Mature Oil Reservoirs Research Articles

An Ultra-Stable Polysaccharide Gel Plugging Agent for Water Shutoff in Mature Oil Reservoirs

Polyacrylamide-based gel plugging agents are extensively utilized in oilfields for water shutoff. However, their thermal stability, salt tolerance, and shear resistance are limited, making it difficult to achieve high-strength plugging and maintain stability under high-temperature and high-salinity reservoir conditions. This study proposes the use of chitosan (CTSs), a polysaccharide with a rigid cyclic structure, as the polymer. The organic cross-linker N,N’-methylenebisacrylamide (MBA) is incorporated via the Michael addition reaction mechanism to develop an ultra-stable, organically cross-linked chitosan gel system. The CTS/MBA gel system was evaluated under various environmental conditions using rheological testing and thermal aging to assess gel strength and stability. The results demonstrate significant improvements in gel strength and stability at high temperatures (up to 120 °C) and under high-shear conditions, as the increased cross-linking density enhanced resistance to thermal and mechanical degradation. Rapid gelation was observed with increasing MBA concentration, while pH and salinity further modulated gel properties. Scanning electron microscopy revealed the formation of a three-dimensional microstructure after gelation, which contributed to the enhanced properties. This study provides novel insights into optimizing polymer gel performance for the petroleum industry, particularly in high-temperature and high-shear environments.

A coupled displacement-pressure model for elastic waves induce fluid flow in mature sandstone reservoirs

Elastic (seismic) wave stimulation is considered one of the unconventional enhanced oil recovery (EOR) methods. Increasing water quantity in the high permeability layer of a mature oil reservoir is highly challenging and can significantly decrease the ultimate recovery due to the reservoir heterogeneity. Using seismic waves can be considered low-cost, environmentally friendly, and illuminates the entire reservoir size compared to conventional EOR methods. A numerical model is developed by extending the Quintal approach for seismic attenuation due to wave-induced fluid flow (WIFF) to incorporate capillary pressure in partially saturated porous media and shift undrained boundary conditions to exclude external flow stress for drained boundary conditions. Therefore, the fluid distribution due to the capillary effect makes the developed finite element method (FEM) u-p model more widely applicable for oil recovery in mature reservoirs. A two-layer partially saturated media was subjected to compressive seismic stress at low frequency (3 Hz). The results indicated that the vertical displacement gradients of the bottom and upper layers decline with excitation time for both fully and partially saturated media. On the other hand, partially saturated pore pressure gradients of both the upper and bottom layers have higher amplitudes with excitation time than fully saturated pore pressure gradients due to the influence of capillar pressure. The cumulative crossflow oil volume for 180 days of continuous stimulation was 1176 bbl, 1032 bbl, and 648 bbl in low permeability layers: 200 md, 100 md, and 50 md, respectively. Therefore, the developed model has the potential for field-scale EOR applications. The study also suggests coupling elastic EOR with CO2 flooding to recover more oil due to increasing fluid mobility and relative permeability to oil in low-permeability reservoirs or tight formations.

Study on organic carbon in medium-low mature shale oil reservoirs rich in type II kerogen: Oxidation behavior, thermal effect, and kinetics

In-situ combustion technology (ISC) was a potential technology for efficient development of medium–low maturity shale oil reservoirs. Clarifying the exothermic behavior of organic carbon oxidation will be beneficial for better control of ISC processes. In this work, the organic carbon composition, type II kerogen and residual oil, were separated and extracted from the shale samples of typical medium–low maturity shale oil reservoirs in the Ordos Basin, China. The synchronous thermal analyzer and mass spectrometry (STA-MS), Fourier transform infrared spectroscopy (FTIR), and ROCK-EVAL VI were used to study the products, heat release, and functional group changes of type II kerogen, residual oil, and shale during the oxidation process. The results indicated that the oxidation heat release of shale mainly came from the oxidation reaction between its residual oil and type II kerogen, but the oxidation heat release range of shale was relatively lagging compared to the single residual oil or type II kerogen affected by rock debris. Secondly, under atmospheric pressure, the type II kerogen experiences obviously higher heat release than residual oil and heavy oil, indicating its superior potential of in-situ heat release. In addition, the major productions that CO, H2O, SO2, and CO2 were quantitatively characterized, with CO2 having the highest production of 882.25 mg/g. Furthermore, combined with the molecular weight, an oxidation reaction equation of type II kerogen was constructed. Finally, the oxidation kinetics parameters of type II kerogen, residual oil, and shale were determined using Friedman and Ozawa-Flynn-Wall (OFW) models. It was found that the activation energy of shale was higher than II kerogen and residual in low temperature oxidation (LTO) and fuel deposition (FD) stages. This may be due to the joint reaction between kerogen and residual oil, thus exacerbating the challenge of shale in-situ ignition. However, due to the catalytic effect of rock debris, the activation energy of shale was lower than LTO in high temperature oxidation (HTO) stage, indicating that once fuel deposition was completed, organic carbon will undergo stable combustion. This study has theoretical guidance for the numerical simulation research of ISC development technology of maturity-low shale oil reservoirs.

Evaluation of Potential of CO2-Enhanced Oil Recovery (EOR) and Assessment of Capacity for Geological Storage in a Mature Oil Reservoir within Upper Assam Basin, India

Evaluation of Potential of CO₂-Enhanced Oil Recovery (EOR) and Assessment of Capacity for Geological Storage in a Mature Oil Reservoir within Upper Assam Basin, India

An Experimental Investigation of Surfactant-Stabilized CO2 Foam Flooding in Carbonate Cores in Reservoir Conditions

Carbon dioxide (CO2) injection for enhanced oil recovery (EOR) has attracted great attention due to its potential to increase ultimate recovery from mature oil reservoirs. Despite the reported efficiency of CO2 in enhancing oil recovery, the high mobility of CO2 in porous media is one of the major issues faced during CO2 EOR projects. Foam injection is a proven approach to overcome CO2 mobility problems such as early gas breakthrough and low sweep efficiency. In this experimental study, we investigated the foam performance of a commercial anionic surfactant, alpha olefin sulfonate (AOS), in carbonate core samples for gas mobility control and oil recovery. Bulk foam screening tests demonstrated that varying surfactant concentrations above a threshold value had an insignificant effect on foam volume and half-life. Moreover, foam stability and capacity decreased with increasing temperature, while variations in salinity over the tested range had a negligible influence on foam properties. The pressure drop across a brine-saturated core sample increased with an increasing concentration of surfactant in the injected brine during foam flooding experiments. Co-injection of CO2 and AOS solution at an optimum concentration and gas fractional flow enhanced oil recovery by 6–10% of the original oil in place (OOIP).

Lattice Boltzmann simulation of cross-linked polymer gel injection in porous media

This study addresses the critical challenge of excessive water production in mature oil and gas reservoirs. It focuses on the effectiveness of polymer gel injection into porous media as a solution, with an emphasis on understanding its impact at the pore scale. A step-wise Lattice Boltzmann Method (LBM) is employed to simulate polymer gel injection into a 2D Berea sample, representing a realistic porous media. The non-Newtonian, time-dependent characteristics of polymer gel fluid necessitate this detailed pore-scale analysis. Validation of the simulation results is conducted at each procedural step. The study reveals that the methodology is successful in predicting the effect of polymer gel on reducing permeability as the gel was mainly formed in relatively larger pores, as it is desirable for controlling water cut. Mathematical model presented in this study accurately predicts permeability reductions up to 100% (complete blockage). In addition, simulations conducted over a wide range of gelation parameters, TD_factor from 1 to 1.14 and Threshold between 0.55 and 0.95, revealed a quadratic relationship between permeability reduction and these parameters. The result of this research indicates LBM can be considered as promising tool for investigating time-dependant fluids on porous media.

Gas-phase reaction of CH4 and H2S – Evidence from pyrolysis experiments and case study from the Sichuan Basin

The application of routine geochemical analyses for identification of dry natural gas sources and post generation processes poses a challenge as its hydrocarbon composition is typically dominated by CH4 (∼≥99 %) while the presence of non-hydrocarbons may be limited. In particular, the possibility of dry gas interaction with H2S at reservoir conditions (low temperatures, high pressures, millions of years residence time) is not established as previous studies of this reaction focused on conditions typical for industrial reactors (high temperature, ambient pressure, residence time of seconds). To address these issues, we studied the molecular and isotopic (δ34S) composition of volatile organic sulfur compounds (VOSC) formed during pyrolysis experiments between CH4 and H2S at 360 °C (4–96 h), reaching %Ro equivalent of 0.80–1.25 which represents thermally mature oil and gas reservoirs. The results demonstrated that methanethiol (MeSH) is the main product of the reaction, while its δ34S value suggest equilibrium isotopic effect with its parent H2S. Subsequent analysis of the molecular and isotopic (δ13C, δ2H, δ34S) composition of thermogenic, H2S containing, dry natural gases from the Jiannan gas field in China revealed the presence of short thiols and sulfides dominated by MeSH. The δ34S of the VOSC identified suggests they all formed by gas-phase reaction of alkanes (mainly CH4) with the associated H2S.This study demonstrates the applicability of VOSC as a proxy for identification of interaction between H2S and dry gas and identification of H2S sources within a gas reservoir or a basin.

Evaluation of Novel Preformed Particle Gel System for Conformance Control in Mature Oil Reservoirs.

To address challenges associated with excessive water production in mature oil reservoirs, this study introduces a carboxymethyl cellulose (CMC)-based material as a novel preformed particle gel (PPG) designed to plug excessive water pathways and redistribute the subsequent injected water toward unswept zones. Through microwave-assisted grafting copolymerization of CMC with acrylamide (AM), we successfully generated multi-sized dry particles within the range of 250-800 µm. Comprehensive analyses, including Fourier-transform infrared spectroscopy (FTIR) and scanning electron microscopy (SEM), have confirmed the chemical composition and morphology of the resulting carboxymethyl cellulose-grafted crosslinked polyacrylamide (CMC/PAMBA). Swelling kinetics and rheology tests were conducted to confirm the ability of this novel PPG system to perform at different reservoir conditions. The results of core flooding experiments showed that the CMC/PAMBA PPG is capable of plugging open fractures with a water breakthrough pressure gradient of up to 144 psi/ft. This preformed particle gel (PPG) system was designed specifically for application in Middle East reservoirs, which are distinguished by high salinity and elevated temperature levels. This PPG system is able to swell up to 10 times its original size in seawater and maintain a strength of about 1300 Pa at a temperature of 80 °C. Further optimization is conceivable to enhance injection efficiency and achieve superior plugging outcomes.

الاستخلاص المعزز للنفط بالميكروبات في مكامن النفط

Microbial enhanced oil recovery (MEOR), characterized with the virtues of low cost and environmental protection, reflects the prevalent belief in environmental protection, and is attracting the attention of more researchers. Nonetheless, with the prolonged slump in global oil prices, how to further reduce the cost of MEOR has become a key factor in its development. This paper described the recent development of MEOR technology in terms of mechanisms, mathematical models, and field application, meanwhile the novel technologies of MEOR such as genetically engineered microbial enhanced oil recovery (GEMEOR) and enzyme enhanced oil recovery (EEOR) were introduced. The paper proposed three possible methods to decrease the cost of MEOR: using inexpensive nutrients as substrates, applying a mixture of chemical and biological agents, and utilizing crude microbial products. Additionally, in order to reduce the uncertainty in the practical application of MEOR technology, it is essential to refine the reservoir screening criteria and establish a sound mathematical model of MEOR. Eventually, the paper proposes to combine genetic engineering technology and microbial hybrid culture technology to build a microbial consortium with excellent oil displacement efficiency and better environmental adaptability. This may be a vital part of the future research on MEOR technology, which will play a major role in improving its economic efficiency and practicality. Microbial Enhanced Oil Recovery (MEOR) is a biological-based technology involving the manipulation of functions or structures within microbial environments present in oil reservoirs. The primary objective of MEOR is to improve the extraction of oil confined within porous media, while boosting economic benefits. As a tertiary oil extraction technology, MEOR enables the partial recovery of the commonly residual 2/3 of oil, effectively prolonging the operational lifespan of mature oil reservoirs. Keywords: Microbial enhanced oil recovery, MEOR mechanisms, theory, Biopolymers, Field trials.

Pore Pressure Diffusion Waves Transmission in Oil Reservoir

Recent studies on seismic wave excitation have revealed that mesoscopic wave-induced fluid flow (WIFF) is a process that attenuates the compressional (P) waves in reservoir rocks at seismic frequency bands. Fluid flow and Biot's slow diffusion (pressure) waves are produced when the P-waves create fluid-pressure gradients at mesoscopic-scale heterogeneities. Pore pressure continuity can be sustained by converting seismic energy into diffusion waves that diffuse away from the interfaces or boundaries. Biot’s diffusion waves fail to comply with a square-law approach because of their slow propagation velocity and higher attenuation. It is currently uncertain how to characterize reservoir fluids in mature oil reservoirs during seismic wave-based enhanced oil recovery (EOR). A simplified 1D two-layer reservoir model was investigated in this study. The findings demonstrate that diffusion wave propagation in oil reservoirs is frequency-dependent and affected by rock permeability and fluid viscosity. At a formation layer interface, it was discovered that diffusion waves obeyed the accumulation-depletion relationship rather than the reflection-refraction approach. Therefore, pore pressure diffusion waves can characterize reservoir fluid during seismic EOR and monitor the CO2 front in depleted reservoirs during storage for CCUS projects. It can also detect shale gas transport in low permeability layers and identify the propagation of fractures during gas/oil recovery.

Development and Application of New Multifunctional Foaming Agents to Enhance Production in Oil Wells

Summary Maintaining or increasing production from wells in mature oil reservoirs with high pressure, temperature, brine hardness, and salinity is a significant technological and economic challenge. These wells usually produce with a high gas-oil ratio and large water cuts and often operate with gas lift systems. This work focuses on the development and application of new multifunctional foaming agents (MFAs) to enhance production from oil wells under these conditions. The MFAs were developed based on molecular design and laboratory studies, which demonstrated that they can be used with water cuts exceeding 30% and in the presence of salinity and hardness levels up to 400,000 ppm and 180,000 ppm, respectively. Furthermore, these agents remain stable at temperatures up to 180°C. The production/lift efficiency of the MFAs was evaluated using two novel dynamic laboratory methods that are conducted close to the wellhead and at downhole conditions of temperature and pressure, respectively. The experimental results demonstrate a significant enhancement in the liquid production efficiency, with some cases showing an increase from no production to as much as 44% when the MFAs were used. The laboratory tests were also used to optimize the MFA type and concentration in the design of a field application. The field test was conducted in three oil wells with water cuts ranging from 40% to 90%, depths exceeding 5000 m, bottomhole temperature around 150°C, and brine hardness and salinity up to 180,000 ppm and 310,000 ppm, respectively. This is the first reported field test of MFAs for production enhancement under such challenging conditions. The MFA was coinjected with gas lift via the annulus. The MFA mixed with reservoir fluids in the tubing and generated foam downhole with concentrations ranging from 160 ppm to 750 ppm. The rheological properties of the foam were designed to prevent pressure losses and the formation of stable foam or emulsions at surface facilities. The field tests demonstrated that the MFA was able to increase oil production at a fixed gas lift injection flow rate. Alternatively, it was able to reduce lift gas consumption while maintaining or even increasing the original oil production.

Seismic Wave Excitation of Mature Oil Reservoirs for Green EOR Technology

Elastic wave-based oil mobilization of residual oil in heterogeneous reservoirs is a viable, low-cost, and green technology method of enhanced oil recovery (EOR). Applications for elastic (seismic) waves at the reservoir scale are currently in the preliminary stages of investigation and development. We employ a two-layer numerical finite element method (FEM) in this research to investigate the possibility of effective propagation of seismic waves in the low permeability area of a mature oil reservoir when seismic stress load is delivered to the rock matrix via a downhole source. The purpose of this research is to evaluate the potential of fluid and rock matrix displacement amplitudes for crossflow generation in a mature oil reservoir. In a low permeability formation, the numerical results reveal that, as the observation radius approaches the reservoir boundary, the rock matrix time-domain displacement performs better as a wave propagation parameter than the pore fluid displacement. However, crossflow oscillations at a peak mesoscopic frequency of 3.0 Hz produce an instantaneous oil transfer rate (recovery rate) of 2.5% (bypassed oil) from the low permeability area. This method can be used in combination with water flooding to recover more oil from both high and low-permeability areas. Mesoscopic attenuation frequency can therefore be utilized as one of the indicators to assess oil recovery in heterogeneous oil reservoirs.

Application of CCUS in India: Designing a CO2 EOR and storage pilot in a mature field

Numerous mature oil and gas reservoirs around the world, along with added financial benefit, present a tremendous benefit of CO2 EOR and storage, especially in the regions where tax benefits and policies related to the CCS is limited. This work presents the first effort of CO2 EOR and storage in a mature oil field in India through a comprehensive application of laboratory study, reservoir static modeling, dynamic simulation, pilot design, and techno-economic sensitivity analyses. Through this case study, the technical feasibility of CO2 EOR and associated storage was assured for the first time through a novel approach of combining various subsurface and surface data with laboratory analyses. Almost no analog was available for CCUS on the same-age rock from a young thrust belt setting. The various vintages of core to seismic scale data posed a great challenge for effective integration. The solution approach to these issues included combining flow physics, fluid chemistry, geological concepts and digital modeling with practical engineering data analyses. Temporal change of oil composition in this reservoir due to the long production history had created some challenges for determination of CO2 miscibility. It was estimated through the lab study and modeling that the miscibility can be achieved near 3000 psi due to its altered oil composition resulted by years of production. To arrest the reservoir pressure decline, a pre-EOR water injection was identified as an immediately need to re-pressurize the reservoir and achieve miscibility of injected CO2. Comprehensive analysis of various subsurface and surface data integrating geoscience and engineering techniques have allowed for a consistent and applicable 3D description of reservoir, which was critical to identify suitable areas with appropriate remaining oil saturation, chemistry, and reservoir pressure. The history matching-calibrated-simulation model was utilized to evaluate the performance of various development scenarios of the identified area. Specifically, CO2 injection in a sector of geological model was performed using Todd-Longstaff miscible flood scheme. Upon comparing the proposed scenarios, a CO2 injection pilot in Pattern-1 was identified, with one injector and three producers over ∼60 acres area. This pilot uses 150 Metric Ton/day (MT/D) of CO2 captured and processed from an existing facility and transported about 70 km to the field location. The CO2 will be injected continuously into this pilot area for 5 years, and the well switches back to water injection afterward. Around 1.1 MMSTB incremental oil will be recovered in next 10 years, corresponding to 11.7% of OOIP in the flooded area. Up to 268,275 MT of CO2 will be sequestered in the reservoir. The learnings from this first ever study of its kind in India set the benchmark for data analysis, integration, and case specific approaches. The success and knowledge base from this endeavor will tremendously help and encourage further expansion of CCUS activities in India.

Modelling minimum miscibility pressure of CO2-crude oil systems using deep learning, tree-based, and thermodynamic models: Application to CO2 sequestration and enhanced oil recovery

The energy demand is still increasing across the globe, while environmental concerns about global warming effect and greenhouse gases have augmented recently. CO2 injection into mature oil reservoirs is an interesting operation that could help us supply the uprising demand while saving the environment. Having accurate knowledge about CO2 minimum miscibility pressure (MMP) is of utmost importance in designing a successful operation. This study mainly focuses on proposing several tools based on powerful tree-based and deep learning algorithms for estimating the MMP of CO2-crude oil system based on an extensive databank. The models employed in this study include extreme gradient boosting (XGBoost), categorical boosting (CatBoost), light gradient boosting machine (LGBM), random forest (RF), deep multi-layer neural network (deep MLN), deep belief network (DBN), and convolutional neural network (CNN). The models were trained and verified using 310 data points. Along with intelligent models, seven popular empirical correlations and two computational approaches, which are based on thermodynamics, were utilized to be compared with the proposed models. The outcomes expressed that the CatBoost model could estimate CO2 MMP values, using mole percent of volatile (C1 and N2) and intermediate (CO2, H2S, and C2–C5) fractions of oil, the average critical temperature of injection gas (Tcave), reservoir temperature (Tres), and molecular weight of C5+ fraction of oil (MWc5+) as input variables, with a total AARD of 1.34 %. Moreover, the variable impact examination showed that reservoir temperature greatly affects the MMP predictions. Finally, the Leverage approach verified the reliability of the databank and wide applicability domain of the developed CatBoost model spotting 5 outlier points (out of 310 points) only. The findings of this communication shed light on the high accuracy and reliability of CatBoost model in estimating CO2 MMP in a wide range of operational conditions.

Geothermal resource exploration in South America using an innovative GIS-based approach: A case study in Ecuador

Integrating geothermal energy contributes to a sustainable energy transition in South American countries. Geothermal energy is a non-variable and renewable resource that can be used for baseload power generation to reduce the overdependence on fossil fuel and hydropower plants. There is a vast and untapped geothermal potential in South America. Nevertheless, multiple barriers, including lack of geological, hydrogeochemical and geophysical background and outdated regional studies have blocked the development as it should be. Thus, this study aims to update and identify promising areas for further geothermal exploration through a favourability map implemented in a GIS-based model for Ecuador as a case study. The results show that approximately half (49.2%) of the national territory of Ecuador has promising areas to explore and develop geothermal systems along the Andean and South-west coast. New zones were identified, which contribute to increasing the national inventories of geothermal energy. Also, the Northern Amazon region presents mature oil fields and reservoirs close to their productive life. Thus, geothermal energy systems may help transition the petroleum industry into a clean energy provider. This research contributes to the needed improvement of existing geothermal resource inventories. The robustness of the proposed GIS-based model has been tested. Thus, it allows the analysis and combination of available open geodata in an effective, low-cost method, and even under a scenario of scarce data availability, to support decision-makers, researchers, or stakeholders, and guide geothermal exploration programs at a national level.

Infill well placement optimization for secondary development of waterflooding oilfields with SPSA algorithm

A significant amount of bypassed oil resources often remain in a mature waterflooding reservoir because of non-uniform sweep caused by natural complexities of a subsurface reservoir and improper management of the reservoir. Infill drilling is one of the most attractive options for increasing oil recovery in consequence of its operational simplicity, low risk and promising results. Determining optimal infill well placements in heterogeneous mature reservoirs is a critical and challenging task that has a significant impact on the recovery performance and economic revenue of subsurface remaining oil resources. An integrated framework is constructed to attain best-obtained optimal location and completion of infill wells in multi-layer mature oil reservoirs. The placement of an infill vertical well is parameterized in terms of two sets of variables that define the location and completion respectively. A variant of SPSA algorithm is used to solve the defined optimization problem. The performance of the proposed algorithm is first tested for the joint optimization of well location and completion of an injection well using a synthetic model. The results show that the algorithm with average SPSA gradients outperforms the single SPSA gradient method both in solution and convergence rate. Besides, there are two plateaus on the performance curve of all algorithms: on the first plateau, each algorithm is approaching to its optimal well location with relatively little change on the completion parameters, while on the second plateau, each algorithm obtains the corresponding optimal completions. A complex heterogeneous reservoir model is then constructed by using the data of a mature oil reservoir in Shengli Oilfield in China to design an optimal 10 years’ infill drilling program. Four vertical production wells are placed in the oil-rich regions and both simultaneous and sequential algorithms are tried to obtain their optimal locations and completions. The performances of simultaneous joint optimization and sequential joint optimization are compared and as a result it is recommended to use sequential joint optimization as the optimization algorithm in the integrated framework.

Experimental Core Flooding Investigation of New ZnO-γAl2O3 Nanocomposites for Enhanced Oil Recovery in Carbonate Reservoirs.

Generally, crude oil production in mature oil reservoirs is difficult. In this regard, some nanoparticles have been used to upgrade injected water into oil reservoirs. These nanoparticles can be used in a variety of injectable waters, including smart water (SMW) with special salinity. This study aims to evaluate the performance of the injection of SMW with ZnO-γAl2O3 nanoparticles in enhanced oil recovery (EOR). The performance of SMW with ZnO-γAl2O3 nanoparticles in regard to contact angle (CA), interfacial tension (IFT) reduction, and oil production with core flooding tests was investigated. The newly prepared ZnO-γAl2O3 structure was characterized by energy dispersive X-ray (EDX), Fourier transform infrared (FT-IR) spectroscopy, transmission electron microscopy (TEM), scanning electron microscopy (SEM), and X-ray diffraction (XRD) analyses in this research. The effects of different concentrations of nanofluids on zeta potential (ZP) and conductivity were investigated. The ZP test confirmed the results of the stability tests of the developed nanofluids in water-based solutions. After the introduction of ZnO-γAl2O3 nanoparticles into the formation of brine and SMW solutions, oil-water (O/W) IFT was reduced. Based on the results, the IFT decreased more when nanoparticles and ions were present in the system. The results of the present study showed that at the concentration of SW+300 ppm ZnO-γAl2O3, the IFT value reached 11 mN/m from 27.24 mN/m. The results of the CA tests showed that improving the capabilities of salt water in the presence of nanoparticles has resulted in a very effective reduction. Also, in this regard, very hydrophilic wettability was achieved using SMW with stable nanoparticles. Moreover, the results of the present study showed that at the concentration of SMW+300 ppm ZnO-γAl2O3 nanoparticles, the CA value reached 31 from 161°. In the end, the solution of SW+300 ppm ZnO-γAl2O3 improved the OR by 15 and 24%. This research indicated that it is possible to develop and implement different nanoparticles by combining SMW to manage reservoir rock wettability and maximize OR from carbonate reservoirs. Thus, this combination as an effective agent could significantly increase reservoir sweep efficiency. Thus, as a result, using the established hybrid technique has distinct advantages over using SMW flooding alone.

Optimization of Water-Alternating-CO2 Injection Field Operations Using a Machine-Learning-Assisted Workflow

Summary This paper will present a robust workflow to address multiobjective optimization (MOO) of carbon dioxide (CO2)-enhanced oil recovery (EOR)-sequestration projects with a large number of operational control parameters. Farnsworth unit (FWU) field, a mature oil reservoir undergoing CO2 alternating water injection (CO2-WAG) EOR, will be used as a field case to validate the proposed optimization protocol. The expected outcome of this work would be a repository of Pareto-optimal solutions of multiple objective functions, including oil recovery, carbon storage volume, and project economics. FWU’s numerical model is used to demonstrate the proposed optimization workflow. Because using MOO requires computationally intensive procedures, machine-learning-based proxies are introduced to substitute for the high-fidelity model, thus reducing the total computation overhead. The vector machine regression combined with the Gaussian kernel (Gaussian-SVR) is used to construct proxies. An iterative self-adjusting process prepares the training knowledge base to develop robust proxies and minimizes computational time. The proxies’ hyperparameters will be optimally designed using Bayesian optimization to achieve better generalization performance. Trained proxies will be coupled with multiobjective particle swarm Optimization (MOPSO) protocol to construct the Pareto-front solution repository. The outcomes of this workflow will be a repository containing Pareto-optimal solutions of multiple objectives considered in the CO2-WAG project. The proposed optimization workflow will be compared with another established methodology using a multilayer neural network (MLNN) to validate its feasibility in handling MOO with a large number of parameters to control. Optimization parameters used include operational variables that might be used to control the CO2-WAG process, such as the duration of the water/gas injection period, producer bottomhole pressure (BHP) control, and water injection rate of each well included in the numerical model. It is proved that the workflow coupling Gaussian-SVR proxies and the iterative self-adjusting protocol is more computationally efficient. The MOO process is made more rapid by squeezing the size of the required training knowledge base while maintaining the high accuracy of the optimized results. The outcomes of the optimization study show promising results in successfully establishing the solution repository considering multiple objective functions. Results are also verified by validating the Pareto fronts with simulation results using obtained optimized control parameters. The outcome from this work could provide field operators an opportunity to design a CO2-WAG project using as many inputs as possible from the reservoir models. The proposed work introduces a novel concept that couples Gaussian-SVR proxies with a self-adjusting protocol to increase the computational efficiency of the proposed workflow and to guarantee the high accuracy of the obtained optimized results. More importantly, the workflow can optimize a large number of control parameters used in a complex CO2-WAG process, which greatly extends its utility in solving large-scale MOO problems in various projects with similar desired outcomes.

A new method for predicting injection multiples of extreme displacement in waterflood reservoirs

The theoretical relationship between water injection multiple (i.e. injected pore volume) and water saturation is inferred from theoretical concepts of reservoir engineering. A mathematical model based on core displacement tests is established for the entire injection process that satisfies both initial displacement and extreme displacement, simultaneously. The results show that prior to the flooding, the water injection multiple has a linear relationship with the water saturation, and the utilization rate of the injected water is the highest. As water breakthrough at the production end, the water-cut increases, and the injection multiple increases exponentially while the utilization efficiency of the injected water gradually decreases. When the injection multiple approaches infinity, the utilization efficiency of the injected water gradually decreases to 0, by which time the water-cut at the production end is always 1. At this time, the water saturation no longer changes, and the water flooding recovery rate reaches its limit. Based on the experimental test data, a mathematical model of the entire process of injection multiple and water saturation is established, which has high fitting accuracy that can predict the injection multiple in the different stages of development of a mature oil reservoir. The dynamically changing index of the injection water utilization efficiency in reservoir development by reactive water flooding can be obtained through reasonable transformation of the mathematical model. This is of great significance in guiding evaluations of the effects of reservoir development and formulating countermeasures.

A comprehensive thermodynamic analysis of an integrated solar enhanced oil recovery system for applications in heavy oil fields

In this work, we present an integrated energy system for solar enhanced oil recovery (SEOR) process accompanied with electricity generation, fresh water and elemental sulfur production. The system shows the possibilities of integrating solar energy in upstream and downstream oil industry applications while offering the same quality of service. Such studies are of great interest to the Gulf Cooperation Council (GCC) region where solar irradiance is high during the year and where an abundance of mature heavy oil reservoir is present. We harness the solar energy from the sun to produce high quality steam at elevated temperature by the means of concentrated solar power technology through solar towers. The steam is used in generating electricity that is used for artificial lift purpose in the production wells, and provides steam suitable for injection purposes in tertiary recovery phase for hydrocarbon reservoirs. The overall system is analyzed in terms of energy and exergy efficiencies and the effects of different operating system parameters are evaluated. The steam generator and the furnace have the highest exergy destruction rates at a relative percentage of 41.3% and 39%. The energy and exergy efficiencies for the Claus process is reported at 78.2% and 18.2%, while the energy and exergy efficiencies of the overall system are calculated as 84% and 33.7%, respectively. Assuming that around 16% of the oil in place in the analyzed reservoir is accessible through Huff n’ Puff, then 3,822,250kg of oil is produced while injecting 67,500kg of steam of density 0.54kg/bbl at reservoir conditions.