Effective Enhanced Oil Recovery Method Research Articles

A Review of Wettability Alteration by Spontaneous Imbibition Using Low-Salinity Water in Naturally Fractured Reservoirs

Analysis of fluid flow in naturally fractured reservoirs (NFRs), as a highly heterogeneous and complex system, requires a detailed study of the fracture-matrix interactions. The main process of fluid movement between the fracture and matrix is spontaneous imbibition (SI), which can occur in co/countercurrent fluid flow states. In addition, most carbonate rocks are fractured and non-water-wet, which can lead to low oil recovery. Wettability greatly affects the performance of the SI process. Injection of water or chemicals can be insufficient because fluids mostly pass through highly permeable fractures and lead to early breakthrough. Therefore, the wettability alteration mechanism should be applied in NFRs, and low-salinity water (LSW) injection is considered an effective enhanced oil recovery (EOR) approach. In this review, experimental and numerical studies of co/counter-imbibition are analyzed to show the importance of investigating the fracture-matrix interactions. In addition, the review shows the wettability effect on imbibition in fractured rocks. The review of experimental studies of LSW imbibition in fractured carbonates shows the possibilities for implementing an EOR method. However, the wettability alteration process during SI using LSW has not yet been studied, and no simulation models of co/countercurrent flows have yet been provided. Based on this review, more experimental studies are recommended to duplicate co/countercurrent imbibition using LSW. Advanced techniques such as CT scanning, MRI, and NTI can be used to reveal fluid distribution. Using experimental data, numerical models can be developed to characterize dynamic wettability alteration during co/countercurrent imbibition.

Machine-Learning Approach for Forecasting Steam-Assisted Gravity-Drainage Performance in the Presence of Noncondensable Gases.

Steam-assisted gravity drainage (SAGD) is an effective enhanced oil recovery method for heavy oil reservoirs. The addition of certain amounts of noncondensable gases (NCG) may reduce the steam consumption, yet this requires new design-related decisions to be made. In this study, we aimed to develop a machine-learning-based forecasting model that can help in the design of SAGD applications with NCG. Experiments with or without carbon dioxide (CO2) or n-butane (n-C4H10) mixed with steam were performed in a scaled physical model to explore SAGD mechanisms. The model was filled with crushed limestone that was premixed with heavy oil of 12.4° API gravity. Throughout the experiments, temperature, pressure, and production were continuously monitored. The experimental results were used to train neural-network models that can predict oil recovery (%) and cumulative steam–oil ratio (CSOR). The input parameters included injected gas composition, prior saturation with CO2 or n-C4H10, separation between wells, and pore volume injected. Among different neural-network architectures tested, a 3-hidden-layer structure with 40, 30, and 20 neurons was chosen as the forecasting model. The model was able to predict oil recovery and CSOR with R2 values of 0.98 and 0.95, respectively. Variable importance analysis indicated that pore volume injected, distance between wells, and prior CO2 saturation are the most critical parameters that would affect the performance, in agreement with the experiments.

The Performance of Engineered Water Flooding to Enhance High Viscous Oil Recovery

Low salinity/engineered water injection is an effective enhanced oil recovery method, confirmed by many laboratory investigations. The success of this approach depends on different criteria such as oil, formation brine, injected fluid, and rock properties. The performance of this method in heavy oil formations has not been addressed yet. In this paper, data on heavy oil displacement by low salinity water were collected from the literature and the experiments conducted by our team. In our experiments, core flooding was conducted on an extra heavy oil sample to measure the incremental oil recovery due to the injected brine dilution and ions composition. Our experimental results showed that wettability alteration occurred during the core flooding as the main proposed mechanism of low salinity water. Still, this mechanism is not strong enough to overcome capillary forces in heavy oil reservoirs. Hence, weak microscopic sweep efficiency and high mobility ratio resulted in a small change in residual oil saturation. This point was also observed in other oil displacement tests reported in the literature. By analyzing our experiments and available data, it is concluded that the application of standalone low salinity/engineered water flooding is not effective for heavy oil formations where the oil viscosity is higher than 150 cp and high oil recovery is not expected. Hence, combining this EOR method with thermal approaches is recommended to reduce the oil viscosity and control the mobility ratio and viscous to capillary forces.

Recovery of Nigerian Heavy Oil: Application of Steam Flooding

Aims: Nigeria has a lot of conventional and heavy oil resources. Although much of the conventional oil resources have been developed since independence, the heavy oil resources have remained underdeveloped due to low recovery based on primary production and consequently doubts about economic viability based on the current fiscal regime. This paper examines the application of Steam Flooding enhanced oil recovery (EOR) method to suitable Nigerian heavy oil reservoirs, seeks to develop a diagnostic model to predict the performance, evaluates the economics to determine the viability of the EOR method. The development of heavy oil will increase Nigeria’s oil reserves and production.
 Study Design: Data was collected for two heavy oil reservoirs from two oil companies in Nigeria following a Non-disclosure Agreement (NDA).
 Place and Duration of Study: Emerald Energy Institute, University of Port Harcourt Nigeria, 2016 - 2021.
 Methodology: The screening criteria of commercially effective EOR methods were applied to select steam flooding for the studied reservoirs. Design of Experiment (DoE) was used to evaluate the reservoirs and operating parameters and to determine their optimum values, which were then used to predict the performance of the reservoirs. The economics of the steam flood technique endorsed for the reservoirs considered were also evaluated using Discounted Cash Flow Analysis (DCFA).
 Results: These assessments confirmed that steam flooding technique was technically and economically viable for the heavy oil reservoirs considered. The steam flood was observed to have a good recovery efficiency of 24%, as against the waterflooding technique which had 13% OOIP and natural depletion of 9% for the offshore reservoir. For the onshore reservoir, the recovery efficiency was 20% for steam flood, and 4% for natural depletion. The economic analysis showed that even at a worst-case heavy oil price of US$15, the project was viable.
 Conclusion: Steam flooding is viable, can be applied to develop heavy oil reservoirs in Nigeria that meet the screening criteria, and thus increase national oil reserve and production.
 Recommendation: The fiscal policy should be adjusted, especially the petroleum profit tax from 85% to 50% as an incentive to operators and investors to embark on steam flooding and other EOR methods.

Conformance control study of preformed particle gels (PPGs) in mature waterflooded reservoirs: numerical and experimental investigations

Improving conformance control in reservoirs with a heterogeneous permeability distribution is the objective of many enhanced oil recovery (EOR) methods. In recent years, the injection of preformed Particle Gels (PPGs) is suggested as an effective EOR method to control the in-depth conformance of waterfronts. In this study, a new mathematical transport model of PPG injection in mature waterflooded reservoirs is developed. The model is based on the experimental results of PPG swelling ratio and entrapment analyses in a carbonate rock sample. The entrapment is considered as a function of the PPG-to-pore size ratio, fluid velocity, temperature, salinity, PPG concentration, and swelling ratio. The formulations of the resistance factor (RF) and residual resistance factor (RRF) are obtained from the injection experiment results at various fluid velocity and PPG concentrations. The entrapment model is coupled with the transport equations of the MATLAB Reservoir Simulation Toolbox (MRST). The model is validated by predicting the pressure drop changes during the 1D PPG injection experiments at three different flow rates. The validated model is then used to predict PPG transport behavior in several 3D field-scale scenarios. The sensitivity analysis results show that a higher recovery increment can be achieved when the reservoir permeability contrast is increased. There is an appropriate PPG-to-pore size ratio (i.e., DPT of 1.75) that can guarantee deep conformance control and avoid PPG washing out during post-waterflooding. Furthermore, the PPG concentration of 1750 ppm resulted in a significant entrapment in the porous medium.

Evaluation of the Effectiveness of Continuous Gas Displacement for EOR in Hydraulically Fractured Shale Reservoirs

SummaryThe main objective of this study is to analyze and describe quantitatively the effectiveness of continuous gas displacement as an enhanced oil recovery (EOR) process to increase production from multifractured shale oil reservoirs. The study uses CH4 continuously injected through horizontal wells parallel to the production wells as the displacement agent and investigates the effects of various attributes of the matrix and of the induced and natural fracture systems.This numerical simulation study focuses on the analysis of the 3D minimum repeatable element (stencil/domain) that can describe a hydraulically fractured shale reservoir under production. The stencil is discretized using a very fine (millimeter-scale) grid. We compare the solutions to a reference case that involves simple depressurization-induced production (i.e., without a gas drive). We monitor continuously (a) the rate and composition of the production stream and (b) the spatial distributions of pressure, temperature, phase saturations, and relative permeabilities.The results of the study indicate that a continuous CH4-based displacement that begins at the onset of production does not appear to be an effective EOR method for hydraulically fractured shale oil reservoirs over a 5-year period in reservoirs in which natural or induced fractures in the undisturbed reservoir and/or in the stimulated reservoir volume (SRV) can be adequately described by a single-medium porosity and permeability. Under these conditions in a system with typical Bakken or Eagle Ford matrix and fracture attributes, continuous CH4 injection by means of a horizontal well parallel to the production well causes a reduction in water production and an (expected) increase in gas production but does not lead to any significant increase in oil production. This is attributed to (a) the limited penetration of the injected gas into the ultralow-k formation, (b) the dissolution of the injected gas into the oil, and (c) its early arrival at the hydraulic fracture (HF; thus, short circuiting the EOR process by bypassing the bulk of the matrix), in addition to (d) the increase in the pressure of the HF and the consequent reduction in the driving force of production and the resulting flow. Under the conditions of this study, these observations hold true for domains with and without an SRV over a wide range of matrix permeabilities and for different lengths and positions (relative to the HF) of the gas injection wells.

Evaluation of the economic efficiency of the WAG process based on experimental data for one of the domestic oil fields

The challenge related to the need for an increase of the recovery factor concerns numerous mature, also domestic oilfields, including the most important ones – located in Main Dolomite formation. Satisfactory recovery factor can be ensured only through applying an effective enhanced oil recovery method (EOR). Water Alternating Gas (WAG), as one of the most effective EOR methods, has been tested in conditions characteristic for domestic deposits in carbonate formations. The results of experimental and simulation works carried out at the Oil and Gas Institute (INiG – PIB) indicate significant potential for the application of the WAG method in domestic conditions. An unquestionable advantage of the WAG method is the opportunity to utilize various types of gases, including flue/waste gas or low-energy natural gas. This issue deserves special attention because, as we know, the reduction in the emissions of gases involved in global warming is critical for the future of our planet. Their utilization in EOR methods, coupled with their safe storage in geological structures, constitute measures that reduce the environmental footprint of produced oil. In the article, based on the of experimental results, a simplified economic analysis of the utilization of four gas types in the form of acidic gases (carbon dioxide and its mixture with hydrogen sulfide) and natural gases (high and very high nitrogen content) in the WAG method was carried out. That allowed to identify the most economically optimal variants of the WAG method. The results showed that despite significantly lower effectiveness of nitrogen-rich natural gases in enhancing oil recovery (in the context of recovery factor), their application might be justified in economic terms. The selection of the optimal variant for enhancing recovery is strongly influenced by the assumed (current) cost of acquiring the injected media, and of course by the current (and forecasted) crude oil price.

Dynamic Contact Angle Reformulates Pore-Scale Fluid-Fluid Displacement at Ultralow Interfacial Tension

Summary Surfactant flooding is an effective enhanced oil recovery method in which the oil/water interfacial tension (IFT) is reduced to ultralow values (<0.01 mN/m). The microscopic fluid-fluid displacement has been extensively studied at high IFT (>10 mN/m). However, the microscopic displacement dynamics can be significantly different when the IFT is ultralow because the dynamic contact angle increases with the increase of the capillary number. In this study, surfactant flooding was performed and visualized in micromodels to investigate the dynamics of multiphase displacement at ultralow IFT. Although the micromodels used were strongly water-wet, the displacements of oil by surfactant solutions at ultralow IFT appeared as drainage. Furthermore, a macroscopic oil film was left behind on the surface, which indicates that a contact line instability occurred during displacements. The shape of the oil/water meniscus was determined by the balance between viscous forces and capillary forces. The meniscus can be significantly distorted by viscous forces at ultralow IFT. Therefore, the water-wet micromodel exhibits an oil-wet behavior at ultralow IFT, and the displacements of oil by surfactant solutions at ultralow IFT manifested as drainage rather than imbibition. The flow behavior is further complicated by the spontaneous formation of microemulsion during displacement. The microemulsion is mainly formed from the residual oil. The formation of a microemulsion bank made the surfactant solution discontinuous, with transport in the form of droplets in the microemulsion bank and displacement front. The novelty of this work is to reveal the effects of dynamic contact angle on the ultralow IFT displacement.

Low-Salinity Water, CO2, Alkaline, and Surfactant EOR Methods Applied to Heavy Oil in Sandstone Cores

Summary Generally, injecting carbon dioxide (CO2) into oil reservoirs is an effective enhanced oil recovery (EOR) technique that improves oil recovery, but injecting CO2 alone can be compromised by problems, such as early breakthrough, viscous fingering, and gravity override. The base CO2 injection method was improved by water-alternating-gas (WAG) injection with formation water (FW) and with low-salinity (LS) water (LSW), with LSW WAG achieving greater recovery than WAG with FW. This study investigates various combinations of standard waterflooding (with FW); flooding with nonmiscible gaseous CO2; WAG with CO2 and FW and/or LSW; foam flooding by adding a surfactant with CO2; adding an alkaline treatment step; and finally adding an LSW spacer between the alkaline step and the foam. These various EOR combinations were tested on Bartlesville sandstone cores (ϕ of approximately12%, K of approximately 20 md) saturated with a heavy oil diluted slightly with 10% heptane for workability. The ultimate outcome from this work is a “recipe” of EOR methods in combination that uses alkaline, LSW, surfactant, and CO2 steps to achieve recovery of more than 63% of the oil originally in place (OOIP) in coreflooding tests. Combining CO2 injection with surfactant [sodium dodecyl sulfonate (SDS)] to produce a foam resulted in better recovery than the WAG methods. Adding alkaline as a leading step appeared to precipitate the surfactant and lower recovery somewhat. Adding an LSW spacer between the alkaline treatment and the foam resulted in a dramatic increase in recovery. The various cases of alkaline + LSW spacer + surfactant + CO2 (each with various concentrations of alkaline and surfactant) achieved an average improvement of 7.71% of OOIP over the identical case(s) without the LSW spacer. The synergistic effect of the LSW spacer was remarkable. ERRATUM NOTICE:An erratum has been added to this paper detailing addition of an omitted reference.

Experimental investigation of driving brine water for enhanced oil recovery in tight sandstones by DC voltage

A large percentage of tight oil is trapped underground due to the lack of effective enhanced oil recovery methods. Direct current (DC) voltage flooding has become one of the emerging and promising methods for in situ enhanced oil recovery because of its economic and environmental advantages. Nevertheless, the effect of DC voltage on the enhanced oil recovery for tight sandstone reservoirs is still unclear. In this study, the effects of DC voltage, the concentration of brine water and flooding styles on enhanced oil recovery have been investigated. The experimental results show that there are an optimum DC voltage (∼10V) and an optimum concentration of brine water (∼0.7 mol/L). The oil displacement efficiency with the DC voltage (∼10V) increases by 50% compared with that the oil displacement efficiency of the conventional flooding with 0.1 mol/L sodium chloride. A low concentration of brine water would increase the oil displacement efficiency when the DC voltage is applied, while a high concentration of brine water would reduce the oil displacement efficiency. Moreover, the results of different flooding styles indicate that the sequential flooding obtains more oil than the simultaneous flooding and conventional flooding under the condition of a relatively high concentration of brine water. Several mechanisms of electrokinetics have been revealed in this study. Laboratory experiments indicate that electrokinetic flooding would be a promising enhanced oil recovery technique and needs to be investigated further.

Experimental Study on EOR Performance of Natural Gas Injection in Tight Oil Reservoirs

Gas injection is an effective enhanced oil recovery method in tight oil reservoirs. In the case of tight oil fields with sufficient natural gas supply, natural gas injection can significantly reduce the cost of operation, leading economic benefit. Natural gas flooding might be a promising EOR method for tight oil development. Based on the material and reservoir condition of a tight formation in Changqing Oilfield, this study conducted a series of natural gas injection experiments to evaluate the feasibility of natural gas injection after water flooding and analysed the influence of gas injection rate to EOR performance. Experiment results shows that natural gas injection can recover 20.8% more oil after water flooding. Sensitivity analyses indicates that natural gas injection had a higher oil recovery with low injection rate.

An evaluation on mechanisms of miscibility development in acid gas injection for volatile oil reservoirs

Produced gas containing the acid gas reinjection is one of the effective enhanced oil recovery methods, not only saving costs of disposing acid gases and zero discharge of greenhouse gases but also supporting reservoir pressure. The subsurface fluid from the Carboniferous carbonate reservoir in the southern margin of the Pre-Caspian basin in Central Asia has low density, low viscosity, high concentrations of H2S (15%) and CO2 (4%), high solution gas/oil ratio. The reservoir is lack of fresh water because of being far away onshore. Pilot test has already been implemented for the acid gas reinjection. Firstly, in our work a scheme of crude oil composition grouping with 15 compositions was presented on the basis of bottomhole sampling from DSTs of four wells. After matching PVT physical experiments including viscosity, density and gas/oil ratio and pressure–temperature (P–T) phase diagram by tuning critical properties of highly uncertain heavy components, the compositional model with phase behavior was built under meeting accuracy of phase fitting, which was used to evaluate mechanism of miscibility development in the acid gas injection process. Then using a cell-to-cell simulation method, vaporizing and/or condensing gas drive mechanisms were investigated for mixtures consisting of various proportions of CH4, CO2 and H2S in the gas injection process. Moreover, effects of gas compositions on miscible mechanisms have also been determined. With the aid of pressure-composition diagrams and pseudoternary diagrams generated from the Equation of State (EoS), pressures of First Contact Miscibility (FCM) and Multiple Contact Miscibility (MCM) for various gases mixing with the reservoir oil sample under reservoir temperature were calculated. Simulation results show that pressures of FCM are higher than those of MCM, and CO2 and H2S are able to reduce the miscible pressure. At the same time, H2S is stronger. As the CH4 content increases, both pressures of FCM and MCM are higher. But incremental values of MCM decrease. In addition, calculated envelopes of pseudoternary diagrams for mixtures of CH4, CO2 and H2S gases of varying composition with acid gas injection have features of bell shape, hourglass shape and triangle shape, which can be used to identify vaporizing and/or condensing gas drives. Finally, comparison of the real produced gas and the one deprived of its C3+ was performed to determine types of miscibility and calculate pressures of FCM and MCM. This study provides a theoretical guideline for selection of injection gas to improve miscibility and oil recovery.

Prevention of network destruction of partially hydrolyzed polyacrylamide (HPAM): Effects of salt, temperature, and fumed silica nanoparticles

Polymer flooding is one of the most effective enhanced oil recovery (EOR) methods. High temperature and a high salt content in oil reservoirs significantly decrease the performance of polymer flooding. In this work, the viscoelastic properties of a partially hydrolyzed polyacrylamide (HPAM) solution with and without salt (NaCl) and at two different temperatures (35 °C and 70 °C) were evaluated using rheological approaches. Two fumed silica nanoparticles (NPs) featuring different surface chemistries were used, and their ability to prevent destruction of the polymer network structure against salt addition and temperature increase was investigated. Linear rheological tests (frequency sweep, creep, and creep recovery) and nonlinear rheological tests (large amplitude oscillatory shear) were employed to evaluate the network structure of these systems. The results showed that either adding salt or increasing the temperature destroyed the mechanical integrity of the HPAM 3-dimensional elastic network. However, the introduction of both types of NPs at a sufficient concentration maintained the network structure of HPAM solutions in the small deformation region. In the large deformation region, it was shown that the extent of intra-cycle shear-thickening behavior in the HPAM solution (T = 35 °C and without any salt) decreased by incorporating salt or by increasing the temperature. Moreover, upon incorporating either of the NPs to the HPAM solution, the nonlinear viscoelastic behavior dramatically changed, and the critical strain (linear to nonlinear transition) decreased to a much lower strain amplitude. The outcomes of this study will help petroleum scientists to design more efficient EOR methods.

Cyclic CH4 Injection for Enhanced Oil Recovery in the Eagle Ford Shale Reservoirs

Gas injection is one of the most effective enhanced oil recovery methods for the unconventional reservoirs. Recently, CH4 has been widely used; however, few studies exist to accurately evaluate the cyclic CH4 injection considering molecular diffusion and nanopore effects. Additionally, the effects of operation parameters are still not systematically understood. Therefore, the objective of this work is to build an efficient numerical model to investigate the impacts of molecular diffusion, capillary pressure, and operation parameters. The confined phase behavior was incorporated in the model considering the critical property shifts and capillary pressure. Subsequently, we built a field-scale simulation model of the Eagle Ford shale reservoir. The fluid properties under different pore sizes were evaluated. Finally, a series of studies were conducted to examine the contributions of each key parameter on the well production. Results of sensitivity analysis indicate that the effect of confinement and molecular diffusion significantly influence CH4 injection effectiveness, followed by matrix permeability, injection rate, injection time, and number of cycles. Primary depletion period and soaking time are less noticeable for the well performance in the selected case. Considering the effect of confinement and molecular diffusion leads to the increase in the well performance during the CH4 injection process. This work, for the first time, evaluates the nanopore effects and molecular diffusion on the CH4 injection. It provides an efficient numerical method to predict the well production in the EOR process. Additionally, it presents useful insights into the prediction of cyclic CH4 injection effectiveness and helps operators to optimize the EOR process in the shale reservoirs.

АНАЛИЗ ЭФФЕКТИВНОСТИ ПРИМЕНЕНИЯ ГИДРАВЛИЧЕСКОГО РАЗРЫВА ПЛАСТА В УСЛОВИЯХ УРШАКСКОГО МЕСТОРОЖДЕНИЯ

Background Creation and implementation of an improved technology of oil deposit development and application of new enhanced oil recovery (EOR) methods, in particular, is the most important task facing oil industry. The authors review hydrofrac application under conditions of Urshak field. Aims and Objectives To analyze the results of applying treatment methods to the bottom hole zone in the well № 398 of Urshak field; to assess the performance of the well after treatments; to calculate the cost-effectiveness in terms of the impact of hydraulic fracturing technology. Methods The algorithm and computational methods for estimating technological effect of the bottom hole zone treatment are presented. Results The effectiveness of hydraulic fracturing was analyzed. It was proved that the technology was effective for the well № 398, and additional oil production made 16,221.16 t. Further use of hydraulic fracturing in Urshak field is recommended, as it is the most effective EOR method which allows to involve remote and low-permeability parts of reservoir in the filtering process. One should keep in mind that after the fracturing water cut has increased 1.87 times.

Selection methodology for screening evaluation of EOR methods

ABSTRACTThe choice of enhanced oil recovery (EOR) methods for specific reservoir conditions is one of the most difficult tasks for a reservoir engineer. Taber (Taber, 1980; Taber et al., 1997a,b) gave informative overview of EOR research history. He also offered technical screening guides for EOR nowadays known as Taber's tables. It should be noted that the approach recommended by Taber could not be taken as strong mathematical ranking of EOR methods. The authors propose an approach for EOR methods selection, based on fuzzy logic, possibility theory, and Bayesian inference mechanisms. Rankings were made by way of best EOR method selection for every criteria using fuzzy intervals comparison. Final correction of each EOR selection coefficient was performed by the generalized Bayesian inference mechanism. Application of this methodology for reservoir conditions of Alberta oil field, as well as the offshore field “Guneshli,” allowed for choosing the most effective EOR method, confirming the accuracy and feasibility of the proposed approach. Simple calculation (not more than five iterations) allows the automation of the process of selecting the most effective EOR method for a particular field.

Injection of Dilute Oil-in-Water Emulsion as an Enhanced Oil Recovery Method for Heavy Oil: 1D and 3D Flow Configurations

Unfavorable mobility ratio and reservoir heterogeneities contribute to water fingering phenomenon that leads to relatively low oil recovery factors in heavy oil fields. Experiments have shown that injection of oil-in-water emulsions can be used as an effective enhanced oil recovery (EOR) method, leading to substantial increase in the volume of oil recovered. Capillary-driven mobility alteration of the water phase by emulsion drops leads to not only more uniform macroscopic reservoir sweep, but also a pore scale reduction in the residual oil saturation. Despite recent developments, fundamental aspects of dilute oil-in-water emulsion flow through porous media and its application as an EOR method are still not clear. Experiments were performed in a 1D flow configuration using silica sandpacks and sandstone cores to determine the effect of permeability, emulsion drop size, dispersed phase concentration and size of injected emulsion bank on the volume of displaced oil, a crude heavy oil from Campos Basin (\(20^{\circ }\) API). X-ray computerized tomography images obtained during experiments in a Castlegate sandstone block in a 1/4 5-spot configuration revealed that emulsion acts both in the macroscale and pore scale, improving the macroscopic sweep and lowering the residual oil saturation.

Screening and optimisation of water/foam/gas injection EOR scenarios in a fractured reservoir

Primary sweep efficiency in carbonate reservoirs is low due to the low contribution of the matrix in production. Also, due to unfavourable mobility ratio, secondary recovery is not also effective. Hence, design and application of an effective enhanced oil recovery method is essential to improve recovery. Different methods such as water injection, gas injection, chemical injection, thermal, and a combination of these methods such as water alternating gas (WAG), simultaneous WAG (SWAG), selective simultaneous WAG (SSWAG), foam injection, and foam-assisted WAG (FAWAG) are applied to improve the recovery efficiency in naturally fractured reservoirs. In this paper, selection of the best EOR method and well pattern for a naturally fractured reservoir is studied to reach the highest net present value (NPV) and field oil recovery efficiency (FOE). Results showed that the FAWAG process in a five-spot well pattern with 22.7% oil recovery efficiency is the best technical and economical method.

Optimized well configuration of gas-assisted gravity drainage process

CO2 flooding has been widespread as one of the effective enhanced oil recovery methods by oil swelling and viscosity reduction. In spite of the efficiencies, the improvement of oil recovery falls short of expectation, especially for immiscible flooding because unswept zone by injected CO2 still exists at the bottom of the reservoir owing to gravity overriding phenomenon. Gas-assisted gravity drainage (GAGD) has been applied to use CO2 gravity overriding conversely and improve carbon capture sequestration efficiency. During GAGD, the area of swept zone by injected CO2 is affected greatly by injector length and producer well perforation design. The producer well perforation just below the injectors inhales CO2 downwardly, which interrupts gas spread from the top. Moreover, CO2 out of the injector far away from the top is affected by the downward pull of the producer more than buoyancy to the top; so, gas does not spread throughout the wide range of the area. The unswept zone existed below the injectors at the end of production can be solved by new perforations in the producer under the injectors. Results obtained would give not only the strength of GAGD but also a suggestion for an effective well length and perforation design of GAGD process.

Evaluation of Interfacial Tension Between SP Solution and Simsim Oil

Surfactant–polymer (SP) flooding has been proved to be an effective enhanced oil recovery method. Producing ultra-low interfacial tensions is an important mechanism relating to SP flooding for enhanced oil recovery. The interfacial tension between surfactant (PJS-1 and BE)/polymer solution and Simsim oil was evaluated in the work. The influence of surfactant and polymer concentration on interfacial tension between Simsim oil and these solutions is discussed. The interfacial tension between the oil and the surfactant solution reduces as the surfactant concentration increases. In the same concentration of surfactant, the interfacial tension between the surfactant solution and the oil becomes larger when the polymer was added in the solution.