Search Results (95)

In comparison to shallow coal seams, deep coal seams exhibit characteristics of high temperature, pressure, and in-situ stress, leading to significant differences in reservoir properties that constrain the effective development of deep coalbed methane (CBM). This study takes the Carboniferous deep 8# coal seam in the Yulin area of Ordos basin as the research subject. Based on the test results from core drilling wells, a comprehensive analysis of the characteristics and variation patterns of coal reservoir properties and a comparative analysis of the exploration and development potential of deep CBM are conducted, aiming to provide guidance for the development of deep CBM in the Ordos basin. The research results indicate that the coal seams are primarily composed of primary structure coal, with semi-bright to bright being the dominant macroscopic coal types. The maximum vitrinite reflectance (R_o,max) ranges between 1.99% and 2.24%, the organic is type III, and the high Vitrinite content provides a substantial material basis for the generation of CBM. Longitudinally, influenced by sedimentary environment and plant types, the lower part of the coal seam exhibits higher Vitrinite content and fixed carbon (FC_ad). The pore morphology is mainly characterized by wedge-shaped/parallel plate-shaped pores and open ventilation pores, with good connectivity, which is favorable for the storage and output of CBM. Micropores (<2 nm) have the highest volume proportion, showing an increasing trend with burial depth, and due to interlayer sliding and capillary condensation, the pore size (<2 nm) distribution follows an N shape. The full-scale pore heterogeneity (fractal dimension) gradually increases with increasing buried depth. Macroscopic fractures are mostly found in bright coal bands, while microscopic fractures are more developed in Vitrinite, showing a positive correlation between fracture density and Vitrinite content. The porosity and permeability conditions of reservoirs are comparable to the Daning–Jixian block, mostly constituting oversaturated gas reservoirs with a critical depth of 2400–2600 m and a high proportion of free gas, exhibiting promising development prospects, and the middle and upper coal seams are favorable intervals. In terms of resource conditions, preservation conditions, and reservoir alterability, the development potential of CBM from the Carboniferous deep 8# coal seam is comparable to the Linxing block but inferior to the Daning–Jixian block and Baijiahai uplift. Full article

The production of gas and condensate from liquid-rich shale reservoirs, particularly within heterogeneous lacustrine systems, remains a critical challenge in unconventional hydrocarbon exploration due to intricate multiphase hydrocarbon partitioning, including gases (C₁–C₂), volatile liquids (C₃–C₇), and heavier liquids (C₇₊). This study investigates a 120-meter-thick interval dominated by lacustrine deposits from the Lower Cretaceous Shahezi Formation (K₁sh) in the Songliao Basin. This interval, characterized by high clay mineral content and silicate–pyrite laminations, was examined to identify the factors controlling hybrid shale gas condensate systems. We proposed the Hybrid Shale Condensate Index (HSCI), defined as the molar ratios of (C₁–C₇)/C₇₊, to categorize fluid phases and address shortcomings in traditional GOR/API ratios. Over 1000 samples were treated by geochemical pyrolysis logging, X-ray fluorescence (XRF) spectrum element logging, SEM-based automated mineralogy, and in situ gas desorption, revealing four primary controls: (1) Thermal maturity thresholds. Mature to highly mature shales exhibit peak condensate production and the highest total gas content (TGC), with maximum gaseous and liquid hydrocarbons at T_max = 490 °C. (2) Lithofacies assemblage. Argillaceous shales rich in mixed carbonate and clay minerals exhibit an intergranular porosity of 4.8 ± 1.2% and store 83 ± 7% of gas in intercrystalline pore spaces. (3) Paleoenvironmental settings. Conditions such as humid climate, saline water geochemistry, anoxic bottom waters, and significant input of volcanic materials promoted organic carbon accumulation (TOC reaching up to 5.2 wt%) and the preservation of organic-rich lamination. (4) Laminae and fracture systems. Silicate laminae account for 78% of total pore space, and pyrite laminations form interconnected pore networks conducive to gas storage. These findings delineate the “sweet spots” for unconventional hydrocarbon reservoirs, thereby enhancing exploration for gas condensate in lacustrine shale systems. Full article

The global emphasis on clean energy has increased interest in producing hydrogen from petroleum reservoirs through in situ combustion-based processes. While field practices have demonstrated the feasibility of co-producing hydrogen and oil, the question of which offers greater economic potential, oil, or hydrogen, remains central to ongoing discussions, especially as researchers explore ways to produce hydrogen exclusively from petroleum reservoirs. This study presents the first integrated techno-economic model comparing oil and hydrogen production under varying injection strategies, using CMG STARS for reservoir simulations and GoldSim for economic modeling. Key technical factors, including injection compositions, well configurations, reservoir heterogeneity, and formation damage (issues not addressed in previous studies), were analyzed for their impact on hydrogen yield and profitability. The results indicate that CO₂-enriched injection strategies enhance hydrogen production but are economically constrained by the high costs of CO₂ procurement and recycling. In contrast, air injection, although less efficient in hydrogen yield, provides a more cost-effective alternative. Despite the technological promise of hydrogen, oil revenue remains the dominant economic driver, with hydrogen co-production facing significant economic challenges unless supported by policy incentives or advancements in gas lifting, separation, and storage technologies. This study highlights the economic trade-offs and strategic considerations crucial for integrating hydrogen production into conventional petroleum extraction, offering valuable insights for optimizing hydrogen co-production in the context of a sustainable energy transition. Additionally, while the present work focuses on oil reservoirs, future research should extend the approach to natural gas and gas condensate reservoirs, which may offer more favorable conditions for hydrogen generation. Full article

Gravity segregation is a critical phenomenon in thick condensate gas reservoirs, significantly influencing fluid composition and phase behavior. Reservoir-scale numerical simulation, serving as an indispensable technical approach in modern petroleum engineering, provides both quantitative data support and theoretical frameworks for development strategy optimization. However, the impact of gravity segregation on the distribution of initial fluid compositions is often overlooked in conventional numerical simulations due to data limitations or underestimated importance. This oversight leads to systematic deviations between simulated reservoir performance and actual field observations, ultimately compromising the efficient development of reservoirs. This study analyzed PVT data from reservoir fluid samples at different depths to determine the initial fluid composition distribution. Two models were developed: one incorporating gravity segregation and another neglecting it, to evaluate their performance during gas injection. Key findings include: (i) Gravity segregation alters the initial fluid composition, creating lighter components near the reservoir top and heavier ones at the bottom, resulting in distinct phase behaviors and production dynamics. (ii) The model accounting for gravity segregation aligns better with historical production data, while the model neglecting it underestimates oil production rates by about 9% and overestimates oil recovery by 2–5% during gas injection, due to inaccurate fluid composition assumptions. (iii) The model without gravity segregation also underestimates differences in oil recovery between injection–production strategies, such as top versus bottom injection. This study highlights the critical role of gravity segregation in reservoir simulation and provides valuable insights for optimizing the development of condensate gas reservoirs with complex fluid distributions. The findings reveal that accounting for gravity segregation in reservoir simulation models through proper initialization of fluid distribution leads to improved simulation accuracy, thereby enabling more precise development strategy design. Full article

With the increase in exploration in recent years, buried hill condensate gas reservoirs have gradually become an important field for increasing reserves and production of offshore oil and gas in China, and efficient development of condensate gas reservoirs has also become a hot issue in hydrocarbon development. Due to the complex phase-change law and retrograde condensation phenomenon of deep condensate gas reservoirs, the reservoir properties and production dynamics data obtained by conventional pressure-recovery-test methods were greatly limited, and the dynamic data and evaluation parameters of the single well control area cannot be accurately determined. In this paper, using the production analysis method to analyze the production dynamics data of a single well, combined with static geological data and well-test analysis data, the reservoir parameters of a single well were evaluated. Specifically, the Blasingame method was applied to realize the production-decline law of production wells, and new dimensionless flow, pressure parameters, and pseudo-time functions were introduced. Using the unstable well test theory and the traditional production decline analysis technology, the IHS Harmony software is used to fit the production dynamic data with the theoretical chart. The evaluation parameters such as reservoir permeability, skin factor, well control radius, and well control reserves were calculated, providing strong support for the production decision-making of the petroleum industry and also providing a strong decision-making basis for the dynamic adjustment of oil–gas-well manufacture. Full article

In view of the flow zoning phenomenon existing in condensate gas reservoirs and the complex pore structure and strong heterogeneity of carbonate rock reservoirs, this study investigates the pressure dynamic behavior during the development process of such gas reservoirs by establishing corresponding models. The model divides the reservoir into three zones. The fluid flow patterns and reservoir physical property characteristics in the three regions are different. In particular, the fracture system in zone 1 has permeability stress sensitivity. The model is solved and the sensitivity analysis of the key parameters is carried out. The research results show that reservoir flow can be divided into 12 stages. Stress sensitivity affects all stages except the wellbore storage stage and becomes increasingly obvious over time. The closed boundary causes fracture closure from the lack of external energy, reducing effective flow channels and triggering the boundary response stage earlier. The increased condensate oil increases the flow resistance and pressure loss, and shortens the duration of the flow stage. The research suggests that improving reservoir conditions and enhancing fluid fluidity can reduce pressure loss and increase production capacity, providing valuable theoretical and practical guidance for the development of carbonate rock condensate gas reservoirs. Full article

The complex interaction of hydrothermal fluids and carbonate rocks is recognized to promote significant impacts on petroleum systems, reservoir porosity, and potential. The objective of this study is to investigate the fluid phases entrapped in the mineral phases of the Barra Velha Formation (Santos Basin), including their petrographic paragenetic relationships, relative timing, temperatures of migration events, and maximum temperature reached by the sedimentary section. The petrographic descriptions (387), Rock-Eval pyrolysis (107), fluid inclusion petrography (14), and microthermometry (428) were performed on core and sidewall samples from two wells from one field of the Santos Basin. Hydrocarbon source intervals were primarily identified in lithologies with high argillaceous content. Chert samples still retain some organic remnants indicative of their original composition prior to extensive silicification. Redeposited intraclastic rocks exhibit the lowest organic content and oil potential. A hydrothermal petroleum system is identified by fluids consisting in gas condensate, light to heavy undersaturated oil, occasionally accompanied by aqueous fluids influenced by juvenile and evaporitic sources, and localized flash vaporization events. These hydrothermal fluids promoted silicification and dolomitization, intense brecciation, and lead to enhanced porosity in different compartments of the reservoir. The relative ordering of paleo-hydrothermal oils and the main oil migration and accumulation events has improved our understanding of the petroleum systems in the basin. This contribution is significant for future regional research on the evolution of fluid systems and their implications for carbonate reservoirs. Full article

Accurately delineating the range of the Xiang-E submarine uplifts is the key to the exploration and development of Silurian shale gas in the Western Hunan–Hubei region. Based on the graptolite stratigraphic division of Well JD1 in Jianshi area, Hubei Province, and combined with the GBDB online database (Geobiodiversity Database), the study compared the shale graptolite sequences of the Wufeng Formation and Longmaxi Formation from 23 profile points and 11 wells which cross the Ordovician–Silurian boundary. The range of the Xiang-E submarine uplift was delineated, and its evolution model and formation mechanism at the Ordovician–Silurian transition were discussed. The graptolite stratigraphic correlation results of drillings and profiles confirmed the development of submarine uplifts in the Western Hunan–Hubei region at the Ordovician–Silurian transition–Xiang-E submarine uplift. Under the joint control of the Guangxi movement and the global sea-level variation caused by the condensation and melting of polar glaciers, the overall evolution of the Xiang-E submarine uplift is characterized by continuous uplift from the Katian Age to the early Rhuddanian Age, with the influence gradually expanding, and then gradually shrinking back in the middle and late Rhuddanian Age. The initial form of the Xiang-E submarine uplift may have originated from the Guangxi movement, and the global sea-level variation caused by polar glacier condensation and melting is the main controlling factor for the changes in its influence range. Within the submarine uplifts range, the Wufeng–Longmaxi Formations generally lack at least two graptolite zone organic-rich shales in the WF2-LM4, and the shale gas reservoir has a poor hydrocarbon generation material foundation, posing a high risk for shale gas exploration. The Silurian in Xianfeng, Lichuan, Yichang of Hubei and Wushan of Chongqing has good potential for shale gas exploration and development. Full article

The Dibei Gas Field, located in the northern Kuqa Foreland Basin, Tarim Basin, western China, is one of the most important condensate gas-producing areas in China, with over one trillion cubic feet of gas reserves discovered in the Jurassic terrestrial reservoirs. However, further hydrocarbon exploration and development in the area is hampered by uncertainties on the petroleum sources. A robust oil–source and gas-source correlation analysis was carried out in the Dibei area to enhance our understanding of the gas accumulation potential. An integrated molecular geochemical analysis, multivariate analysis, and basin modeling were conducted to investigate source rocks, inclusion oils, reservoir oils, and gas from the Dibei area. Two types of source rocks have been identified in the Dibei area: a Jurassic coaly source rock and a Triassic lacustrine source rock based on multivariate analysis. The compositions of the n-alkanes, steranes, and terpanes and the carbon isotope ratios of individual n-alkanes in the inclusion oil extracts and reservoir oils from Jurassic Yangxia and Ahe reservoirs show distinct differences when compared with the two types of source extracts. Multiple oil sources are revealed in the Dibei area, with various degrees of mixing between reservoir oil (present) and inclusion oil (paleo), reflecting evolving oil sources. Basin modeling shows that during the late Himalayan orogeny, the Jurassic strata in the Dibei area experienced a rapid burial within ~20 Ma, with the oil generation window of the source rocks expanding greatly. This caused the shallowly buried Jurassic source rocks to enter the oil generation window, resulting in the occurrence of two oil sources for the inclusion oils and reservoir oils, and an increasing degree of mixing over time. Our finding confirms that the accumulated condensate gas in the Dibei area is mainly derived from the Jurassic source rocks. This allows the extent of prospective exploration to be better defined. Full article

The exploitation of Block L within the Tarim Basin oilfield commenced in 1989 and it has transitioned from the natural energy development stage to the current water injection development stage. Despite this, the efficacy of water flooding remains suboptimal, with the low degree of control, uneven utilization of reserves, and subpar mining outcomes. The block still contains substantial remaining oil resources, necessitating continued extraction. Notably, the primary oil produced in this block is condensate oil, which commands a high economic value. To enhance the oil recovery efficiency of the block reservoir, a development plan employing alternating and water-natural gas flooding has been proposed. The objective of this study is to evaluate the feasibility of the proposed alternating displacement scheme involving natural gas and water in this reservoir. The specific steps include PVT fitting, historical matching, residual oil evaluation, and the optimization of gas injection parameters. Results show that for this reservoir the water-natural gas flooding (WAG) is the optimal option. And this article has the application of WAG flooding simulation, simulating 15 years of operation. Compared with the original development scheme of the original well pattern, the recovery of this reservoir is increased by 12.05%, which provided a reference basis for the on-site application of WAG in this reservoir. Full article

The SAGP (steam and gas push) process is an effective enhanced oil recovery (EOR) method for heavy oil reservoirs. Understanding the microscopic interactions among steam, non-condensable gasses (NCGs), and heavy oil under reservoir conditions in SAGP processes is important for their EOR applications. In this study, molecular simulations were performed to investigate the microscopic interactions among steam, NCG, and heavy oil under reservoir conditions in SAGP processes. In addition, the microscopic EOR mechanisms during SAGP processes and the effects of operational parameters (NCG type, NCG–steam mole ratio, temperature, and pressure) were discussed. The results show that the diffusion and dissolution of CH₄ molecules and the extraction of steam molecules cause the molecules of saturates with light molecular weights in the oil globules to stretch and gradually detach from one another, resulting in the swelling of heavy oil. Compared with N₂, CH₄ has a stronger ability to diffuse and dissolve in heavy oil, swell the heavy oil, and reduce the density and viscosity of heavy oil. For this reason, compared with cases where N₂ is used, SAGP processes perform better when CH₄ is used, indicating that CH₄ can be used as the injected NCG in the SAGP process to improve heavy oil recovery. As the NCG–steam mole ratio and injection pressure increase, the diffusion and solubility abilities of CH₄ in heavy oil increase, enabling CH₄ to perform better in swelling the heavy oil and reducing the density and viscosity of heavy oil. Hence, increasing the NCG–steam mole ratio and injection pressure is helpful in improving the performance of SAGP processes in heavy oil reservoirs. However, the NCG–steam mole ratio and injection pressure should be reasonably determined based on actual field conditions because excessively high NCG–steam mole ratios and injection pressures lead to higher operation costs. Increasing the temperature is favorable for increasing the diffusion coefficient of CH₄ in heavy oil, swelling heavy oil, and reducing the oil density and viscosity. However, high temperatures can result in intensified thermal motion of CH₄ molecules, reduce the interaction energy between CH₄ molecules and heavy oil molecules, and increase the difference in the Hildebrand solubility parameter between heavy oil and CH₄–steam mixtures, which is unfavorable for the dissolution of CH₄ in heavy oil. This study can help readers deeply understand the microscopic interactions among steam, NCG, and heavy oil under reservoir conditions in SAGP processes and its results can provide valuable information for the actual application of SAGP processes in enhancing heavy oil recovery. Full article

The natural gas industry has developed rapidly in recent years, with gas storage playing an important role in regulating winter and summer gas consumption and ensuring energy security. The Ke7010 sand body is a typical edge water condensate gas reservoir with an oil ring, and the construction of gas storage has been started. In order to clarify the feasibility of synergistic storage building for gas injection and production, the fluid characteristics during the synergistic reservoir building process were investigated through several rounds of drive-by experiments. The results show that the oil-phase flow capacity is improved by increasing the number of oil–water interdrives, and the injection and recovery capacity is improved by increasing the number of oil–gas interdrives; the reservoir capacities of the high-permeability and low-permeability rock samples increase by about 4.84% and 7.26%, respectively, after multiple rounds of driving. Meanwhile, a numerical model of the study area was established to simulate the synergistic storage construction scheme of gas injection and extraction, and the reservoir capacity was increased by 7.02% at the end of the simulation period, which was in line with the experimental results. This study may provide a reference for gas storage construction in the study area. Full article

A major problem in natural gas production is the waterlogging of gas wells. This problem occurs at the end of a well’s life when the reservoir pressure becomes low and the gas velocity in the well tubing is no longer sufficient to bring the gas-related fluids (water and gas condensate) up to the surface. This causes water to accumulate at the bottom of the gas well, which can seriously reduce or even stop gas production altogether. This paper presents a study of the foaming of reservoir water using foaming sticks with the trade names BioLight 30/380, BioCond 30, BioFoam 30, BioAcid 30/380, and BioCond Plus 30/380. The reservoir waters tested came from near-well separators located at three selected wells that had undergone waterlogging and experienced a decline in natural gas production. They were characterised by varying physical and chemical parameters, especially in terms of mineralisation and oil contaminant content. Laboratory studies on the effect of foaming agents on the effectiveness of foaming and lifting of reservoir water from the well were carried out on a laboratory bench, simulating a natural gas-producing column using surfactant doses in the range of 1.5–5.0 g/m³ and measuring the surface tension of the water, the volume of foam generated as a function of time and the foamed reservoir water. The performance criterion for the choice of surfactant for the test water was its effective lifting in a foam structure from an installation, simulating a waterlogged gas well and minimising the dose of foaming agent introduced into the water. The results obtained from the laboratory tests allowed the selection of effective surfactants in the context of foaming and uplift of reservoir water from wells, where a decline in natural gas production was observed as a result of their waterlogging. In the next stage, well tests were carried out based on laboratory studies to verify their effectiveness under conditions typical for the production site. Tests carried out at natural gas wells showed that the removal of water from the bottom of the well resulted in an increase in natural gas production, ranging from 56.3% to 79.6%. In practice, linking the results of laboratory tests for the type and dosage of foaming agents to the properties of reservoir water and gas production parameters made it possible to identify the types of surfactants and their dosages that improve the production of a given type of natural gas reservoir in an effective manner, resulting in an increase in the degree of depletion of hydrocarbon deposits. Full article

Hydrocarbon fields that contain non-associated gas, such as gas condensate, are highly valuable in terms of production. They yield significant amounts of condensate alongside the gas, but their unique behavior presents challenges. These reservoirs experience constant changes in composition and phases during production, which can lead to condensate blockage near wells. This blockage forms condensate bridges that hinder flow and potentially decrease gas production. To address these challenges, engineers rely on numerical simulation as a crucial tool to determine the most effective project management strategy for producing these reservoirs. In particular, relative permeability curves are used in these simulations to represent the physical phenomenon of interest. However, the representativeness of these curves in industry laboratory tests has limitations. To obtain more accurate inputs, simulations at the pore network level are performed. These simulations incorporate models that consider alterations in interfacial tension and flow velocity throughout the reservoir. The validation process involves reproducing a pore network flow simulation as close as possible to a commercial finite difference simulation. A scale-up methodology is then proposed, utilizing an optimization process to ensure fidelity to the original relative permeability curve at a microporous scale. This curve is obtained by simulating the condensation process in the reservoir phenomenologically, using a model that captures the dependence on velocity. To evaluate the effectiveness of the proposed methodology, three relative permeability curves are compared based on field-scale productivities and the evolution of condensate saturation near the wells. The results demonstrate that the methodology accurately captures the influence of condensation on well productivity compared to the relative permeability curve generated from laboratory tests, which assumes greater condensate mobility. This highlights the importance of incorporating more realistic inputs into numerical simulations to improve decision-making in project management strategies for reservoir development. Full article

This study investigates the complex dynamics of retrograde condensation in condensate gas reservoirs, with a particular focus on the challenges posed by retrograde condensate pollution, which varies in condensate oil content and impacts on reservoir productivity. Numerical simulations quantify the distribution of condensate oil and the reduction in gas-phase relative permeability in reservoirs with 100.95 g/m³, 227.27 g/m³, and 893.33 g/m³ of condensate oil. Unlike previous studies, this research introduces an orthogonal experiment to establish a methodology for studying the dynamic sensitivity factors across different types of gas reservoirs and various development stages, systematically evaluating their contributions to condensate oil. The analysis reveals that reservoirs with low to moderate condensate oil content gradually experience expanding polluted regions, affecting long-term production. The maximum condensate saturation near the wellbore can reach 0.19, reducing gas-phase relative permeability by about 25.44%. In contrast, high-condensate oil reservoirs show severe early-stage retrograde condensation, with saturations up to 0.35 and a permeability damage rate reaching 73%. The orthogonal experiments identify reservoir permeability and condensate oil content as critical factors influencing production indicators. The findings provide key insights and practical recommendations for optimizing production strategies, emphasizing tailored approaches to mitigate retrograde condensation and enhance recovery, especially in high-condensate oil reservoirs, offering theoretical and practical guidance for improving reservoir management and economic returns. Full article