfactants on wettability in unconventional liquid resources. Contact angle determination, NMR (Nuclear Magnetic Resonance) method and Zeta potential measurement are the most appropriate means to estimate wettability in unconventional reservoirs. Unconventional reservoirs exhibit mixed wettability from intermediate-wet to oil-wet. To this date, surfactants are the only ones experimentally reported on applications of wettability alteration in unconventional liquid resources. Altering wettability in unconventional liquid resources as an improved oil recovery method can be reached by adding surfactants to fracturing fluids. Stability test, wettability alteration experiment, interfacial tension experiment, spontaneous imbibition experiment, forced imbibition experiment and adsorption experiment can be used when evaluating the efficiency of surfactants in altering wettability and recovering hydrocarbons from unconventional reservoirs.

A database and workflow integration methodology for rapid evaluation and selection of Improved Oil Recovery (IOR) technologies for heavy oil fields

Conventional crude oil is the currently dominant but a non-renewable energy resource. Despite the development and improvement of alternative energy technologies, there is still a large gap between the capability of renewable energy systems to capture and reliably supply power, and the ever-increasing global energy demand requirements. Therefore, until technological innovations facilitate sufficient energy generation through alternative fuels, other means of sustaining crude oil production, such as Improved Oil Recovery (IOR) methods, must be systematically explored. Beyond increasing production of conventional oil, IOR methods can effectively facilitate the extraction of oil from unconventional reservoirs, such as heavy oil fields. This capability is of high strategic importance due to the considerably large size of global heavy oil reserves.There are several IOR technologies available, but each of them is suitable only for certain oil field types. The aim of this paper is to illustrate an alternative, low-cost, quick screening method which is competitive to more technically laborious and costly methods for selecting the most suitable technology for a given heavy oil extraction project, using a limited dataset. A two-stage technology screening method is hereby proposed: the first stage is based on previous project literature data evaluation, and the second stage is based on simple empirical oil production correlation methods (such as the Marx & Langenheim model) coupled with Ingen's RAVE (Risk and Value Engineering) and Schlumberger's PIPESIM software applications. The new method can achieve reasonably accurate results and minimise cost and time requirements during the preliminary stages of an oilfield development project, as evidenced via a comprehensive case study.

Field-scale investigation of different miscible CO2-injection modes to improve oil recovery in a clastic highly heterogeneous reservoir

Carbon dioxide flooding is considered one of the most commonly used miscible gas injections to improve oil recovery, and its applicability has grown significantly due to its availability, greenhouse effect and easy achievement of miscibility relative to other gases. Therefore, miscible CO2-injection is considered one of the most feasible methods worldwide. For long-term strategies in Iraq and the Middle East, most oilfields will need to improve oil recovery as oil reserves are falling. This paper presents a study of the effect of various CO2-injection modes on miscible flood performance of the highly heterogeneous clastic reservoir. An integrated field-scale reservoir simulation model of miscible flooding is accomplished for this purpose. The compositional simulator, Eclipse compositional, has been used to investigate the feasibility of applying different miscible CO2-injection modes. The process of the CO2-injection was optimized to start in January 2056 as an improved oil recovery method after natural depletion and waterflooding processes have been performed, and it will continue to January 2072. The minimum miscibility pressure was determined using empirical correlations as a function of reservoir crude oil composition and its properties. Four miscible CO2-injection modes were undertaken to investigate the reservoir performance. These modes were, namely the continuous CO2-injection (CCO2), water-alternating-CO2-injection (CO2-WAG), hybrid CO2-WAG injection, and simultaneous water and CO2-injection (CO2-SWAG) processes. All injection modes were analyzed in respect to the net present value (NPV) and net present value index (NPVI) calculations to confirm the more feasible CO2 development strategy. The results indicated that the application of CO2-SWAG injection mode of 2:1 SWAG ratio attained the highest oil recovery, NPV and NPVI, among the other modes. The achieved incremental oil recovery by this process was 9.174 %, that is 189 MM STB of the oil produced higher than the waterflooding case, 1.113 % (23 MMSTB of oil) in comparison with the CCO2-flooding case, 1.176 % (24.3 MMSTB of oil) in comparison with the hybrid CO2-WAG case and almost 0.987 % (204 MMSTB of oil) when compared with the CO2-WAG case. The results indicated that the application of CO2-WAG injection mode of 1.5:1 WAG ratio attained the highest oil recovery after the SWAG process.

Determination of minimum miscibility pressure in CO2-IOR projects with the aid of hybrid neuro-fuzzy system

Gas injection process is one of the most efficient improved oil recovery methods for conventional oil reservoirs. The efficiency of this process is strongly dependent on minimum miscibility pressure (MMP) which is usually determined through very expensive and time-consuming laboratory tests. So, this paper is concerned with the use of hybrid approach, combining particle swarm optimization and adaptive neuro-fuzzy inference system (ANFIS) with fuzzy c-means clustering technique, aimed at an estimation of injected gas-reservoir oil MMP. The hybrid proposed model makes ANFIS is practical in dealing with complex and high dimensional MMP problem. The process of model building is done by considering the reservoir temperature, crude oil composition, composition of injected CO2 as input parameters and corresponding CO2-oil MMP information as target parameter. The validity of proposed model has been successfully approved by comparing with results obtained by well-known empirical correlations in published literature. The results show that the proposed model significantly outperformed those four correlations with the lowest mean absolute error of 0.0099, the lowest root mean square error of 0.0174, and the highest coefficient of determination of 0.9823. Therefore, the proposed hybrid model can be applied as an alternative method to yield more accurate results in CO2-oil MMP estimation.

Potential of Low-Salinity Waterflood To Improve Oil Recovery in Carbonates: Demonstrating the Effect by Qualitative Coreflood

Summary Low-salinity waterflood (LSF) is a promising improved-oil-recovery (IOR) technology. Although, it was demonstrated that LSF is an efficient IOR method for many sandstone reservoirs, the potential of LSF in carbonate reservoirs is still not well-established because only a limited number of successful coreflood experiments are available in the literature. Therefore, the aim of this study was to examine the oil-recovery improvement by LSF in carbonate reservoirs by performing coreflood experiments. This paper proposes an experimental approach to qualitatively evaluate the potential of LSF to improve oil recovery and alter the rock wettability during coreflood experiments. The corefloods were conducted on core plugs from two Middle Eastern carbonate reservoirs with a wide variation of rock properties and reservoir conditions. Seawater (SW) and several dilutions of formation brine and SW were flooded in the tertiary mode to evaluate their impacts on oil recovery compared with formation-brine injection. In addition, a geochemical study was performed with PHREEQC software (Parkhurst and Appelo 1999) to assess the potential of calcite dissolution by LSF. The experimental results confirmed that lowering the water salinity can alter the rock wettability toward more water-wet, causing improvement of oil recovery in tertiary waterflood in plugs from the two reservoirs. Furthermore, SW is more-favorable for improved oil recovery than formation brine because injection of SW after formation brine resulted in extra oil production. This demonstrates that the brine composition plays an important role during waterflooding in carbonate reservoirs, and not only the brine salinity. It was also observed that oil recovery can be improved by injection of brines that cannot dissolve calcite on the basis of the geochemical modeling study. This implies that calcite dissolution is not the dominant mechanism of IOR by LSF. To conclude, this paper demonstrates that LSF has a good potential as an IOR technology in carbonate reservoirs. In addition, the proposed experimental approach ensures the verification of LSF effect, either it is positive or negative. However, further research is required to explore the optimum salinity and composition and the most-influential parameters affecting LSF response.

Simulation of Wettability Alteration by Low-Salinity Water Injection in Waterflooded Carbonate Cores

Low-salinity water injection is an emerging improved oil recovery technique due to its simplicity compared to other water based improved oil recovery methods. In this study, the wettability alteration option in the authors’ in-house simulator is used to history match and provide some insights in different seawater dilution cycles based on recently published corefloods. Two newly proposed methodologies to model dilution cycles are employed. The authors successfully modeled the experiments enhancing the wettability alteration model in the simulator using two different scaling factors. The study also revealed that the process is more sensitive to oil relative permeability compared to that of the water phase. A linear interpolation model for residual oil saturation (Sor) was proposed.

Application of Systematic Approach for Fast Oil Production Enhancement-Case Studies

Full field studies and master development plans are time consuming and expensive tasks for any company to find optimum improved oil recovery method. Fast oil production enhancement is a method applied over existing assets resulting in fast increase in oil production in less expensive way. This approach consists of five steps as identification of source of production decline problem through evaluation of diagnostic tests, prioritizing different solutions for treating the problem, conceptual integrated modeling of reservoir and wells, production network optimization and economic analysis.
 In this paper we elaborate and implement these five steps in an Iranian Oil Field with twenty wells. Firstly; we found that the production decline is due to poor well cleaning after stimulation and work over operation and also reservoir pressure decline leading to not having sufficient energy to push oil to the surface. Secondly; based on specifications of each well and pre-determined screening criteria; artificial lift methods were prioritized followed thirdly by conceptual modeling of first ranked artificial lift method which was electric submersible pump for first ranked wells. The fourth step was optimization of production network through sequential quadratic programming and lastly probabilistic economic analysis based on different ESP time to failure. The result of this study shows viability of application of ESP in this field in fast way.

A Critical Review of Improved Oil Recovery by Electromagnetic Heating

Conventional thermal improved oil recovery (IOR) methods, such as fire flooding and steam flooding, are commercially viable when properly applied. Every conventional method has one or more limitations. If the reservoir is shallow, the reservoir pressure may be too low to maintain a steam drive. If a reservoir is too deep, wellbore heat losses become excessive. Fireflood success depends on crude composition. Each of the conventional thermal methods requires sufficient reservoir transmissibility to achieve fluid Injection. Electro magnetic heating (EMH) has the potential for overcoming some of the limitations of conventional thermal methods such as environmental, cost and depth of operation. EMH as an IOR method to heating heavy crude by increasing its transmissibility, stimulation solution in asphaltenic wells, oily pollution removal, and so on, has environmental economical and technical advantages.