Reservoir Permeability Research Articles

Refracturing Time Optimization Considering the Effect of Induced Stress by Pressure Depletion in the Shale Reservoir

Refracturing is an important technology for tapping remaining oil and gas areas and enhancing recovery in old oilfields. However, a complete and detailed refracturing timing optimization scheme has not yet been proposed. In this paper, based on the finite volume method and the embedded discrete fracture model, a new coupled fluid flow/geomechanics pore-elastic-fractured reservoir model is developed. The COMSOL 3.5 commercial software was used to verify the accuracy of our model, and by studying the influence of matrix permeability, initial stress difference, cluster spacing, and fracture half-length on the orientation of maximum horizontal stress, a timing optimization method for refracturing is proposed. The results of this paper show that the principle of optimizing the refracturing timing is to avoid the time window where the percentage of Type I (Type I indicates that stress inversion has occurred, 0∘≤α≤20∘; Type II indicates that the turning degree is strong, 20∘<α≤70∘; and Type III indicates less stress reorientation, 70∘<α≤90∘) stress reorientation area is relatively large, so that the fractures can extend perpendicular to the horizontal wellbore. At the same time, the simulation results show that with the increase in production time, the percentage of Type I and Type II increases first and then decreases, while the percentage of Type III decreases first and then increases. When the reservoir permeability, stress difference, and cluster spacing are larger, the two types of refracturing measures can be implemented earlier. But, with the increase in fracture half-length, the timing of refracturing Method I is earlier, and the timing of refracturing Method II is later. The research results of this paper are of great significance to the perfection of the refracturing theory and the optimization of refracturing design.

Analysis and application of low frequency shadows based on the asymptotic theory for porous media

Low-frequency shadows beneath gas reservoirs can be regarded as a time delay relative to the reflection from the reservoir zone, but they cannot be reasonably explained by the high-frequency attenuation or velocity dispersion observed in normal P-waves. According to the new asymptotic theory for porous media, seismic P-waves undergo multiple conversions between fast and slow modes during seismic waves passing through layered permeable reservoirs at low frequencies, and changes in the velocity and amplitude (i.e., energy) of slow P-waves can lead to low-frequency shadows. In this study, a forward analysis was performed on the dispersion and attenuation of fast and slow P-waves within the seismic frequency band based on the asymptotic theory for porous media; the results revealed that fast P-waves do not undergo frequency dispersion and attenuation within the seismic frequency band and that slow P-waves are the primary contributor of dispersion and attenuation. In addition, methods used to calculate the frequencies at which low-frequency shadows occur were analyzed and are discussed. Finally, S-transform time-frequency analysis method was used to calculate and analyze the low-frequency shadows of three-dimensional seismic data acquired from work area M in Sichuan. The low-frequency shadow anomalies determined by this method were found to be highly consistent with those identified based on the data acquired from wells in the target reservoir. These results indicate the good application performance of this method.

Synthesis and Characterization of Self-Dispersion Monodisperse Silica-Based Functional Nanoparticles for Enhanced Oil Recovery (EOR) in Low-Permeability Reservoirs

A controllable particle size mono-dispersing nanofluid system has been developed to address the challenges of low porosity and low-permeability in low to ultra-low-permeability reservoirs. This system combines high dispersion stability with enhanced oil recovery performance, and its effectiveness in improving recovery rates in low-permeability reservoirs, where conventional chemical flooding is ineffective, has been well demonstrated. Using the in situ method to prepare monodispersed nano-silica particles, the effects of the water concentration, ammonia concentration, and silica precursor concentration on the morphology, particle size, and formation time of the silica spherical particles were analyzed. Building on this foundation, a partially hydrophobic modified nano-silica oil displacement fluid was synthesized in situ. The system’s dispersion stability, ability to reduce oil-water interfacial tension, and capacity to alter rock wettability were evaluated. Core physical models were used to evaluate the oil displacement efficiency and the permeability applicability limits of the self-dispersing nano-silica oil displacement system. The experiments confirmed that the particle size distribution of the self-dispersing nano-silica oil displacement system can be controlled within a range of 10 nm to 300 nm. The nanofluids exhibited excellent stability, effectively altering the rock wettability from oil-wet to water-wet and reducing the oil-water interfacial tension to approximately 10−1 mN/m. The nano-displacement system increased the recovery rate of the low permeability reservoirs by more than 17%. The in situ modification method used to prepare these self-dispersing nanoparticles provides valuable insights for synergistic enhancement of recovery when combined with other systems, such as surfactants and CO2. This approach also opens up new possibilities and drives further development in the field of nano-enhanced oil recovery chemistry.

Property Changes of Low-Permeability Oil Reservoirs Under Long-Term Water Flooding

The property changes of low-permeability oil reservoirs after long-term water flooding remain insufficiently understood. This study conducted water flooding experiments on three real core samples and employed scanning electron microscopy (SEM), X-ray diffraction (XRD), and nuclear magnetic resonance (NMR) to analyze how the changes in mineral and pore structure relate to permeability changes before and after water flooding. The results showed that the core permeability decreased significantly after water flooding, with a decrease rate of 69.7%, 19.6%, and 34.4% for the three cores. The well test results of the block also indicate that the reservoir permeability decreases after long-term water injection, with an average decrease of over 60%. The clay mineral content decreased notably, with the largest decrease of 8.6 percentage points in kaolinite and minor decreases in chlorite and illite. SEM results also indicated erosion and damage to the clay mineral structure by the water flow, and kaolinite has a high degree of dissolution. The NMR results showed that after water flooding, the pore size curve shifted to the left, the relaxation time decreased, the number of small pores in the cores increased, and the number of large pores decreased. The median pore radius decreased by 3.4% to 21.53%.

Study on the pore structure and permeability evolution of tight sandstone under liquid nitrogen freezing‐thawing cycles based on NMR technology

To further raise the gas extraction efficiency of the tight sandstone, the liquid nitrogen (LN2) freezing-thawing cycles method can be employed to improve the permeability of the low-permeability reservoirs. Permeability is generally regarded as a macroscopic description of the pore structure and usually has functional relationship to pore structure properties. The permeability of the rock is closely related to the change of microscopic pore structure. The permeability of rock depends on how the subzero temperatures changed the microscopic pore structure of rock, but it has not yet been confirmed obviously. In this study, the nuclear magnetic resonance (NMR) technique was adopted to investigate the pore structure evolution law and permeability of the tight sandstone with different LN2 freezing-thawing cycles. The results demonstrate that the LN2 freezing-thawing cycles promotes pore development and micro-fracture connection, and enhances the pore connectivity. The proportion of meso-pores, macro-pores and micro-fractures in the sandstone samples increases significantly, which provides a channel for the sandstone gas flow and extraction. Total porosity and effective porosity of the samples present a trend of rapid increase as the number of LN2 freezing-thawing cycles increasing, while the residual porosity decreases as the number of LN2 freezing-thawing cycles increasing. Coates model, SDR model (mean T2 model) and PP model were used to calculate and evaluate the permeability of the samples subjected to different LN2 freezing-thawing cycles. Furthermore, PP model can provide a better permeability estimate than the classical Coates and SDR model.

Research on improving permeability of granite reservoir: Polyhydrogen chelating acid acidizing

ABSTRACT Acidization is a highly effective technique for increasing oil well productivity. Therefore, it is critical to study effective stimulation of low-permeability granite reservoirs using acidification. Using the granite reservoir of Baobab oilfield in Chad as the research object, the properties of reservoir rocks were tested using XRD and rock thin section analysis. Dissolution experiments, core flooding experiments, and CT scanning were used to investigate the increased permeability and changes in the pore structure of the cores during acidification. The minerals in the rocks are primarily plagioclase, kalifeldspar, and quartz, with trace amounts of calcite, chlorite, magnetite, illite, biotite, hornblende, sphene, and sericite. At 80°C and 10 mL of main acid injection, polyhydrogen chelating acid (6% HCl + 5% SA601 + 7% SA701) improved granite permeability more than mud acid (8% HCl + 2% HF) and fluoroboric acid (8% HCl + 8% HBF4), with permeability increase of 3.68. The CT three-dimensional images of the rocks show that both the cores acidified with polyhydrogen chelating acid and mud acid formed continuous acid-etched wormholes, while the cores acidified with fluoroboric acid did not. Compared to the mud acid, the core acidified by the polyhydrogen chelating acid produced more visible acid-etched wormholes. Meanwhile, the polyhydrogen chelating acid was more effective at improving the pore throats and expanding the flow channels in the core. This study serves as a reference for the application of acidification and increasing production in low-permeability granite reservoirs.

Natural vibrations of fluid in a well connected with the reservoir by a system of radial fractures

The problem of natural vibrations of a fluid in a horizontal well with multiple fractures obtained by hydraulic fracturing is considered. A mathematical model of the natural vibrations of fluid in a horizontal oil well connected to the reservoir by a system of radial hydraulic fractures is constructed and the frequency characteristics of the natural vibrations of fluid as functions of the hydraulic fracture and reservoir parameters are determined. Using a numerical analysis of the frequency characteristics of vibrations, the effect of changes in the fracture width, the number of fractures, and the reservoir permeability on the natural frequencies is demonstrated.

Improved Fracture Permeability Evaluation Model for Granite Reservoirs in Marine Environments: A Case Study from the South China Sea

Permeability is a crucial parameter in the exploration and development of oil and gas reservoirs, particularly in unconventional ones, where fractures significantly influence storage capacity and fluid flow. This study investigates the fracture permeability of granite reservoirs in the South China Sea, introducing an enhanced evaluation model for planar fracture permeability based on Darcy’s law and Poiseuille’s law. The model incorporates factors such as fracture heterogeneity, tortuosity, angle, and aperture to improve permeability assessments. Building on a single-fracture model, this research integrates mass transfer equations and trigonometric functions to assess intersecting fractures’ permeability. Numerical simulations explore how tortuosity, angle, and aperture affect individual fracture permeability and the influence of relative positioning in intersecting fractures. The model makes key assumptions, including minimal consideration of horizontal stress and the assumption of unidirectional laminar flow in cross-fractures. Granite outcrop samples were systematically collected, followed by full-diameter core drilling. A range of planar models with varying fracture apertures were designed, and permeability measurements were conducted using the AU-TOSCAN-II multifunctional core scanner with a steady-state gas injection method. The results showed consistency between the improved model and experimental findings regarding the effects of fracture aperture and angle on permeability, confirming the model’s accuracy in reflecting the fractures’ influence on reservoir flow capacity. For intersecting fractures, a comparative analysis of core X-ray computed tomography (X-CT) scanning results and experimental outcomes highlighted discrepancies between actual permeability measurements and theoretical simulations based on tortuosity and aperture variations. Limitations exist, particularly for cross-fractures, where quantifying complexity is challenging, leading to potential discrepancies between simulation and experimental results. Further comparisons between core experiments and logging responses are necessary for model refinement. In response to the challenges associated with evaluating absolute permeability in fractured reservoirs, this study presents a novel theoretical assessment model that considers both single and intersecting fractures. The model’s validity is demonstrated through actual core experiments, confirming the effectiveness of the single-fracture model while highlighting the need for further refinement of the dual-fracture model. The findings provide scientific support for the exploration and development of granite reservoirs in the South China Sea and establish a foundation for permeability predictions in other complex fractured reservoir systems, thereby advancing the field of fracture permeability assessment.

Experimental Study on Improving the Recovery Rate of Low-Pressure Tight Oil Reservoirs Using Molecular Deposition Film Technology

The intricate geological characteristics of tight oil reservoirs, characterized by extremely low porosity and permeability as well as pronounced heterogeneity, have led to a decline in reservoir pressure, substantial gas expulsion, an accelerated decrease in oil production rates, and the inadequacy of traditional water injection methods for enhancing oil recovery. As a result, operators encounter heightened operational costs and prolonged timelines necessary to achieve optimal production levels. This situation underscores the increasing demand for advanced techniques specifically designed for tight oil reservoirs. An internal evaluation is presented, focusing on the application of molecular deposition film techniques for enhanced oil recovery from tight oil reservoirs, with the aim of elucidating the underlying mechanisms of this approach. The research addresses fluid flow resistance by employing aqueous solutions as transmission media and leverages electrostatic interactions to generate nanometer-thin films that enhance the surface properties of the reservoir while modifying the interaction dynamics between oil and rock. This facilitates the more efficient displacement of injected fluids to replace oil during pore flushing processes, thereby achieving enhanced oil recovery objectives. The experimental results indicate that an improvement in oil displacement efficiency is attained by increasing the concentration of the molecular deposition film agent, with 400 mg/L identified as the optimal concentration from an economic perspective. It is advisable to commence with a concentration of 500 mg/L before transitioning to 400 mg/L, considering the adsorption effects near the well zone and dilution phenomena within the reservoir. Molecular deposition films can effectively reduce injection pressure, enhance injection capacity, and lower initiation pressure. These improvements significantly optimize flow conditions within the reservoir and increase core permeability, resulting in a 7.82% enhancement in oil recovery. This molecular deposition film oil recovery technology presents a promising innovative approach for enhanced oil recovery, serving as a viable alternative to conventional water flooding methods.

Enhanced oil recovery and carbon sequestration in low-permeability reservoirs: Comparative analysis of CO2 and oil-based CO2 foam

Excessive CO2 emissions contribute to global climate change thus mandating effective methods for CO2 utilization and sequestering. In this study, one-dimensional flow simulation experiments on CO2 flooding, CO2 Huff-n-Puff, oil-based CO2 foam flooding, and oil-based CO2 foam Huff-n-Puff are conducted using low-permeability sandstone cores modeled after the Q131 block in Liaohe Oilfield, characterized by porosity ranging from 15% to 20% and permeability between 25 mD to 35 mD. Low permeability reservoirs are rich in oil resources and may effectively sequester CO2. Parameters pertaining to oil and gas production and carbon storage are collected. Nuclear magnetic resonance (NMR) is employed to determine the spatial variation of oil saturation in the cores. The experimental results show 8.03% and 41.21% increase in oil recovery factor by foam flooding and foam Huff-n-Puff relative to CO2 as the recovery agent. Moreover, NMR analysis confirms lower residual oil saturation in core samples using foam, suggesting better displacement agent. Oil-based CO2 foam recovery contributed to effective carbon sequestration, with carbon storage increasing by 34.24% and 315% relative to CO2 flooding and CO2 Huff-n-Puff, respectively. CO2 storage mechanisms for oil-based CO2 foam recovery method are detailed.

Far-field reactivation of natural fractures by stress shadow effect

Hydraulic fracturing is the most important means to achieve the reservoir stimulation of tight formations like shale, where the reservoir permeability is enhanced after the interaction between hydraulic fracture (HF) and natural fractures (NFs). Apart from the widely known direct intersection behaviors between HF and NFs (i.e., the HF meets the NFs), the NFs may also be reactivated by the stress shadow effect of HF, but the failure mechanism and reactivation modes are still unclear. To address this, the far-field reactivation of NFs under the stress shadow effect is described based on a hybrid phase field model (PFM) with the frictional contact criterion, where the open or slip conditions can be quantitatively calculated using the Mohr-Coulomb yield function along the contact interface of NFs. The zone with reactivated NFs is divided into mode II and mixed mode dominated sub-zones respectively, and the phase diagram of reactivation behaviors is summarized as variations of the location and angle of the NF. The NF reactivation modes are discussed under different geological conditions (strength of NFs, distribution angle of NFs, and initial stress difference). It could be found that the higher initial stress ratio leads to more mode II reactivated NFs, and NFs strengths and angles influence both mode II and mixed mode zones notably. The NF reactivation tends to take place with lower strength, higher injection rate, higher initial stress ratio, and special angle (e.g., HF are perpendicular to NFs), during which the permeability enhancement and reservoir stimulation are evaluated by the phase field model.

On the Significance of Hydrate Formation/Dissociation during CO2 Injection in Depleted Gas Reservoirs

Summary The study aims to quantitatively assess the risk of hydrate formation within the porous formation and its consequences on injectivity during storage of CO2 in depleted gas reservoirs considering low temperatures caused by the Joule-Thomson (JT) effect and hydrate kinetics. Hydrates formed during CO2 storage operation can occupy porous spaces in the reservoir rock, reducing the rock’s permeability and thus becoming a hindrance to the storage project. The aim was to understand which mechanisms can mitigate or prevent the formation of hydrates. The key mechanisms we studied included water dry-out, heat exchange with surrounding rock formation, and capillary pressure. A semicompositional thermal reservoir simulator is used to model the fluid and heat flow of CO2 through a reservoir initially composed of brine and methane. The simulator can model the formation and dissociation of both methane and CO2 hydrates using kinetic reactions. This approach has the advantage of computing the amount of hydrate deposited and estimating its effects on the porosity and permeability alteration. Sensitivity analyses are also carried out to investigate the impact of different parameters and mechanisms on the deposition of hydrates and the injectivity of CO2. Simulation results for a simplified model were verified with results from the literature. The key results of this work are as follows: (1) The JT effect strongly depends on the reservoir permeability and initial pressure and could lead to the formation of hydrates within the porous media even when the injected CO2 temperature was higher than the hydrate equilibrium temperature; (2) the heat gain from underburden and overburden rock formations could prevent hydrates formed at late time; (3) permeability reduction increased the formation of hydrates due to an increased JT cooling; and (4) water dry-out near the wellbore did not prevent hydrate formation. Finally, the role of capillary pressure was quite complex, as it reduced the formation of hydrates in certain cases and increased in other cases. Simulating this process with heat flow and hydrate reactions was also shown to present severe numerical issues. It was critical to select convergence criteria and linear system tolerances to avoid large material balance and numerical errors.

An integrated dynamic modeling workflow for acid gas and CO2 geologic storage screening in saline aquifers with faults: A case study in Western Canada

This study investigates the feasibility of storing the acid gas produced from the oil and gas facilities in Southern Saskatchewan into the Basal Sand aquifer using a coupled wellbore-aquifer-compositional reservoir model. The simulations investigate the pressure change around the fault in proximity of the primary storage location incorporating the influence of reservoir permeability, fault transmissibility, and wellbore configuration, on the factors critical to safe and efficient storage, such as plume migration, pressure changes, and CO2 storage capacity. A compositional fluid model created using an equation of state was integrated into the reservoir model. Simultaneous incorporation of fault transmissibility, phase solubility, water salinity, temporal in-situ hysteresis and structural trapping, and in-situ compositional tracking of individual gas components is considered as the main novelty of this work. The main challenge of the study was the lack of available data to characterize the aquifer. To this end, a comprehensive workflow of reservoir studies and modeling was applied to reduce the uncertainties and evaluate the site selection. The Basal sand scoping models reveal that the aquifer is expected to handle the required disposal volume given its extent. The injected acid gas plume migrates laterally and preferentially towards the northwest, away from the fault, owing to the aquifer's geological structure. CO2 remains entirely in the supercritical state, offering storage advantages due to its lower volume. The reservoir permeability significantly impacts the pressure patterns with lower permeability formations triggering higher wellhead injection pressures. Substantial pressure increases around the sealing fault can be observed. Pressure changes of 110 kPa (16 psi) to over 400 kPa (58 psi) were observed at the fault segment after 20 years of continuous gas injection for the expected range of reservoir properties. Mitigation strategies to minimize the increase in fault pressure entail relocating the injection site away from the fault or utilizing a horizontal well trajectory and using an observation well near the fault for monitoring any pressure buildup and slippage.

Enhance Oil Recovery by Carbonized Water Flooding in Tight Oil Reservoirs

The low permeability of tight sandstone reservoirs limits the application of water flooding to enhance oil recovery. Due to the properties of CO2, people improve crude oil recovery by carbonizing water flooding. However, many studies have not prioritized determining the concentration of carbonated water before comparing the recovery rates of carbonated water flooding and pure water flooding after water flooding. This article takes the Chang 6 oil reservoir as the research object, and uses a combination of nuclear magnetic resonance testing and displacement experiments to conduct experiments on optimizing the concentration of carbonated water. Based on this, experiments on water flooding and carbon water flooding after water flooding to improve crude oil recovery are conducted to compare and analyze the oil enhancement potential of carbonated water flooding. The experimental results show that the physical properties, pore throat structure and seepage capacity of sandstone samples of type I, II and III decrease in turn. With the increase of carbonated water concentration, the expansion coefficient, viscosity reduction rate, contact angle reduction rate and core permeability loss rate of crude oil increase. The damage rate of 0.4mmol/cm3 carbonated water solution (17.6g CO2: 1L water) to the core permeability is only 0.98%, which is the optimal experimental concentration. During the water flooding process, crude oil in pores of different scales in Type I rock cores is utilized, and the degree of utilization in large pores is relatively high. Continuing to use carbonated water to drive oil in the rock cores after water flooding increased the recovery rate of crude oil by 15.24%; The degree of crude oil utilization in small pores of Tpye II core after carbonization and water flooding increased by 29.4%, and the final recovery rate of crude oil increased by 11.35% compared to the core after water flooding; The physical properties of Tpye III core are poor, with a small proportion of large pores, resulting in a 9.04% increase in crude oil recovery rate. Compared with pure water flooding, the recovery rate and utilization degree of large and small pores in the three types of rock cores after carbonization water flooding have been improved to varying degrees. Among them, the utilization degree of crude oil in large pores is the most significant, which increases the recovery rate of crude oil in the rock core after displacement. This study can provide a theoretical basis for improving crude oil recovery by carbonizing water flooding.

Geological and biostratigraphical factors in hydrocarbon recovery optimization using integrated seismic, petrophysical, and core data, Niger Delta

The study of geologic heterogeneities (the quality of reservoir rock according to its spatial variation in properties such as grain size, mineralogy, organic content, fossil content, and natural fracture) and their impact on recovery factors, optimization, and performance of injection fluids in concurrent development (production of both oil and gas at the same time) of oil rim reservoirs (reservoirs with a thin oil column that is overlain with a large gas cap) has become necessary to explore the role of geological and biostratigraphical heterogeneity in optimizing hydrocarbon recovery from oil rim reservoirs in the Niger Delta using integrated seismic, petrophysical, and core data. This is to achieve optimum hydrocarbon recovery instead of relying only on development strategies, which is usually the practice and thus fails. Petrel and Eclipse software were used to simulate the static and dynamic models, respectively, for three oil rim reservoirs, using data (seismic, petrophysical, core, and reservoir data) from a green field in the Niger Delta, Nigeria, for concurrent development under the natural depletion (base case), surfactant enhanced-water-alternating-gas (SeWAG), and water-alternating-gas (WAG) injection options. In each option, two scenarios of injection well positions were simulated: gas-oil contact (GOC) and oil-water contact (OWC). Geological studies showed that Reservoir 1 is a heterolith facies of lower-shoreface deposits with traces of Ophiomorpha burrows, Reservoir 2 is a channel facies of lower shoreface deposits with Ophiomorpha burrows, and Reservoir 3 is a heterolith facies of upper shoreface without vertical burrows. When SeWAG of ratio 1:4:2 was injected at OWC, the highest oil recovery factor was observed compared to other options, and injection at GOC gave the highest gas recovery factor. Permeability anisotropy (Kv/Kh) for reservoirs 1 and 2, with Ophiomorpha burrows being considered, was 0.32 and 0.34, respectively. High recovery factors for both oil and gas were recorded. However, the model of the same reservoir without Ophiomorpha burrows gave reduced values of Kv/Kh of 0.12 and 0.15, respectively, with reduced recovery factors. Reservoir 3, which doesn't have burrows in the initial model, has a Kv/Kh value of 0.11 with low recovery factors in various development cases. However, when Ophiomorpha burrows were integrated into the model, Kv/Kh was 0.31, and the recovery factors increased significantly. The study has shown that geological and biostratigraphical interactions induce Kv/Kh. It has a significant optimization impact on recovery factors in concurrent development and enhances vertical sweep efficiency in EOR (Enhanced Oil Recovery). The study further shows that Ophiomorpha burrows improve the geologic heterogeneity quality of a reservoir (permeability anisotropy) by enhancing the injection fluid to get into micro- and macropore spaces for efficient sweeping of oil and gas into the development well.

Optimization of fracturing parameters for horizontal wells in high-sulfur gas reservoirs considering the effect of sulfur deposition

During the development of high-sulfur gas reservoirs, the precipitation and deposition of elemental sulfur can lead to a reduction in reservoir porosity and permeability. Previous studies focus on the well production with optimized operational parameters, but the effect of sulfur deposition is not included, which impacts fracturing parameters, well production, and economic evaluation. Therefore, this work proposes a reasonable approach for parameter optimization considering sulfur. The variation of porosity and permeability are first evaluated during sulfur deposition. After that, fracture half-length, fracture spacing, fracture conductivity, and fracture distribution are optimized with orthogonalization factor analysis, and the influence of sulfur deposition on different fracture parameters are detailed analyzed. The results shown that the fracture half-length and fracture conductivity are greatly affected by sulfur deposition. Finally, net profit value is applied to obtain the optimal fracture spacing interval. With economic evaluation, the optimal fracture spacing interval of 125 m∼ 150 m is determined considering the net profit and the payback period. This work provides a useful economic method for fracture parameter optimization high-sulfur gas reservoirs, which benefits for the development and production of gas reservoirs.

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.

Capsule polymer flooding for enhanced oil recovery

To solve the problems of shear degradation and injection difficulties in conventional polymer flooding, the capsule polymer flooding for enhanced oil recovery (EOR) was proposed. The flow and oil displacement mechanisms of this technique were analyzed using multi-scale flow experiments and simulation technology. It is found that the capsule polymer flooding has the advantages of easy injection, shear resistance, controllable release in reservoir, and low adsorption retention, and it is highly capable of long-distance migration to enable viscosity increase in deep reservoirs. The higher degree of viscosity increase by capsule polymer, the stronger the ability to suppress viscous fingering, resulting in a more uniform polymer front and a larger swept range. The release performance of capsule polymer is mainly sensitive to temperature. Higher temperatures result in faster viscosity increase by capsule polymer solution. The salinity has little impact on the rate of viscosity increase. The capsule polymer flooding is suitable for high-water-cut reservoirs for which conventional polymer flooding techniques are less effective, offshore reservoirs by polymer flooding in largely spaced wells, and medium to low permeability reservoirs where conventional polymers cannot be injected efficiently. Capsule polymer flooding should be customized specifically, with the capsule particle size and release time to be determined depending on target reservoir conditions to achieve the best displacement effect.

Autonomous Inflow Control Valves Enable Better Water Control in Peru Oil Field

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 218074, “Making Better Wells With Autonomous Inflow Control Valves for Water Control in the Flank of the Bretaña Norte Oil Field, Peru: A Case Study,” by Willy Garcia, SPE, J. Antonio Zegarra, SPE, and Edwar Bustamante, PetroTal Peru, et al. The paper has not been peer reviewed. _ Bretaña Norte is a heavy oil greenfield in a remote area of northeast Peru. The field development strategy was designed around horizontal wells and advanced completions with autonomous inflow control devices (AICDs). As a part of a technology evaluation program, autonomous inflow-control-valve (AICV) technology was selected for field trials because of its ability to autonomously shut off water based on fluid properties. A reservoir simulation study was conducted, and the expected performance of AICV was compared with other AICD technologies installed in the field, indicating potential benefits related to better reservoir management. Field Description Bretaña Norte is an onshore field in the Peruvian Amazon. The Vivian formation is the main reservoir of the Bretaña Norte field and consists entirely of fluvial deposits composed of massive, moderately sorted, fluvial sandstones with thicknesses ranging from 40 to 200 ft. The Vivian formation is subdivided into Vivian S1 and Vivian S2, but only the Vivian S2 formation has been exploited to date. Heavy oil is produced from the Vivian S2 formation (18–19 °API and 25 cp), which features reservoir permeability ranging from 1 to 4 darcies. An active bottom aquifer of greater than 400-ft thickness was encountered under the60-ft oil column of the reservoir, posing a difficult production challenge to the operator: how to handle high volumes of water production that must be reinjected into a different formation. The Bretaña Norte field began production in 2018 with a few initial deviated wells with electrical submersible pumps (ESPs). The first horizontal well completed with standalone screens (SAS) experienced early water breakthrough. Thus, the operator opted for advanced completions with screens and AICDs in 2019. Between 2019 and 2023, 11 wells were completed with different AICD technologies. Even though initial results were positive, such outcomes have been highly dependent on the structural position of the wells. In 2022, a trial well was completed with the AICV technology in the flank of the reservoir, significantly closer to the oil/water contact (OWC), to evaluate its performance under challenging conditions. AICV Technology The AICV is an AICD designed to modify its open-flow area according to the properties (viscosity and density) of the fluids flowing through it and to choke flow progressively as water cut or gas-volume fraction values increase. The AICV is fully reversible, meaning that, if changes in the fluids flowing through the valve occur, it will reopen or reclose accordingly. The AICV consists of two flow paths, the main flow path and the pilot flow path, with an approximate flow distribution of 97 and 3%, respectively. Fig. 1 presents a schematic of the AICV, including a heat map showing the pressure distribution across the different flow paths.

A New model of gas-water two-phase seepage based on Newton's law of motion

The pore throat size, structure distribution, and lithology of porous media in gas reservoirs are varied, and the gas-water two-phase seepage law is complex, making it difficult to describe the seepage model. Newton's law of motion is a basic law of motion in classical mechanics, and its application in gas-water two-phase seepage modeling is an innovative practice of classical mechanics in seepage mechanics systems. Based on Newton's three laws of motion, a gas-water two-phase seepage model was established from the force analysis of fluid, and the relationship between velocity and pressure difference, pipe radius, water film thickness, viscosity, etc. was derived under the condition that the model reached a stable state, i.e., force balance. The relationship is referred to as the steady-state model. Subsequently. the equivalent permeability representation model was derived based on the steady-state model to calculate the permeability of rock samples with different channel distribution characteristics. The results were consistent with the measured values, and there is a good correspondence between channel distribution characteristics and permeability. The relative permeability calculation method was established based on the steady-state model and capillary pressure curve. The obtained relative permeability curve aligned with the two-phase seepage law and coincides with the relative permeability curve obtained by Poiseuille's law. Finally, a new productivity equation was derived based on the steady-state model, and the Inflow Performance Relationship (IPR) curve calculated by the gas well example was consistent with the traditional equation. The research results were based on the force analysis of fluid in porous media and fundamentally explored the law of fluid flow. The derived seepage model can be used to calculate reservoir permeability, the gas-water relative permeability curve, and gas well productivity analysis and to effectively guide gas reservoir development. The study was a successful application of the basic theory of mechanics in gas-water two-phase seepage in gas reservoirs.