Cumulative Oil Research Articles

Analysis of the impact of geological and engineering parameters on productivity in tight oil reservoirs

AbstractTight oil resources are abundant, but the factors affecting production capacity are complex. In this paper, focusing on tight oil reservoirs, three research works were conducted. First, using the numerical simulation software, a numerical model of tight oil reservoirs was established. Second, the influence of geological parameters such as porosity and permeability on oil production were analyzed. Third, the influence of rock compression coefficient and injection fluid on tight oil production were analyzed. Results show that: (a) When the porosity is 0.05, the cumulative oil production in the first 6 years is the highest, while in the later stage of the simulation, the cumulative oil production with a porosity of 0.1 is the highest. (b) The higher the permeability, the greater the cumulative oil production. The cumulative oil production under different permeability conditions are 1392.044, 2178.805, 2939.1704, and 4038.0878 m3, respectively. (c) Under tight reservoir conditions, the impact of different rock compression coefficients on the daily oil production of oil and gas reservoirs is not very significant. (d) The recovery effect is optimal when using the N2 injection scheme. The effectiveness of the CH4 scheme is second, and there is a certain gap compared to the N2 scheme. The development plan of injecting water has the worst effect. However, compared to the depletion development model, the cumulative oil production by injecting N2, CO2, CH4, and water has all increased.

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.

Simulation-Based Optimization Workflow of CO2-EOR for Hydraulic Fractured Wells in Wolfcamp A Formation

Hydraulic fracturing has enabled production from unconventional reservoirs in the U.S., but production rates often decline sharply, limiting recovery factors to under 10%. This study proposes an optimization workflow for the CO2 huff-n-puff process for multistage-fractured horizontal wells in the Wolfcamp A formation in the Delaware Basin. The potential for enhanced oil recovery and CO2 sequestration simultaneously was addressed using a coupled geomechanics–reservoir simulation. Geomechanical properties were derived from a 1D mechanical earth model and integrated into reservoir simulation to replicate hydraulic fracture geometries. The fracture model was validated using a robust production history matching. A fluid phase behavior analysis refined the equation of state, and 1D slim tube simulations determined a minimum miscibility pressure of 4300 psi for CO2 injection. After the primary production phase, various CO2 injection rates were tested from 1 to 25 MMSCFD/well, resulting in incremental oil recovery ranging from 6.3% to 69.3%. Different injection, soaking and production cycles were analyzed to determine the ideal operating condition. The optimal scenario improved cumulative oil recovery by 68.8% while keeping the highest CO2 storage efficiency. The simulation approach proposed by this study provides a comprehensive and systematic workflow for evaluating and optimizing CO2 huff-n-puff in hydraulically fractured wells, enhancing the recovery factor of unconventional reservoirs.

Productivity analysis by insulation design of well with vacuum insulated tubing in SAGD process

This study aims to design insulation and demonstrate its performance on the vertical section of a well in a steam-assisted gravity drainage (SAGD) process. Utilizing the reservoir characteristics of the Athabasca oil sands in Canada, we analyzed oil productivity and derived optimal operating conditions through a multi-objective optimization algorithm. For the simulation, the well's vertical section was insulated with 0.006 W/m‧°C, the thermal conductivity of vacuum insulated tubing (VIT), exhibiting high insulation efficiency. The results indicated that cumulative production increased by up to 20.24%, and production efficiency improved. Additionally, sensitivity analysis using response surface methodology (RSM) revealed that the injection bottom-hole pressure (inj_BHP) was the most significant factor in the insulated well design when parameters varied. A multi-objective optimization using particle swarm optimization (PSO) was conducted to determine the optimal operating conditions, aiming to maximize cumulative oil production and minimize the cumulative steam-oil ratio (cSOR). The optimization resulted in a 39.8% improvement in cumulative oil production and an 88.19% reduction in cSOR, compared to the non-insulation scenario. The findings of this study are anticipated to serve as a guideline for wellbore insulation design in SAGD processes.

Multiphysics Field Coupled to a Numerical Simulation Study on Heavy Oil Reservoir Development via Electromagnetic Heating in a SAGD-like Process

Conventional thermal recovery methods for heavy oil suffer from significant issues such as high water consumption, excessive greenhouse gas emissions, and substantial heat losses. In contrast, electromagnetic heating, as a waterless method for heavy oil recovery, offers numerous advantages, including high thermal energy utilization, reduced carbon emissions, and volumetric heating of the reservoir, making it a focus of recent research in heavy oil thermal recovery technologies. This paper presents a numerical simulation study of electromagnetic heating for heavy oil recovery, using a heavy oil block in the Bohai Bay oilfield in China as a case study. Firstly, a multiphysics field coupled to a mathematical model was established, considering the impact of the temperature on the heavy oil viscosity, the threshold pressure gradient of non-Darcy flow, and the dielectric properties of the reservoir, along with heat dissipation from overlying and undercover sandstone and gravitational effects on fluid flow. Secondly, a numerical simulation method for the coupled multiphysics fields was developed, and the convergence and stability of the numerical simulation method were tested. Finally, a sensitivity analysis based on the numerical simulation results identified the factors affecting heavy oil production. It was found that electromagnetic heating significantly enhances heavy oil production, and the threshold pressure gradient greatly influences the prediction of heavy oil production. Moreover, heat dissipation from the overlying and undercover sandstone severely reduces cumulative oil production. When the production well is located below the electromagnetic heating antenna, larger well spacing results in higher cumulative heavy oil production. Higher heavy oil production is achieved when the antenna is positioned at the center of the reservoir for the studied cases. Power has a big effect on increasing heavy oil production, but its influence diminishes as power increases. There exists an optimal range of electromagnetic frequencies for maximum cumulative production, and higher water saturation leads to poorer electromagnetic heating efficiency. This study provides a theoretical foundation and technical support for the numerical simulation technology and development plan optimization of heavy oil reservoirs subjected to electromagnetic heating.

Application effect of temporary plugging and diverting fracturing technology in well X1

Abstract The deployment of horizontal well development in the sweet spot area of the main sand body can improve the reservoir control degree and the production of a single well. The X1 well in the X block will be put into production after fracturing in 2022. The target layer of this well is a tight reservoir with low porosity and low permeability, and natural fractures are not developed. Combined with the geological characteristics of the target well, horizontal well soluble bridge plug and temporary plugging and diversion fracturing technology are applied to well X1, and branch fractures are formed through temporary plugging and diversion in the fracture, which increases the complexity of fractures and increases the drainage area. The well is currently in production for 485 days, with a peak oil day of 17.4t and a current oil day of 7t, with a cumulative oil production of 4184.6t. In this paper, the fracturing effect of well X1 is preliminatively analyzed, and it is concluded that under the same reservoir conditions, the single particle size sand combined with temporary plugging in the fracture transformation has a relatively good development effect, which can obviously improve the development effect of tight reservoir. The application effect of soluble bridge plug and temporary plugging diversion fracturing technology in this well has certain reference significance for improving the development effect and benefit of horizontal well in ultra-low permeability reservoir.

Phased optimization of multi-thermal fluid flooding for enhanced oil recovery

Multi-thermal fluid flooding has become a critical technique in heavy oil reservoirs and is widely applied in China. Owing to the complexity of the displacement process and the involvement of multiple injection media, conventional optimization methods are unable to achieve economic and efficient development of heavy oil. In this study, an efficient phased parametric optimization method for multi-thermal fluid flooding was developed using horizontal wells in heavy oil reservoirs. This method utilizes particle swarm optimization (PSO), which targets the net present value for the phased optimization of multi-thermal fluid flooding. A comparison between the phased optimization and non-phased optimization shows that the cumulative oil production increased by 16.74% and the net present value increased by 39.66% with phased optimization. The effectiveness of the phased optimization method was verified using a field model. Optimal injection parameter charts were developed for each phase of the multi-thermal fluid flooding under different reservoir parameter conditions. The charts illustrate that the optimal gas injection rate and chemical mass concentration tend towards zero during the steam flooding initiation phase under varying reservoir parameter conditions. Conversely, all the media injection rates increased during the thermal fluid control and steam breakthrough phases. Additionally, with an increase in the crude oil viscosity, effective formation thickness, and original oil saturation, the optimal injection rate of the various media increases. However, with an increase in the permeability and reservoir depth, the optimal injection rate of the various media decreases.

Non-thermal recovery of a viscous oil with a surfactant-polymer process

The goal of this work is to improve recovery of a viscous oil reservoir at 70 °C using a non-thermal process. Polymer floods can improve sweep efficiency, but leave behind a residual oil saturation. A surfactant-polymer flood has the potential to improve both the sweep as well as the displacement efficiency. Phase behavior experiments with the viscous oil, water and surfactants were conducted to identify surfactants. 1D and 2D sandpack displacements were conducted to evaluate the efficacy of the process. Phase behavior experiments showed Winsor type I behavior with a low interfacial tension using a single surfactant, but not ultralow tension. Water flood recovered about 50% OOIP and reduced the oil saturation to about 45% in 1D floods. The subsequent SP flood increased the cumulative oil recovery to 99% in sandpacks when the viscosity of chemical slugs exceeded the oil viscosity. When the permeability decreased (as in a Bentheimer core), the oil recovery decreased to about 86%. Secondary SP floods also recovered most of the oil and faster than tertiary floods. Reduction of polymer concentration (and viscosity to about 1/4th of the oil viscosity) reduced the oil recovery, especially in 2D sandpack floods. Decrease in interfacial tension increased the requirement of polymer concentration to maintain flood front stability. This flood demonstrates the effectiveness of Winsor type I SP formulation for viscous oil, high permeability reservoirs. Such a SP process would reduce the carbon footprint of viscous oil recovery compared to that of thermal processes.

Research and Application of Chemical Water Plugging Technology with High Salt Resistant Gel and Immobile String

Abstract The salinity of formation water in Gasi N1-N2 reservoir is 18 × 104 mg/L, in which calcium and magnesium ions are 6300 mg/L. The conventional gel used for profile control and water plugging has poor salt resistance and is easy to dehydrate under the erosion of formation water; At the same time, the chemical water plugging of oil wells in the past needs to trip down the downhole string for many times, and the construction period is long. In order to solve the former problem, an anti-high salt organic gel suitable for Gasi N1-N21 reservoir is synthesized. The formula is 0.4 wt% SD-3000 + 0.1-0.2 wt% urotropine + 0.05 wt% resorcinol + 0.4 wt% additive. The viscosity of the gel is more than 6000 mPa.s after gelation, and no obvious dehydration phenomenon is found after aging for five months in the formation water environment of Gasi N1-N21 reservoir at 65 °C. The technology of chemical water plugging without moving the string has been innovatively developed, which does not require the operation of tubing and pump during construction. In Gasi N1-N21 reservoir, anti-high salt gel was used to carry out three well-times of chemical water plugging tests without pulling the string, which were all successful, saving 44% of the cost of measures and shortening 78% of the construction period. After water plugging, water production was obviously inhibited, and the average moisture content was reduced from 95% to 45%. The average daily oil increment of a single well was 1.8 tons, and the cumulative oil increment was 1700 tons. The results show that the chemical water plugging technology without pulling string has broad application prospects in Gasi N1-N21 reservoir in Qinghai Oilfield and similar reservoirs in China.

Self-assembly behavior of BS12 in water for combination flooding potential: Deep eutectic solvent as a component

Deep eutectic solvent (DES) as standalone or mixed with surfactant flooding has been increasingly recognized and has attracted attention in enhanced oil recovery (EOR). However, the association between self-assembly behavior and the EOR potential of zwitterionic surfactants in DES-water systems has not been profoundly studied. In this work, two choline-based DES were prepared preferentially. The self-assembly and micellar growth of dodecyl dimethyl betaine (BS12) in DES-water systems was investigated by particle size analysis, fluorescence spectroscopy, and transmission electron microscopy. In the system containing 60 wt% DES, micelles were stretched ∼100 times via complexation, hydrogen bond, and electrostatic shield. Afterward, the key parameters of EOR were evaluated. The synergy effect of DES and BS12 in water reduced the critical micelle concentration (cmc) and the oil–water interfacial tension (IFT) to below 1 mmol/L and 0.1 mN/m, respectively. DES strengthened the BS12 aqueous solution to transform the oil-wet sandstone into water-wet. Therefore, the forces on the crude oil in the pore throats may favor its removal. In the mixed system, larger micelles exhibited better crude oil solubilization performance. Compared with the surfactant-alone system, the solubilization and low IFT brought by DESs/BS12 systems increased the cumulative crude oil recovery rate to 10.74 % and 7.61 %, thus showing promising potential for EOR.

Carbon dioxide storage and cumulative oil production predictions in unconventional reservoirs applying optimized machine-learning models

To achieve carbon dioxide (CO2) storage through enhanced oil recovery, accurate forecasting of CO2 subsurface storage and cumulative oil production is essential. This study develops hybrid predictive models for the determination of CO2 storage mass and cumulative oil production in unconventional reservoirs. It does so with two multi-layer perceptron neural networks (MLPNN) and a least-squares support vector machine (LSSVM), hybridized with grey wolf optimization (GWO) and/or particle swarm optimization (PSO). Large, simulated datasets were divided into training (70%) and testing (30%) groups, with normalization applied to both groups. Mahalanobis distance identifies/eliminates outliers in the training subset only. A non-dominated sorting genetic algorithm (NSGA-II) combined with LSSVM selected seven influential features from the nine available input parameters: reservoir depth, porosity, permeability, thickness, bottom-hole pressure, area, CO2 injection rate, residual oil saturation to gas flooding, and residual oil saturation to water flooding. Predictive models were developed and tested, with performance evaluated with an overfitting index (OFI), scoring analysis, and partial dependence plots (PDP), during training and independent testing to enhance model focus and effectiveness. The LSSVM-GWO model generated the lowest root mean square error (RMSE) values (0.4052 MMT for CO2 storage and 9.7392 MMbbl for cumulative oil production) in the training group. That trained model also exhibited excellent generalization and minimal overfitting when applied to the testing group (RMSE of 0.6224 MMT for CO2 storage and 12.5143 MMbbl for cumulative oil production). PDP analysis revealed that the input features “area” and “porosity” had the most influence on the LSSVM-GWO model's prediction performance. This paper presents a new hybrid modeling approach that achieves accurate forecasting of CO2 subsurface storage and cumulative oil production. It also establishes a new standard for such forecasting, which can lead to the development of more effective and sustainable solutions for oil recovery.

CO2 injection for enhanced oil recovery: Analyzing the effect of injection rate and bottom hole pressure

The goal of net-zero carbon emissions has led to widespread interest in lowering carbon dioxide (CO2) emissions. At the same time, the oil and gas industry seeks to enhance oil recovery (EOR) techniques to meet growing demand. CO2 flooding, a key EOR method, offers a dual benefit: reducing CO2 emissions and enhancing oil recovery. This study investigates the impact of injection rate and bottom hole pressure (BHP) on CO2 injection performance using the Nexus reservoir simulator, a novel application in CO2-EOR research. To the best of the author's knowledge, there is no previous research published in which the researchers used the Nexus reservoir simulator for the study of CO2-EOR. Cases are thoroughly investigated with various injection rates and BHP limitations. Simulation results show that BHP has a minimal impact on oil production, whereas increased injection rates significantly enhance cumulative oil production (COP) by 33.39% and extend reservoir life from 20 to 37 years. Total oil production increased to 33150.7 MSTB, accompanied by reduced water production and maintained reservoir pressure. These findings align with previous research, underscoring the importance of optimized CO2 injection strategies for maximizing oil recovery and reservoir performance.

Research and Application for Alternate Production Technology of Dual-Branch Horizontal Wells in an Offshore Oilfield

Old-well sidetracking is a key method for controlling low-productivity wells in the Bohai oilfield. This study employs reservoir engineering and numerical simulation techniques to investigate the maximum drainage radius and natural coning control mechanism in heavy-oil reservoirs with bottom water. Based on these findings, an alternate production technology was developed for dual-branch horizontal wells. The technology creates a new branch through sidetracking, connecting and isolating the old and new wellbores using a combination of wall hangers and branch guides. Initially, the old wellbore with an ultra-high water cut is temporarily sealed. When the new branch reaches a high water-cut stage, production is switched back to the old wellbore. This technology was successfully applied to three wells in the Bohai oilfield, resulting in the new branch achieving expected production levels, while reopening the old wellbore increased daily oil output by 27 m3 and reduced water cut by 5.6%. Cumulative oil production from these wells reached 95,000 m3. This technology improves well-slot resource utilization, enhances recovery rates, and has significant potential for broader application.

A CO2-Modified Surfactant for Chemical Flooding

Summary Carbon dioxide (CO2) modification of a nonionic surfactant alkyl polyglycoside (C-APG) was conducted based on a commercial APG product under mild synthesis conditions, including a low temperature (50°C) and a low pressure (2.5 bar). Using this method, CO2 was incorporated into APG molecules through the formation of carbonyl structures. The effectiveness and performance of C-APG as a novel surfactant for enhanced oil recovery (EOR) application in carbonate reservoirs were investigated and compared with its precursor—the unmodified APG. The key factors in the chemical structure of C-APG were characterized by Fourier transform infrared spectroscopy (FTIR) to confirm successful CO2 modification. The properties, including compatibility, surface tension, wettability alteration, interfacial tension (IFT), phase behavior, and static and dynamic adsorption of both APG and C-APG, were evaluated by various techniques and methods. Crude oil displacement efficiency of the surfactants was investigated via spontaneous imbibition, visualized micromodel, and coreflooding tests, respectively. Both surfactants were compatible with a high-salinity water (HSW), they exhibited a similar critical micelle concentration (CMC) of 8.5 mg/L and 13.5 mg/L for APG and C-APG, respectively, and had the same contact angle of around 135°. Interestingly, C-APG was found more effective in reducing IFT between oil and water phases. The IFT of oil in the C-APG solution was 0.058 ±0.001 mN/m, one order of magnitude lower than the value of 0.47 ±0.02 mN/m obtained from the solution of original APG, suggesting a better performance of C-APG in chemical flooding for oil displacement. A Winsor Type I microemulsion was formed by APG within the salinity range, while a transition of Type I to Type II microemulsion was observed for C-APG. The static adsorption of APG and C-APG at 2 g/L in carbonate were 0.93 mg/g rock and 1.08 mg/g rock, and the adsorption decreased to 0.11 mg/g rock and 0.13 mg/g rock under dynamic conditions for APG and C-APG, respectively. The spontaneous imbibition test demonstrated a higher oil imbibition recovery of 18.0% from C-APG solution compared to the result of 10.2% obtained from APG solution. A micromodel test showed that more crude oil was displaced by injection of APG or C-APG solution after waterflooding, while C-APG injection exhibited a stronger emulsification. The oil displacement by coreflood test showed that C-APG injection led to a lower differential pressure and a higher cumulative oil production (48%) compared to APG chemical flooding with a cumulative oil production of 41%. The produced fluids containing displaced crude oil from C-APG flooding, and subsequent waterflooding demonstrated very strong emulsification compared to the fluids produced after APG injection. This study demonstrates the significant potential of C-APG in two aspects—CO2 reduction and chemical EOR for the upstream petroleum industry.

Countercurrent Imbibition in Porous Media with Dense and Parallel Microfractures: Numerical and Analytical Study

Summary Countercurrent imbibition is the process in which the wetting fluid spontaneously displaces the nonwetting fluid, while the nonwetting fluid is recovered at the wetting fluid inlet. It is a major mechanism for the recovery of shale oil, shale gas, and tight oil. In shale and tight formations, microfractures are highly developed. Specifically, some typical formations, such as continental shales, consist of dense and parallel microfractures (DPFs). In DPF systems, microfractures are segregated by low-permeability matrix layers, while the very close distance betwen neighboring microfractures results in strong capillary correlation. The underlying assumptions of the classical dual-porosity (DP) model break down. Despite extensive studies on layered media, there is still no suitable model to describe imbibition in the DPF system at the representative elementary volume (REV) scale. In this study, we first numerically simulate countercurrent imbibition in DPF systems with fine grids, adopting typical continental shale parameters. For imbibition parallel to microfractures, two distinct stages are identified: an early stage where fractures are not correlated and a late stage where neighboring fractures are strongly correlated by capillarity. In both stages, cumulative oil production (Q) is proportional to the square root of imbibition time (t1/2), while the prefactors are very different. The late stage is the dominant stage in oil recovery. We note that the matrix permeability rarely contributes to imbibition parallel to microfractures at the late time, indicating that the matrix’s role here is to store fluid rather than to provide flow resistance. In addition, we rationalize the failure of the classical DP model, as it significantly overestimates fracture-matrix fluid exchange near the displacement front. Similarly, for imbibition perpendicular to microfractures, Q is also proportional to t1/2 in the late stage. After elucidating the mechanisms of fracture-fracture capillary interaction, we successfully derive analytical solutions for uni-directional countercurrent imbibition kinetics in DPF systems at the late stage, for imbibition parrallel and perpendicular to microfractures, respectively. We accordingly propose an equivalent REV scale model and examine it with fine-grid simulations. We highlight the importance of adopting anisotropic relative permeability in this DPF system at REV scale for reservoir simulation rather than simply adopting anisotropic absolute permeability. This presents a new challenge for numerical simulations at reservoir scale.

Development of surfactant formulation for high-temperature off-shore carbonate reservoirs.

The residual oil left behind after water flooding in petroleum reservoirs can be mobilized by surfactant formulations that yield ultralow interfacial tension (IFT) with oil. However, finding ultralow IFT surfactant formulations is difficult for high-temperature, off-shore, carbonate reservoirs. These reservoirs are often water-flooded with seawater (with a lot of divalent ions), which is often incompatible with many surfactants at high temperatures. The goal of this research is to develop a surfactant formulation for an off-shore carbonate reservoir at 100°C previously flooded by seawater. Surfactant-oil-brine phase behavior was studied for formulations, starting from a single surfactant to mixtures of surfactants and a co-solvent. Mixtures of three surfactants and one co-solvent were needed to produce ultralow IFT formulations for the oil of interest. The surfactant system with polymer mobility control was tested in crushed reservoir rock packs. The cumulative oil recovery was >99% for the surfactant-polymer (SP) flood with an optimal salinity gradient. The constant salinity SP floods with seawater increased oil recovery significantly beyond the water flood (cumulative oil recovery >91%), even though the recovery was lower than that of the optimal salinity gradient SP flood. Our experimental work demonstrates the effectiveness of the surfactant formulation for a high-temperature carbonate reservoir at seawater salinity.

Integration between experimental investigation and numerical simulation of alkaline surfactant foam flooding in carbonate reservoirs

In Brazil, pre-salt carbonate reservoirs are largely responsible for the current increase in oil production. However, due to its peculiar characteristics, increasing oil recovery by water injection is not enough. Therefore, we seek to evaluate the recovery potential using chemical methods (cEOR). Among these, the Alkali Surfactant Foam (ASF) method appears with high potential, a variant of Alkali Surfactant Polymers (ASP) without the problems presented by it. Therefore, this work presents an innovative methodology, which seeks to evaluate the potential for recovery with ASF in carbonate reservoirs by integrating experimental characterization and recovery prediction using reservoir simulation. For this, phase behavior and adsorption analyses were carried out. The experimental results provided key parameters for the simulation, such as optimal salinity, surfactant adsorption, foam mobility reduction factors. The results are from two case studies of AS and ASF flooding, using a section of UNISIM-II benchmark, using a one-quarter of five-spot model. Having the modelling for these cEOR methods defined, an optimization process for each method was applied, allowing a reliable comparison among the methods and over a base case of water injection, seeking the maximization of the net present value (NPV). As a result, in the experimental part, a low interfacial tension (IFT) value of 0.003 mN/m was achieved with a surfactant adsorption reduction of 17.9% for an optimal setting among brine (NaCl), alkali (NaBO2.4H2O), and surfactant (BIO-TERGE AS 40). In the reservoir simulation part, using a fast genetic algorithm in the optimization process, a NPV of US$ 14.43 million higher than the base case (water injection) and a 4.5% increase in cumulative oil production for the ASF injection case were obtained. Considering the analyses of production curves (cumulative oil production and oil rate) and oil saturation maps, a considerable oil production anticipation was observed, which was the main reason for NPV improvement, proving the high potential for application of the ASF method in carbonate reservoirs.

Analysis of different objective functions in petroleum field development optimization

Oilfield development optimization plays a vital role in maximizing the potential of hydrocarbon reservoirs. Decision-making in this complex domain can rely on various objective functions, including net present value (NPV), expected monetary value (EMV), cumulative oil production (COP), cumulative gas production (CGP), cumulative water production (CWP), project costs, and risks. However, EMV is often the main function when optimization is performed under uncertainty. The behavior and performance of different objective functions has been investigated in this paper, when EMV is the primary criterion for optimization under reservoir and economic uncertainty. One of the goals of this study is to provide insights into the advantages and limitations of employing EMV as the sole objective function in oil field development decision-making. The designed optimization problem included sequential optimization of design variables including well positions, well quantity, well type, platform capacity, and internal control valve placements. A comparative analysis is presented, contrasting the outcomes obtained from optimizing the EMV-based objective function against traditional objective functions. The study underscores the importance of incorporating multiple objective functions alongside EMV to guide decision-making in oilfield development. Potential benefits in minimizing CGP and CWP are revealed, aiding in the mitigation of environmental impact and optimization of resource utilization. A strong correlation between EMV and COP is identified, highlighting EMV’s role in improving COP and RF.

Pore-scale probing CO2 huff-n-puff in extracting shale oil from different types of pores using online T1–T2 nuclear magnetic resonance spectroscopy

CO2 huff-n-puff shows great potential to promote shale oil recovery after primary depletion. However, the extracting process of shale oil residing in different types of pores induced by the injected CO2 remains unclear. Moreover, how to saturate shale core samples with oil is still an experimental challenge, and needs a recommended procedure. These issues significantly impede probing CO2 huff-n-puff in extracting shale oil as a means of enhanced oil recovery (EOR) processes. In this paper, the oil saturation process of shale core samples and their CO2 extraction response with respect to pore types were investigated using online T1–T2 nuclear magnetic resonance (NMR) spectroscopy. The results indicated that the oil saturation of shale core samples rapidly increased in the first 16 days under the conditions of 60 °C and 30 MPa and then tended to plateau. The maximum oil saturation could reach 46.2% after a vacuum and pressurization duration of 20 days. After saturation, three distinct regions were identified on the T1–T2 NMR spectra of the shale core samples, corresponding to kerogen, organic pores (OPs), and inorganic pores (IPs), respectively. The oil trapped in IPs was the primary target for CO2 huff-n-puff in shale with a maximum cumulative oil recovery (COR) of 70% original oil in place (OOIP) after three cycles, while the oil trapped in OPs and kerogen presented challenges for extraction (COR < 24.2% OOIP in OPs and almost none for kerogen). CO2 preferentially extracted the accessible oil trapped in large IPs, while due to the tiny pores and strong affinity of oil-wet walls, the oil saturated in OPs mainly existed in an adsorbed state, leading to an insignificant COR. Furthermore, COR demonstrated a linear increasing tendency with soaking pressure, even when the pressure noticeably exceeded the minimum miscible pressure, implying that the formation of a miscible phase between CO2 and oil was not the primary drive for CO2 huff-n-puff in shale.

Well Trajectory Optimization under Geological Uncertainties Assisted by a New Deep Learning Technique

Summary The large number of geological realizations and well trajectory parameters make field development optimization under geological uncertainty a time-consuming task. A novel deep learning-based surrogate model with a novel well trajectory parametrization technique is proposed in this study to optimize the trajectory of wells under geological uncertainty. The proposed model is a deep neural network with ConvLSTM layers to extract the most salient features from highly channelized and layered reservoirs efficiently. ConvLSTM layers are used because they can extract spatiotemporal features simultaneously since layered reservoirs can be regarded as a time series of spatially distributed reservoir properties. The proposed surrogate model could predict the individual objective function with a coefficient of determination of 0.96. After verifying the validity of the surrogate model, four approaches were used to optimize well trajectories. Two of the approaches consumed all available realizations (surrogate model-based and simulation-based approaches), while the remaining two used a subset of realizations. The selection of the subset was based on the cumulative oil production (COP) and the diffusive time of flight (DTOF). Results showed that although the surrogate model used all realizations, it could provide similar results to the simulation-based optimization with only a 5% computational cost of the simulation-based approach. The novelty of this work lies in its proposal of an innovative surrogate model to improve the analysis of channelized and layered reservoirs and its introduction of a novel well trajectory optimization framework that effectively addresses the challenge of optimizing well trajectories in complex three-dimensional spaces, a problem not adequately tackled in previous works.