Conventional Gas Reservoirs Research Articles

Nanoporous Gas Transport in Shale Gas Reservoirs

In more conventional gas reservoirs, gas flow is simple, uncomplicated, and described by simple flux pressure drop expressions. In shale reservoirs however, this relationship takes the form of a more complex and multiscale flow process involving special flow mechanisms. Shale gas reservoirs often contain a significant number of nanopores leading to an apparent permeability that depends on pore fluid type, pore structure and pressure differentials. The complex geometry of shale reservoirs has drastically stimulated basic research on the transport mechanisms involved in the extraction of gas from shale formations. This study is aimed at studying the gas flow in nano pores. In this paper, permeation experiments for methane flow through nanoporous membranes were conducted and the effect of the pore size and pressure on the behaviour of the gas was analysed. The results obeyed the criteria to divide the flow stage into Darcy and Non-Darcy flow. As the pressure increases, the reservoir permeability also increases, and the gas tends to move faster thereby increasing the rate at which it flows per unit area in the system regardless of the temperature difference which means pressure gradient establishes the direction and rate of flow of gas in a reservoir.

Underground Gas Storage Construction in Gas Fields with Oil Ring and Edge and Bottom Water: A Case Study

ABSTRACT Most underground gas storages (UGSs) are constructed in gas fields, but there are few UGS examples constructed in a gas field with an oil ring and edge/bottom water (OR-EBW-gas field). In areas where suitable gas fields are not available for USG development, existing gas fields with oil ring and edge and bottom water have to be used to construct UGS to balance the seasonal natural gas consumption and supply. Compared with conventional gas reservoirs, fluid distribution is much more complicated in OR-EBW-gas fields and there exist different modes for storage space plan, which brings up more uncertainty for the UGS construction. In this work, an active UGS construction in an OR-EBW-gas field is studied using a comprehensive compositional numerical model. The operation parameters are firstly determined through detailed sensitivity studies. UGS construction schemes employing different porous medium spaces are then investigated to determine the optimal one. The results indicate that UGS constructed using gas cap area is the optimal scheme. After 20 I/W cycles, the predicted working load of the UGS is 1.726 × 108 m3, which reaches the designed value of 1.7 × 108 m3. The incremental cumulative water production and oil production are 0.21 × 104m3 and 0.42 × 104m3 respectively. The study shows that it is crucial to prevent the intrusion of edge water for UGS construction in an OR-EBW-gas field. The oil ring is not suitable for UGS construction due to its poor petrophysical property, but can be used as a natural barrier to separate gas cap and edge water. The formation pressure needs to be improved when the gas cap, oil ring and edge water are selected as USG construction zones. However, it will also lead to a significant increase in the formation pressure near the main control fault, which leads to a high risk of fault failure.

Fracability evaluation of the upper Cretaceous Naparima Hill Formation, Trinidad

The upper Cretaceous Naparima Hill Formation, a primary source rock for conventional oil and gas reservoirs in Southern and Columbus basins, Trinidad is now considered an unconventional reservoir. Effective fracability evaluation is critical to the entire process of unconventional reservoir exploitation. At present, there exists no information on the fracability of the Naparima Hill Formation. A recent study have shown that the Formation consist of four lithofacies (siliceous-calcareous mudstone, calcareous mudstones, carbonate-rich mudstone and siliceous mudstone) that are highly brittle, implying that they are easily fractured. This is debatable because brittle rocks can have a higher fracture toughness, making them more difficult to fracture. In this study, an existing fracability evaluation model that incorporates brittleness, fracture toughness, and minimum horizontal insitu stress was used to evaluate the fracability of the four lithofacies within the Naparima Hill Formation. Through a series of laboratory testing (measurements of P- and S-wave velocities, uniaxial compression tests and Brazilian tests) of the dry outcrop samples, elastic properties (Young's modulus and Poisson's ratio), uniaxial compressive strength and tensile strength were determined. X-ray diffraction analysis (XRD) was also performed on the outcrop samples to determine their mineral compositions. Brittleness indices based on the rock elastic properties, rock strength and mineral compositions were used to evaluate the rock brittleness, and the fracture toughness was estimated from the tensile strength. The study results indicate that all lithofacies are highly brittle, which is consistent with the previous study. The fracability evaluation results showed that the siliceous calcareous mudstones and siliceous mudstones are more fracable than the calcareous and carbonate-rich mudstones. The key factors that control the fracability of the Formation were found to be the amount of quartz, and the rock strength that is influenced by calcite cementation. • This paper presents fracability of the Naparima Hill Formation mudstones • Brittleness alone is not sufficient to evaluate the fracability of mudstones • High quartz content increases the fracability of the mudstones. • High fracture toughness and tensile strength lowers the fracability of the mudstones.

Geochemistry and sources of hydrate-bound gas in the Shenhu area, northern south China sea: Insights from drilling and gas hydrate production tests

Research on the origin and source of hydrate-bound gas and its relationship to deep conventional oil and gas accumulation in a basin is critical to understanding the accumulation mechanism of gas hydrates and to resource evaluation of gas hydrate accumulation. In this study, the hydrate-bound gas obtained via pressure coring and the production gas recovered during a production test on a gas hydrate reservoir in the Shenhu area offshore of Southern China were tested and discussed. The geochemical analysis results indicate that methane is the predominant gas, and heavier hydrocarbons (C2+) are also present but in low concentrations. The molecular compositions of the hydrate gas recovered from two production test sites are similar to those of the hydrate-bound gas acquired via pressure coring. In addition to the isotopic composition of the methane, the carbon and hydrogen isotopes of the C2+ hydrocarbons were obtained for the first time. The δ 13 C isotopes of the methane range from −66.6‰ to −46.2‰, indicating that the hydrate-bound gases have a mixed origin, containing both biogenic and thermogenic gases. The plot of δ 13 C 1 versus δ 13 C 2 suggests that the biogenic and thermogenic hydrocarbons were derived from marine organic matter and terrestrial organic matter, respectively. The isotopic characterization of the hydrate-bound gas reveals that the thermogenic hydrate gas contains both humic-type gas and sapropel-type gas, but the sapropel-type gas is predominant. The source rocks of the thermogenic hydrate gas are interpreted to be both the gas-prone coal measure strata of the Enping Formation and the oil-prone medium-deep lacustrine strata of the Wenchang Formation, the latter of which contributed more to the hydrocarbon supply of the gas hydrates. In addition, the maturity of the source rocks of the thermogenic hydrate gas may be lower than that of the deeply buried conventional hydrocarbons discovered in the Baiyun Sag-Panyu Low Uplift area. The seismic profile crossing the shallow gas hydrate accumulations and deep conventional gas reservoirs clearly shows that the proven LW3-1 thermogenic gas reservoir communicated with the gas hydrate stability zone through vertical migration pathways formed by high-angle faults and gas chimneys. This indicates that there was a cogenetic relationship between the thermogenic hydrate gas and the deep conventional hydrocarbon reservoir, which was supplied the thermogenic gas derived from both the Wenchang and Enping formations. The major implications of this finding are that it confirms, rather than theorizes, the identity of the hydrocarbon source rocks of the thermogenic hydrate gas in the Shenhu area for the first time, and it demonstrates the coupling relationship between the shallow gas hydrate accumulations and the deep conventional reservoirs proposed in previous studies. The mechanisms of hydrocarbon migration and gas hydrate accumulation in the production test gas hydrate reservoirs in the Shenhu area were also identified, providing a valuable reference for subsequent exploration and for the potential exploitation of gas hydrate reservoirs in the South China Sea. • The δ 13 C and δD isotopes of the heavier hydrocarbons (C2+) in the Shenhu area are obtained for the first time. • The origin of the hydrate gas obtained from the second trial production well in the Shenhu area is confirmed. • The hydrocarbon source rocks of the thermogenic hydrate gas in the Shenhu area are identified. • Coupled paragenetic relationship between shallow gas hydrate and deep petroleum system is revealed.

Pore evolution model and diagenetic evolution sequence of the Mesoproterozoic Xiamaling shale in Zhangjiakou, Hebei

Current research on diagenesis and its evolution focuses mainly on sandstone reservoirs. Conventional oil and gas reservoir observation techniques for characterizing shale reservoirs are limited, and comprehensive research on nanoscale pore variations, diagenesis and evolution of shale reservoirs, especially immature and low-maturity marine shale reservoirs, is relatively scarce. To reveal the diagenesis and evolution of low-maturity marine shale, geochemical and mineral analyses, quantitative characterization of the pore structure and qualitative characterization of the pore morphology were performed on the Xiamaling shale. With the burial and geothermal history, the Xiamaling diagenetic evolution sequence and the nanoscale pore system evolution were studied. The results show that smectite continually transforms to an illite-smectite (I/S) mixed layer and then quickly transforms to illite and chlorite; the kaolinite content gradually decreases as maturity increases. The hydrocarbon expulsion threshold of the Xiamaling shale is EqRo = 1.0%, and the porosity decreases to a minimum value of EqRo = 1.0% and then increases. The pore structure evolution model shows that the pore volumes (PVs) of micropores and macropores decrease to minima at approximately EqRo = 0.92% and 0.85%, respectively, and then increase; the mesopore PVs continuously decrease. Micropore and mesopore surface areas (SAs) decrease to their minima at approximately EqRo = 0.85% and 1.0%, respectively, and then increase; simultaneously, the macropore SAs continuously decrease. The main diagenetic types of the Xiamaling shale are compaction, dissolution, cementation, thermal maturation of organic matter (OM), and clay mineral transformation; it reaches period B of the middle diagenetic stage, and the diagenetic evolution sequence is determined. The pore system composition and variation characteristics of the Xiamaling shale are analysed, and a corresponding evolution model is established.

Evaluation of impact of surface diffusion on methane recovery via carbon dioxide injection in shale reservoirs

Injection of carbon dioxide into shale reservoirs is a promising technology for enhancing natural gas recovery and reducing greenhouse gas emissions. Nanoscale phenomena contribute to a significant difference in mass transfer processes within shale-gas reservoirs compared to conventional gas reservoirs. Previous investigations have shown the significance of surface diffusion to gas transfer mechanisms. Surface diffusion was added to an established apparent permeability model, which was then applied for the first time to numerical reservoir simulations to model CO2 injection techniques. Most publications to date have used a theoretical model to predict surface diffusion coefficient in a low-pressure condition, whereas, in this paper, it has been estimated from gravimetric experiments. Shale reservoirs, with different reservoir and petrophysical properties, were generated to investigate the efficiency of transport of CO2 via surface diffusion. A recently proposed fractal model for surface diffusion was used to investigate the impact of rock surface roughness on CH4 production. The results show that surface diffusion plays a significant role in increasing CH4 recovery by up to 3.2% when the average pore radius is less than 2 nm. In particular, a high surface fractal dimension can potentially enhance CH4 production by up to 1.5% and should not be neglected when the average pore radius is less than 1 nm. In areas with high surface capacity, adsorption of CO2 and desorption of CH4 molecules may increase by up to 2.74% and 2.3%, respectively, when compared to models with no surface diffusion. In all the reservoirs examined, geostatistical reservoir simulations showed that reservoir heterogeneity is not favourable to methane recovery via CO2 injection techniques, except for the Barnett shale reservoir. To the best of our knowledge, this work is the first to implement an apparent model within a reservoir simulator to investigate the impact of surface diffusion on methane recovery via CO2 injection techniques at various shale reservoirs with different properties.

An assessment of methane gas production from natural gas hydrates: Challenges, technology and market outlook

Natural gas hydrates are enormous energy resources occurring in the permafrost and under deep ocean sediments. However, the commercial or sustained production of this resource with currently available technology remains a technical, environmental, and economic challenge, albeit a few production tests have been conducted to date. One of the major challenges has been sand production due to the unconsolidated nature of hydrate bearing formations. This review presents progress in methane gas production from natural gas hydrate deposits, specifically addressing the technology, field production and simulation tests, challenges, and the market outlook. Amongst the production techniques, the depressurization method of dissociating natural gas hydrates is widely accepted as the most feasible option and it has been used the most in field test trials and simulation studies. The market for natural gas hydrates looks promising considering the increasing demand for energy globally, limited availability of conventional fossil fuels, and the low carbon footprint when using natural gas compared to liquid and solid fossil fuels. The major market setback currently is cheap gas from shale and conventional oil and gas reservoirs. Cited as: Shaibu, R., Sambo, C., Guo, B., Dudun, A. An assessment of methane gas production from natural gas hydrates: Challenges, technology and market outlook. Advances in Geo-Energy Research, 2021, 5(3): 318-332, doi: 10.46690/ager.2021.03.07

The impact of isothermal flow assumption on accuracy of pressure transient analysis results

AbstractAdiabatic expansion and viscous dissipation of fluid flow in porous media result in considerable heating or cooling of hydrocarbon fluids when pressure gradients are very large. Traditionally, fluid flow in porous media has been assumed isothermal in hydrocarbon reservoirs. While this assumption helps with simplifying the physics of fluid flow by neglecting the thermal effects, it imposes a dominant impact on fluid properties in situations where flow undergoes fast paced and abrupt changes in flow rate and or pressure. The analytical solutions of fluid flow for pressure transient analysis rely on the isothermal flow assumption. Since the variations of fluid properties are not accounted for in temperature fluctuations, there is an inherent error in standard methods of well test analysis. In this paper, the errors in pressure transient analysis as a consequence of the assumption of isothermal fluid flow are investigated. The magnitude of error is quantified as a function of flow rate and pressure drop. Error analysis shows that at higher flow rates, the thermal impacts are elevated such that the application of isothermal flow models becomes erroneous and invalid. It can be shown that oil well tests are more influenced by thermal effects compared to gas well tests in conventional dry gas reservoirs. This study highlights an important thermal impact that is often neglected and should be considered in the design, execution, and analysis stages of well testing. Also, it suggests that isothermal analytical models should be avoided for well test analysis with large flow rates.

The effect of gas production from deeper conventional gas reservoirs on shallower gas hydrate layer stability: A case study in the conditions of the Sakarya gas field, Western Black Sea

Gas hydrate deposits are generally found in the shallow deepwater regions and permafrost regions. The presence of water, methane, and thermodynamic conditions (low temperature and high pressure) is critical for gas hydrate accumulation. Disturbing thermodynamic conditions such as depressurizing and thermal treatment are the primary processes for gas hydrate dissociation. In this study, we investigate the stability of a shallow depth gas hydrate layer in the conditions of conventional gas production from a newly discovered deep gas field, Sakarya gas field, Western Black Sea. The study focuses on thermal conduction generated by conventional gas production across the wellbore profile along the gas hydrate section. The study includes wellbore simulations using the academic version of PIPESIM to obtain temperature and pressure profiles across the wellbore and numerical simulations for thermal transition for various cases in the hydrate zone using TOUGH + HYDRATE v.1.5 (T + H). The temperature elevation in the hydrate zone was found to change between 19 K and 25 K. The critical temperature elevation for hydrate dissociation and hydrate dissociation front were determined using the simulations, which might cause wellbore stability problems in the long term. We increase the impact of the study by suggesting appropriate solutions to minimize the adverse effects of production from the hot and deep conventional gas on gas hydrate stability found at shallower depths.

Correlation and difference between conventional and unconventional reservoirs and their unified genetic classification

The discovery and large-scale exploration of unconventional oil/gas resources since 1980s have been considered as the most important advancement in the history of petroleum geology. It has not only changed the balance of supply and demand in the global energy market, but also improved our understanding of the formation mechanisms and distribution characteristics of oil/gas reservoirs. However, misconceptions widely exist in studies of different types of petroleum accumulations because of the lack of a unified genetic classification. Unconventional reservoir has been used in the literature as a general name for various oil/gas reservoirs that are formed under complex dynamic mechanisms as long as buoyancy is not the major controlling factor. On the other hand, different terms have been given to the reservoirs even with the same formation mechanism. This paper selected six representative basins in China as the major subject of the study, analyzed the drilling results of 80,762 reservoir layers from 12,237 exploration wells in these basins. By investigating the progress of unconventional oil/gas exploration in North America in the past 30 years and addressing the distribution characteristics of discovered 52,926 oil/gas reservoirs in 1,186 basins around the world, this study revealed the correlations and differences of formation and distribution characteristics between conventional and unconventional oil and gas reservoirs. It was found that there are five correlations between conventional and unconventional reservoirs, including sharing the same oil and gas source, occurring in strata with the same geological age, coexisting in the same sedimentary basins, being confined in the same petroleum systems, and being enriched in the same reservoir layers. It was also found that there are five differences between conventional and unconventional reservoirs, including differences in hydrocarbon compositions, spatial relations to source rocks, reservoir lithology and quality, distribution in geological settings, and reservoir formation mechanism. Then, the unified genetic classification scheme is put forward to clarify their differences and correlations. All kinds of conventional and unconventional oil and gas resource are classified into 3 categories and 6 subcategories according to their dynamic mechanisms of formation, reclassified into 15 types based on main controlling factors, and further divided into 49 styles considering their underground occurrences. The application results show that all different oil/gas reservoirs can find their corresponding positions in the classification scheme, and all the oil/gas reservoirs with the same genetic mechanism, major controlling factor and occurrence can find their particular position in this classification scheme.

Brittleness Index of High-Rank Coal Reservoir and Its Influencing Factors in Mabidong Block, Qinshui Basin, China

Brittleness index is an important mechanical index to evaluate the fracturability of conventional oil and gas reservoirs. However, the brittleness index of an organic coal reservoir is more complex. In this study, based on array sonic logging and density logging data, coal brittleness index is calculated using an elastic parameter method in the Mabidong coalbed methane (CBM) block in southern Qinshui Basin. In combination with coal-body structure observation, the maceral analysis, and proximate data of coal cores, a comprehensive study of geological influencing factors of coal brittleness index has been carried out. According to coal fragmentation degree, the coal-body structure of coal seams can be divided into primary, cataclastic, and granulate structure. The average interval of brittleness index of primary, cataclastic, and granulate structural coals is 63.3-71.48, 73.01-74.85, and 77.41-82.77, respectively. The results indicate that generally the order of brittleness index is primary structural coal < cataclastic structural coal < granulate structural coal. Young’s modulus and the brittleness index have a good positive correlation. Poisson’s ratio and the brittleness index are negatively correlated in No. 3 coal seam but are positive correlated in No. 15 coal seam. The vitrinite content is positively correlated with brittleness index, and the inertinite content is negatively correlated. For the primary and cataclastic structure coal, the ash and volatile is positively correlated with the brittleness index. The correlation of brittleness index, macerals, and coal quality parameters in the primary structure coal is better than that of the cataclastic and granulate structure coal. The research results are helpful to guide the coal brittleness index and coal-body structure prediction in fracturing of CBM wells.

A quantitative study of the scale and distribution of tight gas reservoirs in the Sulige gas field, Ordos Basin, northwest China

Gas and water distribution is discontinuous in tight gas reservoirs, and a quantitative understanding of the factors controlling the scale and distribution of effective reservoirs is important for natural gas exploration. We used geological and geophysical explanation results, dynamic and static well test data, interference well test and static pressure test to calculate the distribution and characteristics of tight gas reservoirs in the H8 Member of the Shihezi Formation, Sulige gas field, Ordos Basin, northwest China. Our evaluation system examines the scale, physical properties, gas-bearing properties, and other reservoir features, and results in classification of effective reservoirs into types I, II, and III that differ greatly in size, porosity, permeability, and saturation. The average thickness, length, and width of type I effective reservoirs are 2.89, 808, and 598 m, respectively, and the porosity is > 10.0%, permeability is > 10 × 10−3 µm2, and average gas saturation is > 60%. Compared with conventional gas reservoirs, tight gas effective reservoirs are small-scale and have low gas saturation. Our results show that the scale of the sedimentary system controls the size of the dominant microfacies in which tight gas effective reservoirs form. The presence of different types of interbeds hinders the connectivity of effective sand body reservoirs. The gas source conditions and pore characteristics of the reservoirs control sand body gas filling and reservoir formation. The physical properties and structural nature of the reservoirs control gas-water separation and the gas contents of effective reservoirs. The results are beneficial for the understanding of gas reservoir distribution in the whole Ordos Basin and other similar basins worldwide.

Distribution Model of Fluid Components and Quantitative Calculation of Movable Oil in Inter-Salt Shale Using 2D NMR

Some inter-salt shale reservoirs have high oil saturations but the soluble salts in their complex lithology pose considerable challenges to their production. Low-field nuclear magnetic resonance (NMR) has been widely used in evaluating physical properties, fluid characteristics, and fluid saturation of conventional oil and gas reservoirs as well as common shale reservoirs. However, the fluid distribution analysis and fluid saturation calculations in inter-salt shale based on NMR results have not been investigated because of existing technical difficulties. Herein, to explore the fluid distribution patterns and movable oil saturation of the inter-salt shale, a specific experimental scheme was designed which is based on the joint adaptation of multi-state saturation, multi-temperature heating, and NMR measurements. This novel approach was applied to the inter-salt shale core samples from the Qianjiang Sag of the Jianghan Basin in China. The experiments were conducted using two sets of inter-salt shale samples, namely cylindrical and powder samples. Additionally, by comparing the one-dimensional (1D) and two-dimensional (2D) NMR results of these samples in oil-saturated and octamethylcyclotetrasiloxane-saturated states, the distributions of free movable oil and water were obtained. Meanwhile, the distributions of the free residual oil, adsorbed oil, and kerogen in the samples were obtained by comparing the 2D NMR T1-T2 maps of the original samples with the sample heated to five different temperatures of 80, 200, 350, 450, and 600 °C. This research puts forward a 2D NMR identification graph for fluid components in the inter-salt shale reservoirs. Our experimental scheme effectively solves the problems of fluid composition distribution and movable oil saturation calculation in the study area, which is of notable importance for subsequent exploration and production practices.

Gas–water two-phase productivity model for fractured horizontal wells in volcanic gas reservoirs with natural fractures

ABSTRACT Volcanic gas reservoirs, as new exploration and development fields, are rich in resources and have broad exploration and development prospects. However, compared with the conventional sandstone gas reservoirs, volcanic gas reservoirs have more complex storage and permeability mode, with multiple media including pores, caves and fractures, which determines the strong heterogeneity, complicated seepage mechanisms, and difficult development of volcanic gas reservoirs. To further improve the prediction accuracy of fractured horizontal well productivity in volcanic gas reservoirs, Xushen low-permeability volcanic gas reservoirs are presented as examples herein using the equation of motion based on the principle of equal flow. Considering the stress-sensitive effect, starting pressure gradient, high-speed turbulence effect, and dual porous medium structure, as well as combining the nature of gas and real gas state equations, a gas–water two-phase productivity model is established for a matrix-natural fracture-artificial fracture-wellbore volcanic gas reservoir fractured horizontal well. In addition, factors affecting production are studied. Results indicate that stress-sensitivity coefficient of different media has different effects on the production. The natural-fracture stress-sensitive coefficient has the greatest influence on production. With the increase of the natural-fracture stress-sensitive coefficient, the gas production decreases and the reduction amplitude changes little, which is almost uniform. When natural-fracture stress-sensitive coefficient is 0.08, gas well production decreases by 14.24%. The second is the artificial main fracture stress-sensitivity coefficient. With the increase of the artificial main fracture stress-sensitivity coefficient, the decrease of gas production becomes larger. When artificial main fracture stress-sensitivity coefficient is 0.1, gas well production decreases by 6.6%. The matrix stress-sensitivity coefficient on production is the least, almost zero. The high-speed nonlinear coefficient significantly affected the production. With the increase of the high-speed nonlinear coefficient, the gas well production decreases, and the decrease rate is faster and faster. When the high-speed nonlinear coefficient increases to 10000 m−1, gas well production decreases by 45.65%. However, the starting pressure gradient had little effect on production. Finally, the model is verified by the actual production data of Xushen1-H2 well. The average errors of the gas production, water production, and pressure calculations are 9.65%, 9.63%, and 9.8%, respectively. This study contributes positively to the productivity prediction of fractured horizontal wells in low-permeability volcanic gas reservoirs.

Hydrocarbon mixture and CO2 adsorptions in A nanopore-bulk multiscale system in relation to CO2 enhanced shale gas recovery

Thanks to the continuous depletion of conventional gas reservoirs, shale gas plays an important role to meet the global natural gas demand. The CO2 'huff-n-puff' process has been proven to be an effective method to enhance shale gas recovery and sequestrate CO2. Unlike conventional reservoirs, shale media can contain a significant number of nano-scaled pores and their pore volume can be comparable to that of macropores and fractures in which fluids behave as bulk. While previous works studied the mechanisms of CO2 ‘huff-n-puff’ process in shale gas exploitation, the volume partitioning between nanopores and macropores/fractures is not fully taken into account. In this work, we built a nanopore-bulk multiscale model with varying pore size distributions (PSDs) to study the CO2 'huff-n-puff' process in a constant volume depletion (CVD) setting by using density functional theory (DFT). We found that the volume partitioning effect on adsorption, fluid compositions, hydrocarbon mixture (C1, C2, and C3) recovery is significant in the CO2 'huff-n-puff' process. The majority of hydrocarbon mixtures can be released from micropores and smaller mesopores during the CO2 ‘huff’ and ‘soak’ process, while the average hydrocarbon densities in larger mesopores might increase. During the CO2 ‘huff’ and ‘soak’ process, due to a stronger confinement effect in smaller pores, the PSD case with a higher volume ratio of smaller pores releases fewer hydrocarbons, while stores more CO2 per unit pore volume. Overall, the volume partitioning has a significant effect on hydrocarbon adsorption, compositions, and recovery as well as CO2 storage during the CO2 ‘huff-n-puff’ process in shale gas exploitation and geological CO2 sequestration.

Diffusion-Based Modeling of Gas Transport in Organic-Rich Ultratight Reservoirs

SummaryThe complex pore structure and storage mechanism of organic-rich ultratight reservoirs make the hydrocarbon transport within these reservoirs complicated and significantly different from conventional oil and gas reservoirs. A substantial fraction of pore volume in the ultratight matrix consists of nanopores in which the notion of viscous flow may become irrelevant. Instead, multiple transport and storage mechanisms should be considered to model fluid transport within the shale matrix, including molecular diffusion, Knudsen diffusion, surface diffusion, and sorption. This paper presents a diffusion-based semianalytical model for a single-component gas transport within an infinite-acting organic-rich ultratight matrix. The model treats free and sorbed gas as two phases coexisting in nanopores. The overall mass conservation equation for both phases is transformed into one governing equation solely on the basis of the concentration (density) of the free phase. As a result, the partial differential equation (PDE) governing the overall mass transport carries two newly defined nonlinear terms; namely, effective diffusion coefficient, De, and capacity factor, Φ. The De term accounts for the molecular, Knudsen, and surface diffusion coefficients, and the Φ term considers the mass exchange between free and sorbed phases under sorption equilibrium condition. Furthermore, the ratio of De/Φ is recognized as an apparent diffusion coefficient Da, which is a function of free phase concentration. The nonlinear PDE is solved by applying a piecewise-constant-coefficient technique that divides the domain under consideration into an arbitrary number of subdomains. Each subdomain is assigned with a constant Da. The diffusion-based model is validated against numerical simulation. The model is then used to investigate the impact of surface and Knudsen diffusion coefficients, porosity, and adsorption capacity on gas transport within the ultratight formation. Further, the model is used to study gas transport and production from the Barnett, Marcellus, and New Albany shales. The results show that surface diffusion significantly contributes to gas production in shales with large values of surface diffusion coefficient and adsorption capacity and small values of Knudsen diffusion coefficient and total porosity. Thus, neglecting surface diffusion in organic-rich shales may result in the underestimation of gas production.

Effect of Stress-Sensitive Permeability and Porosity on Production Performance in Water-Soluble Gas Reservoirs

Abstract Water-soluble gas reservoirs have the characteristics of high temperature and high pressure (HTHP) and experience obvious pressure-sensitive effects during the production process. Therefore, the influences of formation water and dissolved natural gas in formation water on water-soluble gas reservoirs are different from conventional gas reservoirs. In view of this, this work first carried out a stress sensitivity test with irreducible water and variable internal pressure at high temperature for a water-soluble gas reservoir, showing that permeability loss ratio and effective stress have an exponential relationship, a result basically consistent with conventional tests. However, the stress sensitivity test result with irreducible water was greater than the stress sensitivity test result without irreducible water; porosity decreased slightly with increasing confining pressure, and the total decrease ratio was less than 5.2%, with an average of 3.01%. Second, a high-pressure, high-temperature, nuclear magnetic resonance (NMR) online detection system was introduced to detect the pore signal of core samples under different effective stress states, and pore compression and deformation characteristics were evaluated. Results show large pores to have been compressed slightly more than small pores, pores to be significantly compressed in the initial stage, and the greater the increase in effective stress, the more obvious the compression. Third, the occurrence and characteristic changes of irreducible water in the process of rock compression were detected by the NMR online system, indicating irreducible water to be difficult to migrate through compression in water-soluble gas reservoirs under slight compression of rock and pore structure and the occurrence and characteristics of irreducible water to have not changed significantly. Finally, by establishing a theoretical model of water-soluble gas reservoirs to simulate the water breakthrough of gas wells under stress sensitivity conditions, this work shows that when stress sensitivity exists, gas-well water breakthrough time is earlier and production is diminished.

Sequential distribution of gas reservoirs in the Hangjinqi area, Ordos Basin, North China: Application of continuous and discontinuous hydrocarbon accumulation mode

The gas accumulation mode can be divided into two types based on the migration and accumulation characteristics: discontinuous accumulation into the reservoir rocks and continuous accumulation within or adjacent to the source rocks. Correspondingly, there are three different gas reservoirs including conventional, unconventional, and those in a transitional state. To demonstrate the differences in the formation mechanisms and distribution features of the two accumulation types, we have scrutinized the continuous accumulation and discontinuous accumulation in the Hangjinqi area of the Ordos Basin in North China. Continuous gas accumulation (basin-centered gas and water-soluble gas, as well as potential coalbed methane and shale gas) and discontinuous accumulation (various conventional gas traps) are, respectively, distributed in the southern and northern regions of the Hangjinqi area, which may change with the source-rock quality, migration force, reservoir capacity, and trapping condition. We identified that the essential factors influencing the formation and current distribution of gas reservoirs are the hydrocarbon generation ability, porosity, and cap rock-trap combinations in the study area. An ideal complete gas reservoir sequence develops coalbed methane, shale gas, basin central gas, water soluble gas, and conventional gas reservoirs from the center to the edge of the basin. Understanding the distribution characteristics of continuous accumulation and discontinuous accumulation allows better prediction of the potential gas reservoir types with the knowledge of discovered reservoirs. We recommend exploring anticline gas reservoirs in areas north of the Boerjianghaizi fault and basin-centered gas reservoirs in areas south of the Boerjianghaizi fault. We also suggest performing further research on shale source rocks because the maturity and the burial depth of the marine-continental organic-rich shale in the Shanxi-Taiyuan Formations are recognized to be favorable for shale gas generation and preservation.

A Review of Gas Flow and Its Mathematical Models in Shale Gas Reservoirs

The application of horizontal wells with multistage hydraulic fracturing technologies has made the development of shale gas reservoirs become a worldwide economical hotspot in recent years. The gas transport mechanisms in shale gas reservoirs are complicated, due to the multiple types of pores with complex pore structure and special process of gas accumulation and transport. Although there have been many attempts to come up with a suitable and practical mathematical model to characterize the shale gas flow process, no unified model has yet been accepted by academia. In this paper, a comprehensive literature review on the mathematical models developed in recent years for describing gas flow in shale gas reservoirs is summarized. Five models incorporating different transport mechanisms are reviewed, including gas viscous flow in natural fractures or macropores, gas ad-desorption on shale organic, gas slippage, diffusion (Knudsen diffusion, Fick diffusion, and surface diffusion), stress dependence, real gas effect, and adsorption layer effect in the nanoshale matrix system, which is quite different from conventional gas reservoir. This review is very helpful to understand the complex gas flow behaviors in shale gas reservoirs and guide the efficient development of shale gas. In addition to the model description, we depicted the type curves of fractured horizontal well with different seepage models. From the review, it can be found that there is some misunderstanding about the essence of Knudsen/Fick diffusion and slippage, which makes different scholars adopt different weighting methods to consider them. Besides, the contribution of each mechanism on the transport mechanisms is still controversial, which needs further in-depth study in the future.

Quantum-Based Analytical Techniques on the Tackling of Well Placement Optimization

The high dimensional, multimodal, and discontinuous well placement optimization is one of the main difficult factors in the development process of conventional as well as shale gas reservoir, and to optimize this problem, metaheuristic techniques still suffer from premature convergence. Hence, to tackle this problem, this study aims at introducing a dimension-wise diversity analysis for well placement optimization. Moreover, in this article, quantum computational techniques are proposed to tackle the well placement optimization problem. Diversity analysis reveals that dynamic exploration and exploitation strategy is required for each reservoir. In case studies, the results of the proposed approach outperformed all the state-of-the-art algorithms and provided a better solution than other algorithms with higher convergence rate, efficiency, and effectiveness. Furthermore, statistical analysis shows that there is no statistical difference between the performance of Quantum bat algorithm and Quantum Particle swarm optimization algorithm. Hence, this quantum adaptation is the main factor that enhances the results of the optimization algorithm and the approach can be applied to locate wells in conventional and shale gas reservoir.