Search Results (1,577)

Steam-assisted gravity drainage (SAGD) is a widely used thermal enhanced oil recovery (EOR) technique in North America, particularly in high-permeability oil sand reservoirs. While effective, its economic viability has declined due to low oil prices and high greenhouse gas (GHG) emissions from the steam generation. To improve cost-effectiveness and reduce emissions, solvent-assisted SAGD techniques have been explored. Expanding Solvent-SAGD (ES-SAGD) involves co-injecting light hydrocarbons like propane or butane with steam to enhance oil viscosity reduction. This approach lowers the steam–oil ratio by combining solvent dissolution effects with thermal effects. However, the high cost of solvents, particularly butane, challenges its commercial feasibility. Propane is cheaper but less effective, while butane improves performance but remains expensive. This research aims to optimize ES-SAGD by using a propane–butane mixture to achieve efficient performance at a lower cost than pure butane. A linear sand pack is used to evaluate different propane/butane compositions, maintaining constant operational conditions and a solvent concentration of 15 vol.%. Temperature monitoring provides insights into steam chamber growth. Results show that solvent injection significantly enhances ES-SAGD performance compared to conventional SAGD. Performance improves with increasing butane concentration, up to 80% butane in the C₃–C₄ mixture at the test pressure and ambient temperature. Propane alone results in the lowest system temperature, while conventional SAGD reaches the highest temperature. These findings highlight the potential of optimized solvent mixtures to improve ES-SAGD efficiency while reducing costs and GHG emissions. Full article

As conventional oil resources decline, optimizing the development of tight reservoirs has become critical for sustaining production. Horizontal wells with artificial fractures offer a promising solution, but improper water injection often leads to uneven waterflooding, particularly in irregular horizontal–vertical well systems—a common challenge in fields like China’s Fuxian oilfield. This study tackles this issue by introducing a practical and effective method to optimize water injection flow rates, significantly enhancing oil recovery in such complex well patterns. Through advanced numerical modeling and three-dimensional flow visualization, we analyze sweep efficiency and water breakthrough risks, categorizing the horizontal well’s drainage area into three distinct regions, each requiring tailored injection rates. Using a representative model with one horizontal well and three vertical wells, we demonstrate that adjusting the flow rate ratio among injectors to 6:3:1 (instead of a uniform 1:1:1) boosts cumulative oil production by an additional 2997.6 m³. These findings provide field engineers with an actionable strategy to improve waterflooding efficiency, directly increasing recoverable reserves and economic viability in tight reservoirs. The proposed approach has immediate relevance for oilfield operations, offering a scalable solution to maximize recovery in similar unconventional reservoirs worldwide. Full article

A significant part of oil fields has reached a late stage of development, where technologies aimed at increasing the oil recovery factor are becoming particularly relevant. One such technology is surfactant–polymer flooding. To implement this technology, it is necessary to select a chemical formulation that retains its properties under reservoir conditions and enhances the efficiency of water flooding. This work presents a laboratory evaluation of various polymer and surfactant samples to develop an effective chemical formulation. The results demonstrate that anionic surfactants based on sodium laureth sulphate and betaine significantly reduce interfacial tension at the oil–water interface of the target reservoir. Furthermore, when combined with a partially hydrolysed polymer, the sodium laureth sulphate-based surfactant increases the capillary number by 4500 times (reducing interfacial tension from 32.77 mN/m to 0.065 mN/m and increasing the viscosity of the injected agent from 0.5 mPa·s to 4.36 mPa·s). Based on core flooding studies, it can be concluded that the proposed surfactant–polymer composition increases the oil displacement factor from the core sample by 0.15–0.24, depending on the injection volume. The selected formulation can be recommended for application in water flooding at the target reservoir. Full article

This study is dedicated to fundamental research on evaluating the effectiveness of enhanced oil recovery (EOR) methods for high-viscosity oil reservoirs. This paper presents the results of filtration experiments assessing the application of thermal, chemical, and gas-based EOR techniques to reservoir cores of high-viscosity oil, using the East Moldabek field in Kazakhstan as a case study. Experimental studies were conducted on the Cretaceous horizons M-II and M-III as well as the Jurassic horizon J-IV. The obtained production data from the East Moldabek wells indicated the low efficiency of conventional recovery methods. The objective of this study was to identify the most effective EOR method in terms of displacement efficiency. The investigated recovery techniques included base case conventional waterflooding (displacement using formation water), thermal EOR (hot-water flooding), chemical EOR (polymer flooding and ASP flooding), and gas EOR (nitrogen and CO₂ flooding). The filtration experiments were conducted at different times using various filtration systems. The results indicated that the most effective EOR methods for the highly viscous oil in the East Moldabek field were the chemical and thermal EOR techniques. The chemical EOR included ASP flooding, polymer flooding, and surfactant solution injection. ASP flooding achieved the highest increase in displacement efficiency, reaching 19%, making it the most effective method among all of the others. Full article

Silicate bacteria, capable of decomposing silicate minerals that are widely distributed in oil reservoirs, have never been applied in microbial enhanced oil recovery (MEOR). This study investigated a typical silicate bacterium (Paenibacillus mucilaginosus) for the first time in a simulation experiment on low-permeability cores. Meanwhile, a biosurfactant-producing bacterium (Pseudomonas aeruginosa) and an acid-producing bacterium (Bacillus licheniformis) that have been widely studied and applied in MEOR were used for comparison. The results show that although P. mucilaginosus is inferior to P. aeruginosa and B. licheniformis in terms of enhancement of oil recovery at the microbial flooding stage, it can maintain efficient dissolution of minerals over extended periods during the subsequent water flooding stage. This is different from the other two bacteria and ultimately leads to a 6.9% enhancement in oil recovery (7.9% for P. aeruginosa and 4.8% for B. licheniformis). P. mucilaginosus improves oil recovery by increasing the porosity (1.4%) and permeability (12.3 mD) of low-permeability cores through biological weathering. The μCT results show that the pore quantity and pore volume across varying pore radii in low-permeability cores are altered after the MEOR simulation experiment by reducing the quantity and volume of pores with radii less than 10 μm and increasing the quantity and volume of pores with radii between 10 and 25 μm. Under MEOR simulation experimental conditions, P. mucilaginosus slightly degrade saturated hydrocarbons (1.9%), mainly the n-alkanes of C11–C20, but cannot degrade aromatic hydrocarbons, resins, and asphaltenes. The enhanced oil recovery by P. mucilaginosus is attributed to its bio-dissolution under neutral pH conditions, which prevents acid sensitivity damage to low-permeability cores. Thus, its MEOR characteristics are significantly different from the biosurfactant-producing bacterium P. aeruginosa and acid-producing bacterium B. licheniformis. Injecting P. mucilaginosus at the early stages of reservoir development or using it together with other microorganisms should maximize its MEOR effect. This study advances the MEOR framework by extending silicate-dissolving bacteria from agricultural microbial fertilizer systems to MEOR in low-permeability reservoirs, revealing the broad prospects of mineral-targeting microbes for both research and industrial applications in MEOR. Full article

This study addresses the numerical simulation of non-isothermal two-phase water-oil flow in oil reservoirs. The problem of heavy oil recovery by reservoir heating (via heated fluid injection) is investigated, aiming to reduce oil viscosity and increase its mobility. The governing equations are formulated in terms of non-wetting phase pressure (oil), wetting phase saturation (water), and reservoir average temperature, without assuming local thermal equilibrium. Temperature-dependent relative permeabilities are considered. The Finite Volume Method is employed, and the resulting algebraic equations are linearized using the Picard method. The linearized discretized equations are solved sequentially for pressure, saturation, and average temperature, utilizing the Preconditioned Conjugate Gradient (pressure and average temperature) and Preconditioned Stabilized Biconjugate Gradient Method (saturation). After validating the numerical results, a sensitivity analysis is performed using a reservoir with slab geometry. The results demonstrate the positive impact of reservoir heating on heavy oil recovery. Full article

Polymer flooding has been gradually applied in Chinese offshore oilfields to enhance oil recovery (EOR). Injectivity loss during polymer flooding is a common issue that could cause lower displacement speed and efficiency, and eventually compromise the polymer flooding result. This paper presents a case study of a Chinese offshore field where injectivity loss issues were encountered in the polymer flooding project. A series of measures are applied to enhance the injectivity. The injectivity enhancement strategies are proposed and conducted from three main aspects, namely, (1) surface polymer fluid preparation; (2) downhole wellbore stimulation; and (3) reservoir–polymer compatibility, respectively. For the surface polymer fluid preparation, a series of sieve flow tests are conducted to obtain the optimal mesh size to improve the polymer fluid preparation quality and reduce the amount of “fish eyes”. The downhole wellbore stimulations involve oxidization-associated acidizing treatment and re-perforation. Polymer–reservoir compatibility tests are conducted to optimize the molecular weight (MW). Regarding the surface measures, the optimal filtration sieve mesh number is 200, which could reduce fish eyes to a desirable level without causing mesh plugging. After mesh refinement, the average injection pressure of the twelve injection wells decreases by 0.5 MPa. For the downhole stimulations, acidizing treatment are applied to six injection wells, which decreases the injection pressures by 6 to 7 MPa. For Well A, where acidizing does not work, the re-perforation measure is used and enhances the injectivity by 300%. Moreover, the laboratory and field polymer–reservoir compatibility tests show that the optimal polymer molecular weight (MW) is sixteen million. Proposed strategies applied from the surface, downhole, and reservoir aspects could be used to resolve different levels of injectivity loss, which could provide guidance for future offshore polymer projects. Full article

China’s offshore heavy oil resources are abundant but underutilized. Circulating steam stimulation enhances production while increasing casing failure risks in thermal recovery wells. Accurately assessing casing performance after repeated thermal cycles is crucial for ensuring wellbore integrity. This paper presents tensile and creep experiments on TP110H casing under cyclic temperatures. The temperature distribution within the “casing-cement sheath-stratum” system is derived using heat transfer theory. Stress and displacement equations are established based on thick-walled cylinder theory and thermo-elasticity. Thermal coupling analysis assesses casing stress in straight, inclined, and sidetrack well sections. Key factors, including steam injection pressure, in situ stress, cement modulus, and prestress, are analyzed for their effects on cumulative strain below the packer. Strain-based methods evaluate casing safety. Results show that under thermal cycling at 350 °C, after 16 cycles, the casing’s elastic modulus, yield strength, and tensile strength decrease by 15.3%, 13.1%, and 10.1%, respectively, while the creep rate increases by 16.0%. Above the packer, the casing remains safe, but the lower section may be at risk. Using low-elasticity cement, higher steam injection pressure, and prestressing can help improve casing performance. This study provides guidance on enhancing casing safety and optimizing steam stimulation parameters. Full article

A high-temperature and high-pressure experimental device was upgraded to accommodate a maximum pressure of 40 MPa and a maximum temperature of 800 °C. Using this experimental device, one-dimensional oxidation displacement experiments were carried out via air injection in the Hudson original reservoir to change the pressure from low pressure (5 MPa) to high pressure (30 MPa) and via air injection after water injection under 30 MPa high-pressure conditions. A stable medium–high-temperature thermal oxidation front and displacement state could be formed in the experiments under different pressure measurements of 5 MPa, 15 MPa, and 30 MPa and in the air injection experiment after water injection under high pressure, at 30 MPa, which was similar to the oxidation front and displacement characteristics of heavy oil air injection in situ combustion. However, as the pressure increased, the air consumption and fuel consumption became smaller, and the temperature of the oxidation front became lower. And compared with the original reservoir, the air consumption and fuel consumption of air injection after water injection increased, and the temperature of the oxidation front became higher. This was completely different from the law of heavy oil in situ combustion. With the increase in pressure, the pore volume number (PV) of the injected air was smaller, the gas production/injection ratio was smaller, and the oil displacement efficiency was higher. Therefore, the stability of the 30 MPa high-pressure air injection displacement was better. The gas/oil ratio (GOR) produced by 30 MPa air injection after water injection in the experiment was stable, and air injection after water injection could reduce the water cut and greatly improve oil displacement efficiency. Therefore, air-injection-enhanced oil recovery technology was still feasible in the reservoir after water injection. Full article

Injecting liquid into the formation has an impact on the microstructure of the reservoir and formation fluids, and negative effects often lead to the failure of oil well stimulation measures to achieve the expected results. It is crucial to clarify the reasons for the decrease in the injection capability of low-permeability reservoirs in China and the mechanisms of the impact of on-site injection water quality. This study first conducted injection experiments with different water qualities. To study the micro factors that cause damage, clay mineral X-ray diffraction (XRD) analysis, high-pressure mercury injection experiments before and after damage, nuclear magnetic resonance (NMR) during the damage process, scanning electron microscopy (SEM) after damage, and energy dispersive spectroscopy elemental spectrum analysis (EDS) of incompatible sediment were carried out on the experimental core. In injection experiments with different water qualities, the permeability decreased by up to 65.35% when the injection volume reached 60 PV. The main causes of the decrease in injection capability are poor reservoir porosity and permeability and formation particle blockage. The particles mainly come from suspended particles, emulsified oil, migration of formation particles, and sediment formed by the injected water. This paper also proposes a reference for water quality index optimization in similar reservoirs. The new water quality index reduced permeability damage by at least 3.22%. Full article

Reservoir evaluation in multi-source systems is challenging because studies generally follow single-source principles. This limitation has substantially hindered the understanding of reservoir and hydrocarbon accumulation processes in source–reservoir systems. This study examines the Dingbian area of the Ordos Basin, China, and investigates the key factors controlling hydrocarbon accumulation in the Chang 9 reservoir of the Triassic Yanchang Formation within a multi-source system. The study area spans approximately 0.9 × 10⁴ km². First, by comparing the biological markers in Chang 9 crude oil with those of potential source rocks, the oil source of the Chang 9 reservoir was identified. The study area was subsequently divided into three provenance zones—northeast, northwest, and central mixed source areas—based on heavy mineral content and the orientation of sedimentary sand bodies. Additionally, well logging data, oil production data, petrographic thin sections, scanning electron microscopy (SEM), and mercury injection porosimetry were used to investigate the reservoir characteristics, oil reservoir features, and crude oil properties across different source areas. The results indicate that the oil source of the Chang 9 reservoir in the Dingbian area is the Upper Chang 7 source rock. The northwest source area exhibits superior reservoir properties compared to the other two zones. In the northwest source area, lithology-structure oil reservoirs are predominant, whereas the central mixed source area is characterized by structural-lithology oil reservoirs, and the northeast source area predominantly features lithology-controlled reservoirs. From the northwest to the central mixed source areas, and finally to the northeast source area, crude oil density and viscosity increase gradually, while the degree of oil–water separation decreases correspondingly. Based on these findings, the study concludes that the distribution of structures, lithology, and source rocks significantly influences the Chang 9 reservoirs in the Dingbian area. The controlling factors of oil reservoirs differ across the various source zones. In multi-source systems, evaluating oil reservoirs based on source zones provides more precise insights into the characteristics of reservoirs in each area. This approach provides more accurate guidance for exploration and development in multi-source regions, as well as for subsequent “reserve enhancement and production increase” strategies. Full article

Hydraulic fracturing is a crucial technology for resource development, such as shale gas, and its optimization is necessary to enhance development efficiency. However, evaluating fracture shapes involves technical uncertainties. Japan Organization for Metals and Energy Security (JOGMEC) and Kyoto University have conducted laboratory-scale hydraulic fracturing experiments using coagulable fluorescent resin as the injection fluid (resin fracturing test) to visualize hydraulic fractures and investigate their relationship with acoustic emissions (AEs) generated during fracturing. Since lab-scale experiments can only examine the phenomena near the injection hole owing to size limitations, we designed an experiment to apply the visualization method to the outcrop scale. This paper presents the results from an in situ, outcrop-scale hydraulic fracturing experiment conducted at the Kamioka Mine, Gifu Prefecture, Japan, from 2022 to 2023, with goals similar to those of the laboratory experiments. A resin fracturing borehole (RF1) with a diameter of 76 mm was core-drilled to a depth of approximately 10 m for the resin fracturing tests. AEs were observed in five boreholes drilled around RF1 at the same depth. Resin fracturing tests were performed at two different depths, with breakdown confirmed at both. A core of a larger diameter (205 mm) was recovered by coaxial overcoring around RF1, and resin-filled fractures were observed under black light on the core surfaces. After the resin fracturing experiment, two analyses were performed using the acquired core and AE data to predict the fracture extension and the mechanism of AE occurrence. We compared the distribution of AE events and visualized fractures in the core. Additionally, we compared the stress direction estimated from failure mechanism analysis using AE data with the maximum stress direction estimated from hydraulic fracturing. Our analysis provided several insights into fracture extension. The distribution of AE hypocenters was consistent with the direction of the hydraulic fractures confirmed by coring after the resin fracturing test. The failure mechanisms are classified based on the polarity of the first P-wave motion of the AE waveform. However, the actual scale of oil fields is significantly larger than that considered in this study. Discussing visible fractures created by hydraulic fracturing is deemed meaningful. We expect that the results of this study will provide valuable information for the precise estimation of hydraulic fractures. Full article

This article provides an overview of low-permeability reservoir development technologies, including carbon dioxide injection, nitrogen injection, air injection, natural gas injection, water injection (unstable water injection, advanced water injection), water–gas alternating injection, and hydraulic fracturing (hydraulic fracturing, repeated fracturing). These technologies have their own strengths and weaknesses in improving crude oil recovery and are significantly constrained by reservoir characteristics. This article uses specific cases such as the increase in CO₂ injection pressure in Yaoyingtai oilfield, which significantly improves recovery rate, nitrogen injection in Zhongyuan oilfield, which increases adjacent well production and single-well recovery rate, air injection in a certain block of Changqing oilfield, natural gas injection in Yushulin oilfield, which has the best effect under specific pressure, as well as the effects and problems of water injection technology, the increasing production effect, and potential risks of hydraulic fracturing, to deeply analyze the application effectiveness and influencing factors of various technologies. Through comparative analysis, it can be concluded that CO₂ injection has corrosion and gas channeling problems, nitrogen injection is limited by solubility, oxygen consumption in air injection is affected by temperature and pressure, natural gas injection is constrained by reservoir structure, water injection technology is unstable and difficult to determine timings, and fracturing technology faces difficulties in energy replenishment and time determination. Therefore, optimizing and applying these technologies rationally is of great significance for the efficient development of low-permeability reservoirs. Full article

The relative permeability of a fluid plays a vital role in numerical simulation studies of multiphase flow. Several empirical models are used to estimate relative permeability, but these models are often inaccurate due to differences in the assumptions under which it is formulated. A specific model of relative permeability can significantly impact the results of a simulation, so it is essential to select the most appropriate model. This study incorporates the numerical simulation of water flooding into several well-known classical and non-linear predictive models of relative permeability. Based on the comparison of classical predictive models, the results reveal that the predictions from the classical models were more closely aligned with experimental data during the pre-water injection phase. However, after the water injection, the models overestimated the average reservoir pressure. Due to this limitation, all classical models were unable to match water-cut data accurately. In contrast, the proposed non-linear model demonstrated superior performance in matching the water-cut data. Compared to classical models, it accurately predicted water cut and reservoir performance. The proposed model developed for sandstone reservoirs was able to predict k_rw (the relative permeability of water) and k_ro (the relative permeability of oil) with low errors (RMSE = 0.028 and 0.01, respectively). The R² values of the proposed model for k_ro and k_rw were 0.97 and 0.98, indicating excellent agreement with the experimental results. The proposed model also demonstrated a significant improvement in the accuracy of simulation data matching after water injection. Additionally, this model provides flexibility in parameter tuning and a solid foundation for relative permeability model development. By improving relative permeability modeling, this study enhances water flooding simulations for more efficient resource utilization and reduced environmental impact. This new approach improves the selection and development of appropriate models for numerical simulations of water flooding in sandstone reservoirs thereby enhancing predictions of reservoir performance. Full article

Background/Objectives: Commercial poultry flocks undergo Salmonella vaccinations to manage salmonellosis outbreaks. Due to reports of severe injection site reactions to Salmonella bacterins, assessment of local inflammatory responses is necessary. The objective was to assess local inflammatory and systemic humoral immune responses to commercial autogenous Salmonella bacterin vaccines (SV1 or SV2) following primary or secondary intradermal (i.d.) vaccination in Light-Brown Leghorns (LBLs). Methods: LBL pullets received primary (14 wks) or secondary (19 wks) vaccination by i.d. growing feather (GF) pulp injection of SV1, SV2, Salmonella Enteritidis (SE) lipopolysaccharide (LPS), or water–oil–water emulsion (V). Local leukocyte levels and relative cytokine mRNA expression were monitored before (0 d) and at 6 h, 1 d, 2 d, 3 d, 5 d, and 7 d post-GF pulp injection (p.i.). Blood was collected through 28 d post-primary or -secondary vaccination, and SE-specific antibodies were quantified via ELISA. Results: Primary vaccine administration increased local heterophil and macrophage levels and increased IL-6 and IL-8 mRNA expressions at 6 h p.i., independent of treatment. Secondary administration extended these local immune activities through 3 d p.i. and included prolonged IL-17A mRNA expression. Primary and secondary GF-pulp injection with V resulted in rapid lymphocyte recruitment by 6 h p.i., comprised primarily of CD4⁺ and γδ T cells. SV1 and SV2 also produced a T-dependent systemic humoral immune response, as indicated by the IgM-to-IgG isotype switch, along with a memory phenotype in the secondary response. Conclusions: These commercial-killed Salmonella vaccines, when prepared in water–oil–water emulsions, stimulated prolonged innate and T helper (Th) 17-type inflammatory responses at the injection site and produced a classic systemic humoral immune response after a second vaccination. Further research is needed to determine if extended inflammation influences adaptive immune responses in eliminating Salmonella infection. Full article