Dry Gas Reservoirs Research Articles

Key Characteristics and Controlling Factors of the Gas Reservoir in the Fourth Member of the Ediacaran Dengying Formation in the Penglai Gas Field, Sichuan Basin

This study focuses on the PS8 well in the Penglai Gas Field (Sichuan Basin), a newly identified key exploration area, where high-yield gas testing has been achieved from the Ediacaran Fourth Member of the Dengying Formation. Comprehensive analyses of drilling cores, cuttings, thin sections, analytical data, well logging, and production testing data were conducted to investigate the main characteristics of the gas reservoir and the factors controlling the formation model of the reservoir. The results reveal that the reservoir rocks in the Fourth Member of the Dengying Formation are primarily algal-clotted dolomite, algal-laminated dolomite, and arenaceous dolomite. The reservoir porosity is dominated by secondary pores, such as algal-bonded framework pores, intergranular dissolved pores, and intercrystalline dissolved pores, which contribute to the overall low porosity and extremely low permeability. The gas reservoir is classified as a unified structural–lithological reservoir, with the upper sub-member of the Fourth Member serving as a completely gas-bearing unit. This unit is characterized as an ultra-deep, dry gas reservoir with medium sulfur and medium CO2 contents. The development of this gas reservoir follows a “laterally generated and laterally stored, upper generation and lower storage” reservoir formation model. Regional unconformities and fracture systems developed during the Tongwan II Episode tectonic movement provide efficient pathways for hydrocarbon migration and accumulation. The high-quality source rocks in the lower Cambrian Qiongzhusi Formation serve as both the direct cap rock and lateral seal of the gas reservoir, creating an optimal source–reservoir spatial configuration. This study provides valuable insights into the giant gas reservoir of the Dengying Formation, which can aid in optimizing exploration activities in the Sichuan Basin.

Phase Behavior and Compression Factors of Ultradeep Condensate and Dry Gas Reservoir under High Temperature and Pressure: Experiment and Calculation

Phase Behavior and Compression Factors of Ultradeep Condensate and Dry Gas Reservoir under High Temperature and Pressure: Experiment and Calculation

Numerical investigation on heat extraction performance of supercritical CO2 in depleted oil and gas reservoirs

Using supercritical CO2 (sCO2) for geothermal exploitation not only improves the heat extraction rate and saves injection-production energy consumption, but also gains environmental benefit of carbon sequestration. Compared to hot dry rock, depleted oil and gas reservoirs are nature porous reservoirs harboring abundant geothermal resources, in which artificial reservoir fracturing is unnecessary prior to the geothermal extraction. Besides, a lot of pre-existing oil-gas well networks along with ground facilities can be reutilized, significantly reducing geothermal drilling costs. This paper conducts a numerical investigation on using sCO2 for heat extraction in depleted oil and gas reservoirs. Firstly, A coupled wellbore-reservoir model is established to analyze the flow and heat transfer characteristics of sCO2 in the reservoir and injection-production well. Secondly, the variation of sCO2 gas saturation, production temperature, production rate and heat extraction rate are studied. Finally, the influence of different factors on sCO2 heat extraction performance is examined. The results indicate that the maximum sCO2 heat extraction rate is 18.45 MW, and the temperature rise of sCO2 within the reservoir is still higher than 24 °C after 30 years. To enhance sCO2 heat extraction performance, reducing injection temperature, increasing production pressure and well spacing are advisable. In the case of multi-well scheme, a higher ratio of production wells to injection wells and a decentralized arrangement pattern are encouraged. The findings of this paper are anticipated to provide theoretical basis and technical support for efficient geothermal harvest in depleted oil and gas reservoirs and potential appropriate option in building heating.

Impact of Material Balance Calculation on Trapped Gas in Water-drive Gas Reservoir

Abstract The development of water-drive gas reservoir takes a very important position in China. Not only its recovery is markedly lower than that of dry gas reservoir, but also its residual gas saturation is higher. The main reason has been proven in the lab is water invasion which can generate trapped gas by sealing gas in porous media. However, it is still difficult to calculate the volume of trapped gas theoretically and practically. In order to quantify trapped gas, we designed experiments to simulate the development of water-drive gas reservoir. The experimental system can provide accurate measurements on gas production, water influx, pressure and so on. The results showed that the original material balance equations are not consistent with experimental data when water invasion happens. With water influx increasing, the errors become more obvious. This phenomenon has been repeated for many times in our lab. On basis of this phenomenon and with the analysis of many experimental data, we observed that water influx causes some high pressure trapped gas which is not considered in original material balance equation. By regression analysis, we proposed a correction term which can be added to the original material balance equation to effectively eliminate the disagreements between the results of original equation and the experiments. The modified material balance equation was also verified by field cases. The correction term can be applied to quantify the degree of trapped gas, which is significant to calculate the water influx and to predict production and improves the original material balance equation so that the trapped gas in water-drive gas reservoir can be fully considered. The correction term is proposed through statistical regression analysis based on a large number of experimental data. The modified material balance equation with the correction term can quantify the trapped gas and have a great significant impact on the development of water-drive gas reservoir, especially on the water influx calculation and production prediction.

Geochemical Characteristics and Origin of Natural Gas in the Middle of Shuntuoguole Low Uplift, Tarim Basin: Evidence from Natural Gas Composition and Isotopes

Multiple types of reservoirs, including volatile oil reservoirs, condensate gas reservoirs, and dry gas reservoirs, have been discovered in ultra-deep layers buried at depths greater than 7500 m. Understanding the genetic types of natural gas is of utmost importance in evaluating oil and gas exploration potential. The cumulative proved reserves of the super deep layer in the Shuntuoguole low uplift area of the Tarim Basin exceed 1 × 108 t (oil equivalent). The origin, source, and accumulation characteristics of natural gas still remain a subject of controversy. By analyzing the composition and carbon isotope of natural gas, a detailed investigation was conducted to examine the unique geochemical and reservoir formation characteristics of the Ordovician ultra-deep natural gas within different fault zones in the middle region of the Shuntuoguole low uplift. It was determined that most of the natural gas in this area is displaying a characteristic of wet gas with a drying coefficient ranging from 0.41 to 0.99. The carbon isotope composition of methane in the gas reservoir shows relatively light values, ranging from −49.4‰ to −42‰. The carbon and hydrogen isotopes of the components are distributed in a positive order. The natural gas is oil type gas, which is derived from marine sapropelic organic matter and has a good correspondence with the lower Yuertusi formation. The maturity of natural gas in Shunbei No. 1 and No. 5 fault zones is about 1.0%, which is the associated gas of normal crude oil, while the maturity of No. 4 and No. 8 fault zones is higher than 1.0%, which is the mixture of kerogen pyrolysis gas and crude oil pyrolysis gas. The variations in the drying coefficient and carbon isotope composition of the natural gas provide evidence for the migration patterns within the Shuntuoguole low uplift central region. It indicates that the Shunbei No. 5 and No. 8 fault zones have likely migrated from south to north, while the No. 4 fault zone has migrated from the middle to both the north and south sides. These migration patterns are primarily controlled by high and steep strike-slip faults, which facilitate the vertical migration of natural gas along fault planes. Consequently, the gas accumulates in fractured and vuggy reservoirs within the Ordovician formation.

Fluid inclusion records of oil-cracked wet gas in Permian carbonate reservoirs from the Eastern Sichuan Basin, China

Oil-cracked gas is an important gas resource in petroliferous basins. In theory, oil-cracked gas should be rich in C2+ (i.e., wet gas). However, gas reservoirs of oil cracking origin in the Sichuan Basin (South China) are mainly composed of dry gas. Fluid inclusions record hydrocarbon generation and evolution. Obviously, identifying wet gas inclusions is the key to solving the above controversy. Here, we calibrate the Raman spectroscopic detection limits of ethane and propane (0.007 and 0.016 MPa, respectively) and demonstrate that Raman spectroscopy is a powerful method to identify C2+-bearing inclusions. Based on this technique, C1–C2–C3-bearing wet gas inclusions (C1/ƩCi = 0.90–0.93) are identified in calcite cements of the Permian Changxing Formation carbonate reservoir in the Eastern Sichuan Basin. These inclusions are direct geological evidence of oil-cracked gas because the calcite cement precipitated after the formation of pyrobitumen. Furthermore, reconstruction of the temperature-pressure-composition evolutions of calcite-hosted (Changxing Formation) and quartz-hosted gas inclusions in the Ordovician Wufeng–Silurian Longmaxi Formation black shale indicates that high pressure can effectively retard the cracking of C2+ gas hydrocarbons. Differences in gas composition and δ13CCH4 signature between reservoir gas and inclusion gas lead us to conclude that large-scale oil cracking occurred during the Early–Middle Jurassic in the Permian Changxing carbonate reservoir. Nevertheless, oil-cracked gas escaped during the evolution of the paleo-gas reservoir. Formation of the current dry gas reservoir can be attributed to the continuous mixing of late-stage kerogen pyrolysis gas.

The Production Splitting Method of Offshore Multilayer Combined Water Flooding Gas Wells with Gas Dissolving.

Offshore gas reservoirs are characterized by thin interlayers, high production, few wells, etc., and are often exploited by multilayer combined mining, whereas the production dynamics of multilayer gas reservoirs are very different from those of single-layer gas reservoirs. Therefore, clarifying the gas production contribution of each layer in multilayer combined gas reservoirs is an important prerequisite for analyzing the potential of gas reservoirs and realizing efficient development. In this paper, unlike the past method of evaluating the gas production contribution of each layer by using the KH attribute of the reservoir, we combined the modified B-L equation considering CO2 dissolution and the multilayer multizone seepage equation to establish a dynamic split model of the production dynamics of multilayer water-driven gas reservoirs, verified the reliability of the model through the numerical model and the results of the production well logging, quantitatively analyzed the degree of influence of each parameter on the contribution of the layered gas production, and designed the orthogonal experiments. The main controlling factors of the gas production contribution of each layer were determined. The results of the study show that (1) the main controlling factors for the gas production contribution of each layer in the early stage of WDG are, in order, permeability, thickness, outer boundary distance, porosity, CO2 content, and total gas production rate; however, the main controlling factors for the gas production contribution of each layer in the late stage of WDG are, in order, thickness, permeability, outer boundary distance, porosity, CO2 content, and total gas production rate; and the combined view shows that the permeability and thickness have the greatest influence. (2) In multilayer production, the conditions of high permeability, close gas-water boundary, poor gas content, and low CO2 content will reduce the gas production contribution of the layer with the increase of production time. (3) Compared with the results of production logging and numerical simulation, the split model can better predict the gas production of each layer, and the prediction error is no more than 10%. (4) By comparing with the numerical simulation results, the model can realize the prediction of the time of seeing water in the layer with stronger water body capability. (5) The model takes into account the effect of the CO2 content, better reflects the actual gas composition of each layer, and can improve the production prediction accuracy by up to 4%. Considering the high cost of production logging in offshore oil and gas fields, the inability of the KH method to reflect the dynamic changes of gas production in each layer, the poor application of stratified sampling to dry gas reservoirs, and other limitations, the model in this paper can be utilized to simulate the multilayer water-driven gas drive process when the energy of the water body is strong by using the geological parameters of the reservoir and the fluid parameters, and the simulation results of this model provide directions for offshore multilayer water-driven gas reservoirs to improve the recovery rate, and for plugging and regulating the water and exploiting the potential of gas wells that have seen water.

A screening tool for carbon dioxide injection in gas reservoirs based on the material balance approach

Significant efforts are made to reduce the carbon dioxide concentrations in the atmosphere as part of a global scheme that aims to mitigate climate change. Carbon geological storage involves the storage of CO2 permanently in a subsurface reservoir, commonly a brine saturated aquifer, or a depleted reservoir. Carbon dioxide is also injected for enhanced oil or gas recovery (EOR/EGR). This work applies a material balance to CO2 for injection and storage in a single-phase dry and/or condensate gas reservoirs. The developed framework based on piston-like displacement can be either used for pressurising depleted gas reservoirs with CO2 or for EGR. Sensitivity studies of carbon dioxide injection in pressure depleted gas reservoirs and piston-like injection under water drive are presented for various production rates and initial reservoir pressures. Monte Carlo simulations are conducted for combinations of porosity and permeability of different formations such as sandstone, shale, and unconsolidated sand. The results show that CO2 piston-like injection in EGR is more efficient compared to first depleting the reservoir and then injecting CO2 as it controls the water influx. The recovery factors in CO2 EGR are almost insensitive to initial pressures and production rates for both single-phase and condensate gas. Higher permeability formations are much more effective, however, a formation with very high permeability may lead to stability problems.

Design and Performance Analysis of Dry Gas Fishbone Wells for Lower Carbon Footprint

Multilateral well drilling technology has recently assisted the drilling industry in improving borehole contact area and reducing operation time, while maintaining a competitive cost. The most advanced multilateral well drilling method is Fishbone drilling (FbD). This method has been utilized in several hydrocarbon fields worldwide, resulting in high recovery enhancement and reduced carbon emissions from drilling. FbD involves drilling several branches from laterals and can be considered as an alternative method to hydraulic fracturing to increase the stimulated reservoir volume. However, the expected productivity of applying a Fishbone well from one field to another can vary due to various challenges such as Fishbone well design, reservoir lithology, and accessibility. Another challenge is the lack of existing analytical models and the effect of each Fishbone parameter on the cumulative production, as well as the interaction between them. In this paper, analytical and empirical productivity models were modified for FbD in a dry gas reservoir. The modified analytical model showed a higher accuracy with respect to the existing model. It was also compared with the modified empirical model, which proved its higher accuracy. Finally, machine learning algorithms were developed to predict FbD productivity, which showed close results with both analytical and empirical models.

Natural gas characteristics and gas-source comparisons of the Lower Triassic Feixianguan Formation, Eastern Sichuan Basin, China

There is great controversy regarding the origin and source of natural gas in the Lower Triassic Feixianguan Formation in the Eastern Sichuan Basin. This seriously restricts the study of natural gas dynamics in the Feixianguan Formation and thus hampers natural gas exploration in the region, so further study is urgently required. Using experimental tests of natural gas composition, stable isotopes, and noble gas isotopes with gas chromatography (GC) and mass spectrometry (MS) studies of source rock and reservoir asphalt saturated hydrocarbons, the natural gas geochemical characteristics, the genetic identification and a gas-source comparison of the Feixianguan Formation were studied. Then, constrained by the thermal history, the histories of gas generation and expulsion were restored by basin simulation technology. Finally, a gas accumulation model was established for the Feixianguan Formation. The results showed that (1) the H2S-rich and H2S-poor gas reservoirs of the Feixianguan Formation are distributed on the east and west sides of the Kaijiang-Liangping trough in the Eastern Sichuan Basin, respectively. The carbon and hydrogen isotope compositions of the natural gas in the gas reservoirs are generally heavy and have typical characteristics of high-maturity dry gas reservoirs. (2) The natural gas of the Feixianguan Formation is organic thermogenic gas, which is mainly oil-type gas generated by the secondary cracking of crude oil. The gas-generating parent material is mainly type II kerogen. (3) The natural gas of the Feixianguan Formation in the Eastern Sichuan Basin was mainly generated by argillaceous source rocks of the Upper Permian Longtan Formation. (4) Natural gas accumulation occurred as follows: the paleo-structure heights were filled with crude oil in the Early Jurassic, and paleo-oil reservoirs were formed in the Feixianguan Formation; during the Middle-Late Jurassic, the paleo-oil reservoirs were cracked when the reservoir temperatures rose above 160 °C, and paleo-gas reservoirs were formed. Since the end of the Late Jurassic, the paleo-gas reservoirs have been adjusted and reformed to form the present-day natural gas reservoirs. These results provide a basis for studying natural gas accumulation dynamics of the Feixianguan Formation in the Eastern Sichuan Basin.

Natural gas characteristics and gas-source comparisons of the lower triassic Jialingjiang formation, Eastern Sichuan basin

There are abundant natural gas resources in the Lower Triassic Jialingjiang Formation in the Eastern Sichuan Basin (ESB). Important progress has been made in the study of reservoir characteristics and sedimentary facies of marine reef-beach facies in the Jialingjiang Formation. However, there are still differences in the understanding of its natural gas origin and gas source rocks, which greatly restricts the understanding of the reservoir forming process and formation mechanism of the gas reservoirs, so further study is urgently needed. Based on experimental tests of natural gas composition, stable isotopes, and noble gas isotopes with gas chromatography (GC) and mass spectrometry (MS) studies of source rocks and reservoir asphalt saturated hydrocarbons, the natural gas geochemical characteristics, genetic identification and gas-source comparison of the Jialingjiang Formation were studied. The results showed that (1) the natural gas of the Jialingjiang Formation was mainly hydrocarbon gas, and methane was dominant. The average drying coefficient was 99.266%, which is typical of high maturity dry gas reservoirs. The δ13C1, δ13C2 and δ13C3 values ranged from −36.00‰ to 24.80‰, −37.80‰–27.60‰ and −39.20‰–23.20‰, respectively. The δD1, δD2 and δD3 values were between −164.00‰ and −124.00‰, −162.00‰ and −111.00‰ and −173.21‰ and −71.00‰, respectively. (2) The natural gas has a crustal source origin, which was mainly oil-type thermogenic gas generated by secondary cracking of crude oil. The gas-generating parent material is mainly partial sapropelic kerogen and was in the sedimentary environment of salt to brackish water. (3) The natural gas was mainly generated by argillaceous source rocks of the Upper Permian Longtan Formation. (4) The natural gas accumulation in the Jialingjiang Formation has experienced three stages, including paleo-oil reservoir, paleo-gas reservoir and current gas reservoir. The results provide a basis for the exploration decision-making of natural gas in the Jialingjiang Formation in the ESB.

Numerical modeling of the conservative exploitation of conventional gas reservoirs

This paper reports the results of a research project aimed at designing heuristically oriented exploitation plans based on simple parameters of static modeling rather than complex ones of dynamic modeling for conventional gas reservoirs. The combined use of heuristic rules relying on the Maximum Efficient Rate (MER) criteria and the Maximum Depletion Rate Model (MDRM, Global Energy Research, Uppsala University) was investigated to model a systemic approach for these reservoirs. Integration of these principles and their comparative evaluation led to findings about their mutual relationships, notably the MER to be regarded as a particular case of the MDRM. The rules rely on a combined use of the exponential version of the Fundamental Equation of Mineral Production (EFE) with the exponential decline (ED) curve analysis. A bridge between the physics of flow in porous media and the Law of Conservation of Matter was found by demonstrating the conditions of equivalence between the ED and the EFE. Production data built upon reservoir characterization of the gas reservoirs supported the comparative analysis. A systematic approach enabled the replication of the material balance-based production profiles by applying a MER-based P/R of 0.08 and a MDRM based of 6 for the plateaus of the wet and dry gas reservoirs, respectively. Production models rested on broadly accurate rules relying on mutual relationships between contemporary volumes of reserves and output yields. The production models reviewed appear useful for a discrete application of the Ockham razor criterion to make relatively effortless modeling of conventional gas reservoir production.

PENENTUAN SENSITIVITAS YANG BERPENGARUH TERHADAP PRODUKSI RESERVOIR MULTILAYER SECARA COMMINGLE

Multilayer reservoirs are not uncommon in oil and gas fields. In optimizing production in multilayer reservoirs, commingle production is an option. When producing a multilayer reservoir, it is necessary to select a reservoir with suitable characteristics. More and more research in producing multilayer reservoirs by commingle is being carried out. Forchheimer conducted research on the effect of turbulence that occurs, especially in gas wells. This turbulence effect causes pressure disturbances from the reservoir into the well. When the reservoir is produced in commingle, how does gas turbulence affect the production. This research is devoted to the production of commingle wells that penetrate three layers of a multilayer dry gas reservoir by considering the turbulence that occurs. Then it is determined the possible sensitivity that has an effect using literature studies in the multilayer field and gas well field based on the cumulative changes in production that occur in each sensitivity.

Multistage optimization of a petroleum production system with material balance model

In this paper, we propose a mathematical formulation for the optimal management over time of an oil production network as a multistage optimization problem. The proposed model differs from common practice where the reservoir of the oil production network is approximated by decline curves or by black-box simulators. We model the reservoir as a controlled (non-linear) dynamical system by using material balance equations, under the standard assumptions that the fluids follow a black-oil model and that the reservoir has a tank-like behavior. The state of the dynamical system has five dimensions: the total volume of respectively oil, gas, and water in the reservoir; the total pore volume; and the reservoir pressure. We use a dynamic programming algorithm to numerically solve the multistage optimization problem on two specific instances of the general optimization problem where the state dimension can be reduced from dimension five to dimension one or two. More precisely, the first numerical application consists in optimizing the production of a dry gas reservoir which is subdivided in two tanks and which leads to a two-dimensional state (one dimension per tank), whereas the second numerical application tackles an oil reservoir with water injection which leads to a two-dimensional state. The two applications illustrate that our approach handles interconnected tanks (in the dry gas case) and that our approach allows optimization beyond first recovery of oil (in the oil with water injection case). We also provide numerical and theoretical comparisons with decline curves in the dry gas application.

Hydrocarbon generation potential and model of the deep lacustrine source rocks in the Dongying Depression, Bohai Bay Basin

The deep mudstone in the Palaeogene of the Dongying Depression has been relatively deeply buried and is a useful example of a deep source rock. We use TOC, rock pyrolysis, gas chromatography-mass spectrometry (GC-MS) and vitrinite reflectance (VRo) to evaluate organic matter types, the sedimentary environment, thermal maturity, and hydrocarbon generation potential. Thermal pyrolysis experiments and PVT phase simulation were also used to study the evolution of hydrocarbon generation in these deep source rocks. Two sets of dark mudstone are formed in a reductive salt lake environment, and the organic matter types are mainly I and II. TOC data and pyrolysis experiments show considerable hydrocarbon generation potential. The mudstone samples present low pristane/phytane, high gammacerane/C30hopane, and gammacerane/C31hopane (22R) values, reflecting a strong reduction environment with development of gypsum and salt rocks for the source rocks. A significant effect of maturity on the carbon isotope was indicated, and the carbon isotope values of aromatics are unusually heavier than those of saturated hydrocarbons and resins. The maturity parameters VRo and pyrolysis peak temperature (Tmax) are somewhat reduced owing to the influence of multiple units of gypsum-salt rocks. The VRo values of the two sets of mudstone are in the range 0.74%–1.0% and 0.75%–1.95%, respectively, indicating that these mudstones are mainly moderately mature and high to over mature. The results of thermal simulation experiments of a hypersaline mudstone show that the increase in organic matter maturity is uneven at different stages of thermal evolution, and the increasing rate is relatively fast in the oil generation window. The wide maturity range of the source rocks contributes to the formation of various types of reservoirs, including normal oil, volatile light oil, condensate gas and single dry gas in the deep part of depression; all reservoir types are distributed regularly with burial depth. A detailed hydrocarbon generation model for salt lake facies is proposed to show the evolutionary stages of biogas, bitumen, low mature oil, normal oil, wet gas, volatile oil, condensate gas, and dry gas with increasing thermal maturity. Reservoirs of volatile oil, condensate gas, and dry gas develop at depths of >4000 m. At depths of >4500 m, condensate gas and single dry gas reservoirs mainly exist; these are the main targets for deep petroleum exploration in the area.

Application of Machine Learning to Accelerate Gas Condensate Reservoir Simulation

According to the roadmap toward clean energy, natural gas has been pronounced as the perfect transition fuel. Unlike usual dry gas reservoirs, gas condensates yield liquid which remains trapped in reservoir pores due to high capillarity, leading to the loss of an economically valuable product. To compensate, the gas produced on the surface is stripped from its heavy components and reinjected back to the reservoir as dry gas thus causing revaporization of the trapped condensate. To optimize this gas recycling process compositional reservoir simulation is utilized, which, however, takes very long to complete due to the complexity of the governing differential equations implicated. The calculations determining the prevailing k-values at every grid block and at each time step account for a great part of total CPU time. In this work machine learning (ML) is employed to accelerate thermodynamic calculations by providing the prevailing k-values in a tiny fraction of the time required by conventional methods. Regression tools such as artificial neural networks (ANNs) are trained against k-values that have been obtained beforehand by running sample simulations on small domains. Subsequently, the trained regression tools are embedded in the simulators acting thus as proxy models. The prediction error achieved is shown to be negligible for the needs of a real-world gas condensate reservoir simulation. The CPU time gain is at least one order of magnitude, thus rendering the proposed approach as yet another successful step toward the implementation of ML in the clean energy field.

Underground hydrogen storage in a partially depleted gas condensate reservoir: Influence of cushion gas

Hydrogen gas as a clean and renewable kind of energy can be considered to supply electricity demand during peak usage times. Actually, excess electricity cannot be stored in great quantities, but it can be converted to hydrogen, which can be stored and converted to electricity as a peak shaving. However, due to the very low hydrogen energy density in terms of volume, a huge capacity is needed for its storage. Therefore, underground hydrogen storage (UHS) can be evaluated as a solution. This study investigated the effect of cushion gas on underground hydrogen storage in a partially depleted gas condensate reservoir in a real case which is located in the Middle east. To the best of our knowledge, it is the first time the feasibility of underground hydrogen storage in a gas condensate reservoir has been investigated. The effect of some parameters such as cushion gas type, namely; methane, nitrogen, carbon dioxide, condensate existence, the implementation time of storage, hydrogen injection initialization stage, and hydrogen injection/production rate was investigated on hydrogen heating value and recovery during the underground hydrogen storage operation. The results of replacing alternative gases as part of cushion gas showed that the highest amount of hydrogen recovery and purity could be obtained by injecting the nitrogen. While carbon dioxide was the most effective alternative gas to improve condensate production but in terms of hydrogen recovery and purity was not. Also, implementing hydrogen storage in the gas condensate reservoir leads to higher hydrogen recovery than dry gas reservoirs due to the trapping of alternative gases in the condensate phase. However, most of the injected carbon dioxide was produced during hydrogen production, which is unfavorable. This study shows that 60% depletion of the gas condensate reservoir is the best condition to start underground hydrogen storage. Further, applying a hydrogen injection initialization stage indicated that the hydrogen recovery and heating value could be increased. However, it requires a detailed economic evaluation to consider the cost/benefit of initialized hydrogen loss and recovery.

Transformation of a Large Ancient Oil Reservoir to a Dry Gas Reservoir: A Case Study of the Kela-2 Gas Field in the Kuqa Foreland Basin, NW China

Various lines of evidence, including the occurrence of bitumen and fluid inclusions, show that oil charge once took place in the Kela-2 gas field, Kuqa foreland basin, Northwest China. However, the scale of the ancient oil reservoir remains unclear, as does the process by which the reservoir evolved into the present dry gas field. Here, using data from analyses of fluid inclusions, petrography, laser Raman spectroscopy, and quantitative fluorescence, the hydrocarbon accumulation history of the Kela-2 gas field is reconstructed. The results show that the gas field underwent three periods of hydrocarbon charging and one period of adjustment. The first oil charging occurred at about 12 Ma, as recorded by the first group of oil inclusions containing 0–8 vol.% gas with yellowish-brown fluorescence. The second charging involved mature oil charging at about 4 Ma, recorded by the second group of oil inclusions containing 15–25 vol.% gas with blue-white fluorescence. According to quantitative grain fluorescence (QGF) and rock pyrolysis analysis, an ancient oil reservoir existed with an oil-column height of about 350 m, and the paleo oil–water contact was lower than the present gas–water contact. Under intense thrusting from 3 Ma, the ancient oil reservoir was destroyed, with oil escaping through the Kashangtuokai thrust fault, which broke the salt layer, as this layer at that time lay in the brittle deformation domain. The inferred destruction of the ancient oil reservoir is supported by the numerous oil and gas shows at the surface and in shallow layers near the Kashangtuokai fault, as well as the anomalous development of authigenic kaolinite in the gas reservoir, which was enhanced by an open or semiopen system caused by the fault breaking through the salt layer. Subsequently, with increasing burial depth to more than 3000 m, the fault that had cut through the salt layer annealed because the salt layer then lay within the ductile deformation domain. The higher overpressure that occurred during the third gas charging at about 2 Ma reflected the annealing of the fault in the salt layer, favoring late gas accumulation and preservation. The evolution of the Kela-2 gas field provides an important case study for understanding the role of the salt layer crossing the brittle–plastic transition and the dynamic evolution of the salt caprock in salt-containing foreland basins.

The Application of P/Z Methods in Evaluation of Initial Gas in Place of X Reservoir

Reservoir X is located in West Tanjung Jabung Regency, Jambi, Indonesia, with initial pressure is 2,028 psia, and a temperature is 226°F. The reservoir has been produced from February 2018 to the present (February 2021), with cumulative gas production of 5.17 Bscf. Based on the Plan Of Development (POD) study in 2016, the initial gas in place was determined volumetrically to be 49,92 Bscf. To compare the initial gas in place, it is deemed necessary to recalculate the initial gas in place by utilizing another method. The calculation of Initial Gas In Place (IGIP) is conducted by using the P/Z method. In this method, the Initial Gas in Place is obtained 49.01 Bscf. Based on analyzing the phase diagrams and the prevailing reservoir conditions, reservoir X indicated a dry gas reservoir. Such reservoir drive mechanism is a depletion drive, determined from the P/Z vs Gp plot, generating a straight line. Based on the assumed abandonment pressure value of 300 psia, the estimated ultimate recovery value is 41.93 Bscf, with the recovery factor value of 87.65% and the remaining reserves of 36.76 Bscf.

Phase Behavior and Compressibility Factors of Ultra-Deep Condensate and Dry Gas Reservoir with Pressure Up to 146 Mpa: Experimental and Calculation

Phase Behavior and Compressibility Factors of Ultra-Deep Condensate and Dry Gas Reservoir with Pressure Up to 146 Mpa: Experimental and Calculation