CO2 storage performance influenced by CO2-brine-carbonate reactions: A case from China's first CCUS project in carbonate gas reservoir

An innovative concept on deep carbonate reservoir stimulation: Three-dimensional acid fracturing technology

Carbonate gas reservoirs in China are rich in reserves. In the development process, there are many reserves with low permeability, low efficiency and low recovery degree. It is difficult to stabilize gas well production and prolong its life cycle. Under the condition of original water saturation (Sw) of 0%, 20%, 40%, 55% and 65%, respectively, the physical simulation experiment of gas reservoirs depletion development was carried out by using long core multi-point embedded pressure measuring system. The long cores with average gas permeability of 2.300 mD, 0.485 mD and 0.046 mD (assembled from 10 carbonate cores) were used to carry out this experiment. During the experiment, the pressure dynamics at different positions inside the long core and the gas production dynamics at the outlet were recorded in real time to reveal the production performance and reserves utilization law of carbonate gas reservoirs. The results show that the stable production period of tight reservoir in carbonate gas reservoirs is short, and the low production period is relatively long. The stable production time and recovery rate of gas reservoir increase with the increase of reservoir permeability and decrease with the increase of water saturation. The production of tight carbonate gas reservoirs with permeability less than 0.1 mD is greatly affected by pore water, and the reservoir pressure distribution shows a steep pressure drop funnel, and the reserves far from well are rarely used. Therefore, the reserves far from well should be utilized by closing well to restore formation pressure balance, densifying well pattern or transforming reservoir. The variation range of water saturation in the development of carbonate gas reservoirs is influenced by reservoir permeability and water saturation, and closely related to formation pressure gradient in production process. It decreases with the increase of reservoir permeability and increases with the increase of original water saturation. The research results provide a theoretical basis for understanding the relationship between physical properties of carbonate gas reservoirs and production performance, reserves utilization law, and realizing balanced utilization, efficient development and long-term stable production of carbonate gas reservoirs.

Existing fractured gas reservoir development techniques are mainly based on dual medium numerical-simulation models, which can, to a certain extent, effectively simulate natural fractures with high fracture density; however, these models have some limitations, particularly in terms of simulating the fracture morphology and distribution. Considering carbonate gas reservoirs with complex fractures, in this paper, we establish a numerical-simulation model of embedded discrete-fracture seepage in horizontal wells of carbonate gas reservoirs, in order to compare and study the development effect of carbonate gas reservoirs under different horizontal well fracture parameters. The fracture distribution and structure in carbonate gas reservoirs is obtained using an ant-tracking approach based on 3D seismic bodies, and a numerical-simulation model based on the embedded discrete-fractures model is solved using the open-source program MRST. We considered the following parameters: half fracture length, fracture permeability, and horizontal segment length. By changing the fracture parameters of horizontal wells and comparing the gas-production trends, technical optimization in gas reservoir development can be realized. The results show that the embedded discrete-fracture model can effectively solve the difficult problem of characterizing fluid seepage in fractures of different scale in carbonate gas reservoirs. Although gas production increases with increasing fracture length, fracture conductivity, horizontal section length, and natural fracture conductivity, the contributions of these parameters to gas well production capacity are greatly influenced by the natural fractures.

Injecting CO2 into depleted gas reservoirs facilitates CO2 storage and enhances natural gas recovery rate (CSEGR), offering significant environmental benefits. Carbonate gas reservoirs are widely distributed globally and are characterized by large reservoir thicknesses, abundant reserves, poor reservoir physical properties, and high heterogeneity. In the depletion state, considerable amounts of natural gas remain in the matrix pores, and numerous natural cavities provide ample space for CO2 storage. Consequently, carbonate gas reservoirs hold great potential for implementing the CSEGR program. To accurately model the flow behavior of CO2 in highly heterogeneous carbonate gas reservoirs and assess the feasibility of implementation the CSEGR program, a three-dimensional numerical model was developed at the reservoir scale using geological data from the fourth section of the Dengying Formation (Deng-4) in the Anyue Gas Field. The study investigates the CH4 production and CO2 storage characteristics of four typical reservoir bodies, tracks the spatial migration of CO2, and explores the effects of CO2 injection rate and interlayer permeability on the CSEGR process. Numerical results show that the cavity-type reservoir is ideal for the CSEGR scheme, with an enhanced gas recovery (EGR) rate exceeding 20%, whereas the fracture-cavity reservoir is unsuitable due to premature CO2 breakthrough caused by natural fractures. The cavity-type reservoir serves as the primary site for CO2 injection and storage, with some CO2 migrating into the pore-type reservoir through interlayer crossflow. For both pore-type and cavity-type reservoirs, the migration distance of the CO2 front is proportional to the square root of the injection time. Lower CO2 injection rates and smaller interlayer permeabilities delay CO2 breakthrough, leading to higher EGR rates. However, reduced injection rates also lower CH4 production rates and extend CO2 injection duration.

To improve the carbonate gas reservoir development and production, highly deviated wells (HDW) are widely used in the field. Production decline analysis of HDW is crucial for long‐term gas reservoir development. However, it is a new challenge to incorporate the complex pore structure of naturally fractured‐vuggy carbonate gas reservoirs and evaluate the production performance of HDW. This paper presents a semianalytical model to analyze the pressure and production behavior of HDW in naturally fractured‐vuggy carbonate gas reservoirs, which consist of fractures, vugs, and matrix. The primary flow occurs only through the fracture and the outer boundary is closed. Introducing pseudopressure and pseudotime, the Laplace transformation, Fourier transformation, and its inverse and Stehfest numerical inversion were employed to establish a point source and line source solutions. Furthermore, the validity of the proposed model was verified by comparing a field data from the Arum River Basin in Turkmenistan. Finally, the effects of major parameters on the production decline curves were analyzed by using the proposed model and it was found that they had influences at different stages of gas production history and the sensitivity intensity of each parameter was different. With its high efficiency and simplicity, this semianalytical model will serve as a useful tool to evaluate the well production behavior for the naturally fractured‐vuggy carbonate gas reservoirs.

Water invasion in carbonate gas reservoirs often results in excessive water production, which limits the economic life of gas wells. This is influenced by reservoir properties and production parameters, such as aquifer, fracture, permeability and production rate. In this study, seven full diameter core samples with dissolved pores and fractures were designed and an experimental system of water invasion in gas reservoirs with edge and bottom aquifers was established to simulate the process of water invasion. Then the effects of the related reservoir properties and production parameters were investigated. The results show that the edge and bottom aquifers supply the energy for gas reservoirs with dissolved pores, which delays the decline of bottom-hole pressure. The high water aquifer defers the decline of water invasion in the early stage while the big gas production rate accelerates water influx in gas reservoirs. The existence of fractures increases the discharge area of gas reservoirs and the small water influx can result in a substantial decline in recovery factor. With the increase of permeability, gas production rate has less influence on recovery factor. These results can provide insights into a better understanding of water invasion and the effects of reservoir properties and production parameters so as to optimize the production in carbonate gas reservoirs.

The carbonate gas reservoir is one of the most important gas formation types; it comprises a large proportion of the global gas reserves and the annual gas production rate. However, a carbonate reservoir with weathering crust formation is rare, and it is of significant interest to illustrate the geological characteristics of this kind of formation and present the emerging problems and solution measures that have arisen during its exploitation. Therefore, in this research, a typical carbonate gas reservoir with weathering crust formation that is located in Ordos Basin, China, was comprehensively studied. In terms of formation geology, for this reservoir, the distribution area is broad and there are multiple gas-bearing layers with low abundance and strong heterogeneity, which have led to large differences in gas well production performance. Some areas in this reservoir are rich in water, which seriously affects gas well production. Regarding production dynamics, the main production areas in this gas reservoir have been stable on a scale of 5.5 billion cubic meters for more than a decade, and the peripheral area has been continually evaluated to improve production capacity. Nevertheless, after decades of exploration and development, the main areas of this reservoir are faced with several problems, including an unclear groove distribution, an unbalanced exploitation degree, low formation pressure, and increases in intermittent gas wells. To deal with these problems and maintain the stability of gas reservoir production, a series of technologies have been presented. In addition, several strategies have been proposed to solve issues that have emerged during the exploration and exploitation of peripheral reservoir areas, such as low-quality formation, unclear ancient land and complex formation-water distribution. These development measures employed in the carbonate gas reservoir with weathering crust formation in the Ordos Basin will surely provide some guidance for the efficient exploitation of similar reservoirs in other basins all over the world.

Water invasion is one of the most critical constraints on developing carbonate gas reservoirs, with a significant impact on gas well production. Therefore, it is crucial to establish a correct experimental model of water invasion to study the mobility and flow mechanism of aquifer water. In this study, three-full-diameter core was selected from Longwangmiao carbonate gas reservoirs. Then, the experimental evaluation methods and process of aquifer water mobility are established and conducted, and the effects of different parameters on the mobility of aquifer water are analyzed. The results show that the mobility of aquifer water is affected by the pore compressibility of formation rock and its elastic expansion. The proportion of movable water per unit drawdown pressure is 0.1%/MPa, which has little relationship with the production pressure difference. The formation drawdown pressure is the key factor controlling the mobility of the aquifer water. The greater the formation drawdown pressure, the higher the proportion of movable water in aquifer water, and the stronger the degree of water invasion. The cumulative movable water accounted for 6%-9% of the aquifer water in the development of carbonate gas reservoirs, and the final movable water production is related to the abandonment pressure. The aquifer water did not flow initially with drawdown pressure, but there was a critical drawdown pressure with the value of 10 MPa to 13 MPa, and it has a negative association with reservoir permeability. The finding of this study can help for better understanding the concept of water invasion in formation water-bearing reservoirs, and these results can fill the gaps in the mobility conditions and flow mechanisms of aquifer water and provide technical reference for optimizing water-invasion carbonate gas reservoir development.

Technological progress and development directions of PetroChina overseas oil and gas field production

Influence of reservoir heterogeneity on water invasion differentiation in carbonate gas reservoirs

Innovation and practice of key technologies for the efficient development of the supergiant Anyue Gas Field

Systematic enhance gas recovery (EGR) strategies are important technical means to improve the effect of low permeability carbonate gas reservoir and keep stable production in the middle- late development period. Lower paleozoic carbonate gas reservoirs of M gas field in Ordos Basin are one of typical low permeability reservoirs in China, which are located at the hub of the onshore natural gas network, with area nearly 10000 km2. As the crucial contributor of natural gas production, 1000 gas wells have been put into operation in total with accumulated gas production nearly 1000 × 108 m3 over the years. However, as the whole gas field enters the middle and late stage of development, the proved reserves have been basically used up, which are bringing the new problems such as serious unbalanced exploitation, large amount low pressure and low yield wells, rapid rate decline and water production. In the meanwhile, considering complex development of erosion trenches, strong horizontal and vertical heterogeneity and large scale of gas area, the application of existing EGR technologies are difficult. Therefore, due to characteristics and difficulties of geology and production performance in the middle and late development of these kind of gas reservoirs, systematic EGR technical strategies, as tapping potential reserves, reservoir classification, well pattern optimization and drainage recovery, which are mainly from improving the degree of reserve production and reducing the abandonment pressure two aspects, are putted forward. The innovated key technologies such as paleogeomorphology restoration based on dynamic monitoring, three-excellent reservoirs evaluation, well pattern optimization of multi-layer heterogeneous gas reservoirs, and optimization of working system of water producing gas wells based on early wellbore liquid loading identification have been formed. It is estimated that the reserves can be increased by 220.3 × 108 m3, gas production by 303.4 × 108 m3 and gas recovery by 6.8%. The research contents have guiding significance for the development and practice of similar gas reservoirs in China.KeywordsEnhance gas recoveryReservoirs classification and evaluationWell pattern optimizationLiquid loading identificationWorking systemLow permeability gas reservoir

Fluid flow in the dual-medium carbonate gas reservoir is characterized by stress sensitivity and non-Darcy flow effect. In order to accurately describe the unsteady flow of gas and water in the dual-medium gas reservoir, a two-phase flow model of gas and water is built. First, reservoir space and fluid flow characteristics of carbonate gas reservoirs are investigated, and the flow model that considers both the stress sensitivity and non-Darcy flow is built based on the fundamental flow theory, after fully investigating the reservoir space and fluid flow characteristics of carbonate gas reservoirs. Then, the perturbation theory is introduced, and the model is solved in the Laplace space, after which the obtained Laplace space analytical solution is converted into the real-space solution. Finally, the productivity evaluation model for the dual-medium gas reservoir with the gas-water two-phase flow is built, based on the flowing material balance method and Newton iteration. The presented productivity evaluation model is applied to analyze the effects of stress sensitivity and non-Darcy flow on the two-phase flow model of gas and water for the dual-medium gas reservoir and the reservoir productivity. The results indicate that a higher stress sensitivity coefficient is demonstrated to indicate higher stress sensitivity and accelerated production decline of the reservoir, while a lower non-Darcy flow effect coefficient represents a stronger non-Darcy effect and boosted drop of initial production of the reservoir. Hence, it is not reasonable to neglect the effects of stress sensitivity and non-Darcy flow during the evaluation of the productivity of a dual-medium carbonate gas reservoir. The model presented in this research provides important references for improving the recovery performance of dual-medium gas reservoirs.

Carbonate gas reservoirs are crucial in gas field development, with carbonate bottom-water gas reservoirs being a significant subset. However, the development of these reservoirs often faces challenges such as water invasion, leading to a low gas recovery rate. Enhancing gas recovery is a primary goal for researchers in this field. This study provides a systematic review of the mechanisms, identification, and dynamic prediction of water invasion in these gas reservoirs. The technical adaptability and application range of different enhanced recovery methods are summarized, and their application effects are evaluated. The results indicate that carbonate gas reservoirs have diverse types of storage and permeability spaces, with a wide distribution of pore size scales, leading to various types of enclosed gas caused by water invasion. The prediction accuracy of water invasion models for bottom-water gas reservoirs with fractures and vugs is relatively low. Therefore, numerical simulation research on the basis of fine reservoir characterization is the key technology. The control of bottom-water invasion and the rescue measures after the bottom-water invasion are the keys to improving gas recovery, which can be divided into four types: drainage gas recovery, water control production, active drainage, and injection medium. Gas production by drainage is the main technology for improving gas recovery, among which foam drainage is the most widespread. The optimization of development parameters in production by water control has a good effect in the early stages of development. The active drainage technology on the water invasion channel is the bottom-up technology for the effective development of strong water-flooded gas reservoirs. CO2 injection may have great potential to improve the recovery of bottom-water gas reservoirs, which is one of the important research directions under the background of “carbon peaking and carbon neutrality”. The research provides theoretical and technical reference significance for enhanced recovery of carbonate bottom-water gas reservoirs.

Unambiguously determining irreducible water saturation Swirr\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$$\\left({S}_{\\rm{wirr}}\\right)$$\\end{document} poses a formidable challenge, given the availability of multiple independent methods. Traditional approaches often depend on semi-experimental relationships derived from simplified assumptions. These methods, originally designed for oil sandstone reservoirs, result in varying Swirr\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$${S}_{{\ ext{wirr}}}$$\\end{document} values when employed in carbonate gas reservoirs. Nuclear magnetic resonance (NMR) is the most advanced technique for determining Swirr\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$${S}_{{\ ext{wirr}}}$$\\end{document}. While highly accurate, the NMR-based method necessitates the laboratory measurement of the transverse relaxation time T2\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$$\\left({T}_{2}\\right)$$\\end{document} cutoff. Laboratory-based T2\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$${T}_{2}$$\\end{document} cutoff determination is resource-intensive and time-consuming. This research aims to develop a robust model for determining Swirr\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$${S}_{{\ ext{wirr}}}$$\\end{document} in carbonate gas reservoirs by utilizing NMR well logging measurements and special core analysis (SCAL) tests. Various T2\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$${T}_{2}$$\\end{document} cutoff values were initially employed to compute bound water saturation Sbw\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$$\\left({S}_{{\ ext{bw}}}\\right)$$\\end{document} at different depths to achieve this. Subsequently, the data points T2,Sbw\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$$\\left({T}_{2}, {S}_{{\ ext{bw}}}\\right)$$\\end{document} were graphed on a scatter plot to unveil the relationship between Sbw\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$${S}_{{\ ext{bw}}}$$\\end{document} and T2\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$${T}_{2}$$\\end{document}. The scatter plot illustrates an exponential decrease in Sbw\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$${S}_{bw}$$\\end{document} with increasing T2\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$${T}_{2}$$\\end{document}, forming the basis for the Swirr\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$${S}_{{\ ext{wirr}}}$$\\end{document} model derived from this relationship. Finally, the parameters of the Swirr\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$${S}_{{\ ext{wirr}}}$$\\end{document} model were fine-tuned using SCAL tests. Notably, this Swirr\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$${S}_{{\ ext{wirr}}}$$\\end{document} model not only accurately yields Swirr\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$${S}_{{\ ext{wirr}}}$$\\end{document} at each depth but also offers a dependable determination of the optimal T2\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$${T}_{2}$$\\end{document} cutoff for the reservoir interval.