Abstract (
)
Download PDF (
)
HTML
(
)
Knowledge map
Save
To achieve the goals of carbon peaking and carbon neutrality under the backgrounds of poor resource endowments, weak theoretical basis and other factors, the development of the coalbed methane industry of China faces many bottlenecks and challenges. This paper systematically analyzes the coalbed methane resources, key technologies and progress, exploration effect and production performance in China and abroad. The main problems are summarized as low exploration degree, low technical adaptability, low return on investment and small development scale. This study suggests that the coalbed methane industry in China should follow the “two-step” (short-term and long-term) development strategy. The short-term action before 2030, can be divided into two stages: (1) From the present to 2025, to achieve new breakthroughs in theory and technology, and accomplish the target of annual production of 10 billion cubic meters; (2) From 2025 to 2030, to form the technologies suitable for most geological conditions, further expand the industry scale, and achieve an annual output of 30 billion cubic meters, improving the proportion of coalbed methane in the total natural gas production. The long-term action after 2030 is to gradually realize an annual production of 100 billion cubic meters. The strategic countermeasure to achieve the above goals is to adhere to “technology+management dual wheel drive”, realize the synchronous progress of technology and management, and promote the high-quality development of the coalbed methane industry. Technically, the efforts will focus on fine and effective development of coalbed methane in the medium to shallow layers of mature fields, effective development of coalbed methane in new fields, extensive and beneficial development of deep coalbed methane, three-dimensional comingled development of coalbed methane, applying new technologies such as coalbed methane displacement by carbon dioxide, microwave heating and stimulation technology, ultrasonic stimulation, high-temperature heat injection stimulation, rock breaking by high-energy laser. In terms of management, the efforts will focus on coordinative innovation of resource, technology, talent, policy and investment, with technological innovation as the core, to realize an all-round and integrated management and promote the development of coalbed methane industry at a high level.
Abstract (
)
Download PDF (
)
HTML
(
)
Knowledge map
Save
Based on the oil and gas exploration practice in the Songliao Basin, combined with the latest exploration and development data such as seismic, well logging and geochemistry, the basic geological conditions, oil and gas types and distribution characteristics, reservoir-forming dynamics, source-reservoir relationship and hydrocarbon accumulation model of the whole petroleum system in shallow and medium strata in the northern part of Songliao Basin are systematically studied. The shallow-medium strata in northern Songliao Basin have the conditions for the formation of whole petroleum system, with sufficient oil and gas sources, diverse reservoir types and well-developed transport system, forming a whole petroleum system centered on the source rocks of the Cretaceous Qingshankou Formation. Different types of oil and gas resources in the whole petroleum system are correlated with each other in terms of depositional system, lithologic association and physical property changes, and they, to a certain extent, have created the spatial framework with orderly symbiosis of shallow-medium conventional oil reservoirs, tight oil reservoirs and shale oil reservoirs in northern Songliao Basin. Vertically, the resources are endowed as conventional oil above source, shale oil/tight oil within source, and tight oil below source. Horizontally, conventional oil, tight oil, interlayer-type shale oil, and pure shale-type shale oil are developed in an orderly way, from the margin of the basin to the center of the depression. Three hydrocarbon accumulation models are recognized for the whole petroleum system in northern Songliao Basin, namely, buoyancy-driven charging of conventional oil above source, retention of shale oil within source, and pressure differential-driven charging of tight oil below source.
Abstract (
)
Download PDF (
)
HTML
(
)
Knowledge map
Save
Based on paleogeomorphology, drilling and seismic data, this paper systematically studies the structural and sedimentary evolution, source rock characteristics, reservoir characteristics and formation mechanism, hydrocarbon accumulation model and enrichment law in the Linhe Depression of the Hetao Basin, NW China. The Hetao Basin mainly experienced three stages of evolution, namely, weak extensional fault depression, strong extensional fault depression and strike-slip transformation, giving rise to four positive structural belts (Jilantai, Shabu, Nalinhu and Xinglong), which are favorable areas for oil and gas accumulation. The two main saline lacustrine source rocks, Lower Cretaceous Guyang Formation and Oligocene Linhe Formation, are characterized by high sulfur content, rich algae, early maturity, early expulsion, and wide oil generation window. The large structural transition belt in the intermountain area around the Hetao Basin controls the formation of large-scale braided river delta deposits, which are characterized by high quartz content (50%-76%), long-term shallow burial and weak compaction, low cement content, and good reservoir properties in delta front sandbody. The burial depth of the effective Paleogene reservoirs is predicted to reach 8000 m. Three hydrocarbon accumulation models, nose-uplift near sag, buried hill surrounding sag, fault nose near source rock, are constructed. The law of hydrocarbon accumulation in the Linhe Depression is finally clarified as follows: near-source around the depression is the foundation, high-quality thick reservoir is the premise, good tectonic setting and trap conditions are the key.
Abstract (
)
Download PDF (
)
HTML
(
)
Knowledge map
Save
Based on the combination of core observation, experimental analysis and testingand geological analysis, the main controlling factors of shale oil enrichment in the Lower Permian Fengcheng Formation in the Mahu Sag of the Junggar Basin are clarified, and a shale oil enrichment model is established. The results show that the enrichment of shale oil in the Fengcheng Formation in the Mahu Sag is controlled by the organic abundance, organic type, reservoir capacity and the amount of migration hydrocarbon in shale. The abundance of organic matter provides the material basis for shale oil enrichment, and the shales containing types I and II organic matters have good oil content. The reservoir capacity controls shale oil enrichment. Macropores are the main space for shale oil enrichment in the Fengcheng Formation, and pore size and fracture scale directly control the degree of shale oil enrichment. The migration of hydrocarbons in shale affects shale oil enrichment. The shale that has expelled hydrocarbons has poor oil content, while the shale that has received hydrocarbons migrated from other strata has good oil content. Lithofacies reflect the hydrocarbon generation and storage capacity comprehensively. The laminated felsic shale, laminated lime-dolomitic shale and thick-layered felsic shale have good oil content, and they are favorable lithofacies for shale oil enrichment. Under the control of these factors, relative migration of hydrocarbons occurred within the Fengcheng shale, which leads to the the difference in the enrichment process of shale oil. Accordingly, the enrichment mode of shale oil in Fengcheng Formation is established as "in-situ enrichment" and "migration enrichment". By superimposing favorable lithofacies and main controlling factors of enrichment, the sweet spot of shale oil in the Fengcheng Formation can be selected which has great significance for the exploration and development of shale oil.
Abstract (
)
Download PDF (
)
HTML
(
)
Knowledge map
Save
The conventional lithofacies and facies model of subaerial and marine pyroclastic rocks cannot reflect the characteristics of subaqueous volcanic edifice in lacustrine basins. In order to solve this problem, the lithofacies of subaqueous eruptive pyroclastic rocks is discussed and the facies model is established by taking the tuff cone of Cretaceous Huoshiling Formation in the Chaganhua area of the Changling fault depression, Songliao Basin as the research object. The results indicate that the subaqueous eruptive pyroclastic rocks in the Songliao Basin can be divided into two facies and four subfacies. The two facies are the subaqueous explosive facies and the volcanic sedimentary facies that is formed during the eruption interval. The subaqueous explosive facies can be further divided into three subfacies: gas-supported hot pyroclastic flow subfacies, water-laid density current subfacies and subaqueous fallout subfacies. The volcanic sedimentary facies consists of pyroclastic sedimentary rocks containing terrigenous clast subfacies. A typical facies model of the tuff cone that is formed by subaqueous eruptions in the Songliao Basin was established. The tuff cone is generally composed of multiple subaqueous eruption depositional units and can be divided into two facies associations: near-source facies association and far-source facies association. The complete vertical succession of one depositional unit of the near-source facies association is composed of pyroclastic sedimentary rocks containing terrigenous clast subfacies, gas-supported hot pyroclastic flow subfacies, water-laid density current subfacies and subaqueous fallout subfacies from bottom to top. The depositional unit of the far-source facies association is dominated by the subaqueous fallout subfacies and contains several thin interlayered deposits of the water-laid density current subfacies. The gas-supported hot pyroclastic flow subfacies and the pyroclastic sedimentary rocks containing terrigenous clast subfacies are favorable subaqueous eruptive facies for reservoirs in continental lacustrine basins.
Abstract (
)
Download PDF (
)
HTML
(
)
Knowledge map
Save
Based on the geological and geochemical analysis of potential source rocks in different formations and the classification of crude oil types, combined with the hydrocarbon generation thermal simulation experiments, the source, genesis, and distribution of different types of oils in the Mahu large oil province of the Junggar Basin are investigated. Four sets of potential source rocks are developed in the Mahu Sag. Specifically, the source rocks of the Permian Fengcheng Formation have the highest hydrocarbon generation potential and contain mainly Types II and I organic matters, with a high oil generation capacity. In contrast, the source rocks in other formations exhibit lower hydrocarbon generation potential and contain mainly Type III organic matter, with dominant gas generation. Oils in the Mahu Sag can be classified as three types: A, B and C, which display ascending, mountainous and descending C20-C21-C23 tricyclic terpenes abundance patterns in sequence, and gradually increasing relative content of tricyclic terpenes and sterane isomerization parameters, indicating an increasing oil maturity. Different types of oils are distributed spatially in an obviously orderly manner: Type A oil is close to the edge of the sag, Type C oil is concentrated in the center of the sag, and Type B oil lies in the slope area between Type A and Type C. The results of oil-source correlation and thermal simulation experiments show that the three types of oils come from the source rocks of the Fengcheng Formation at different thermal evolution stages. This new understanding of the differential genesis of oils in the Mahu Sag reasonably explains the source, distribution, and genetic mechanism of the three types of oils. The study results are of important guidance for the comprehensive and three-dimensional oil exploration, the identification of oil distribution in the total petroleum system, and the prediction of favorable exploration areas in the Mahu Sag.
Abstract (
)
Download PDF (
)
HTML
(
)
Knowledge map
Save
Based on the data of field outcrops, drilling cores, casting thin sections, well logging interpretation, oil/gas shows during drilling, and oil/gas testing results, and combined with modern salt-lake sediments in the Qinghai Lake, the Neogene saline lake beach-bars in southwestern Qaidam Basin are studied from the perspective of sedimentary characteristics, development patterns, sand control factors, and hydrocarbon accumulation characteristics. Beach-bar sand bodies are widely developed in the Neogene saline lake basin, and they are lithologically fine sandstone and siltstone, with wavy bedding, low-angle cross bedding, and lenticular-vein bedding. In view of spatial-temporal distribution, the beach-bar sand bodies are stacked in multiple stages vertically, migratory laterally, and extensive and continuous in NW-SE trending pattern in the plane. The stacking area of the Neogene beach-bar sandstone is predicted to be 3 000 km2. The water salinity affects the sedimentation rate and offshore distance of beach-bar sandstone, and the debris input from the source area affects the scale and enrichment of beach-bar sandstone. The ancient landform controls the morphology and stacking style of beach-bar sandstone, and the northwest monsoon driving effect controls the long-axis extension direction of beach-bar sandstone. The beach-bars have a reservoir-forming feature of “one reservoir in one sand body”, with thick beach-bar sand bodies controlling the effective reservoir distribution and oil-source faults controlling the oil/gas migration and accumulation direction. Three favorable exploration target zones in Zhahaquan, Yingdong-eastern Wunan and Huatugou areas are proposed based on the analysis of reservoir-forming elements.
Abstract (
)
Download PDF (
)
HTML
(
)
Knowledge map
Save
This paper depicts the distribution of the Wushenqi paleo-uplift in the Ordos Basin by using the latest drilling and seismic data, and analyzes the tectonic evolution of the paleo-uplift with the support of Bischke curve and balanced section. The compressional Wushenqi paleo-uplift which developed in the Early Caledonian orogeny (Huaiyuan orogeny) is approximately a ellipse extending in S-N direction. Its long axis is about 194 km and short axis is about 55-94 km in nearly W-E direction. The denudation thickness and area of the Cambrian in the core are 170-196 m and 11 298 km2, respectively. It was mainly formed during the Huaiyuan orogeny according to the chronostratigraphic framework. It was in the embryonic stage in the Middle-Late Cambrian, denuded after developed obviously at the end of Late Cambrian. The paleo-uplift of the 3rd member of the Ordovician Majiagou Formation was reactivated and reduced in area. In the sedimentary period of the Ma 4 Member-pre-Carboniferous, the paleo-uplift experienced non-uniform uplift and denudation. It entered the stable period of burial and preservation in the Carboniferous and later period. The Wushenqi paleo-uplift was formed on the weak area of the basement and tectonic belts, into an compressional structure with irregular morphology, under the control of the non-coaxial compression in the south and north and the stress transmitted by the uplift in the basin. The Wushenqi paleo-uplift has a controlling effect on the sedimentary reservoirs and hydrocarbon accumulation.
Abstract (
)
Download PDF (
)
HTML
(
)
Knowledge map
Save
The geological characteristics and enrichment laws of the shale oil in the third submember of the seventh member of Triassic Yanchang Formation (Chang 73) in the Ordos Basin were analyzed by using the information of core observations, experiments and logging, and then the exploration potential and orientation of the Chang 73 shale oil were discussed. The research findings are obtained in three aspects. First, two types of shale oil, i.e. migratory-retained and retained, are recognized in Chang 73. The former is slightly better than the latter in quality. The migratory-retained shale oil reservoir is featured with the frequent interbedding and overlapping of silty-sandy laminae caused by sandy debris flow and low-density turbidity current and semi-deep-deep lacustrine organic-rich shale laminae. The retained shale oil reservoir is composed of black shale with frequent occurrence of bedding and micro-laminae. Second, high-quality source rocks provide a large quantity of hydrocarbon-rich high-quality fluids with high potential energy. The source-reservoir pressure difference provides power for oil accumulation in thin interbeds of organic-poor sandstones with good seepage conditions and in felsic lamina, tuffaceous lamina and bedding fractures in shales. Hydrocarbon generation-induced fractures, bedding fractures and microfractures provide high-speed pathways for oil micro-migration. Frequent sandstone interlayers and felsic laminae provide a good space for large-scale hydrocarbon accumulation, and also effectively improve the hydrocarbon movability. Third, sand-rich areas around the depression are the main targets for exploring migratory-retained shale oil. Mature deep depression areas are the main targets for exploring retained oil with medium to high maturity. Theoretical research and field application of in-situ conversion in low-mature deep depression areas are the main technical orientations for exploring retained shale oil with low to medium maturity.
Abstract (
)
Download PDF (
)
HTML
(
)
Knowledge map
Save
Currently, the differences in gravity flow deposits within different systems tracts in continental lacustrine basins are not clear. Taking the middle submember of the third member of Paleogene Shahejie Formation (Sha 3 Member) in the Shishen 100 area of the Dongying Sag in the Bohai Bay Basin as an example, the depositional architecture of sublacustrine fans during forced regression and the impact of the fourth-order base-level changes on their growth were investigated using cores, well logs and 3D seismic data. Sublacustrine fans were mainly caused by hyperpycnal flow during the fourth-order base-level rise, while the proportion of slump-induced sublacustrine fans gradually increased during the late fourth-order base-level fall. From rising to falling of the fourth-order base-level, the extension distance of channels inside hyperpycnal-fed sublacustrine fans reduced progressively, resulting in the transformation in their morphology from a significantly channelized fan to a skirt-like fan. Furthermore, the depositional architecture of distributary channel complexes in sublacustrine fans changed from vertical aggradation to lateral migration, and the lateral size of individual channel steadily decreased. The lobe complex’s architectural patterns evolved from compensational stacking of lateral migration to aggradational stacking, and the lateral size of individual lobe steadily grew. This study deepens the understanding of depositional features of gravity flow in high-frequency sequence stratigraphy and provides a geological foundation for the fine development of sublacustrine fan reservoirs.
Abstract (
)
Download PDF (
)
HTML
(
)
Knowledge map
Save
In order to understand the mechanism of air flooding shale oil, an online physical simulation method for enhanced shale oil recovery by air injection was established by integrating CT scanning and nuclear magnetic resonance (NMR). The development effect of shale oil by air flooding under different depletion pressures, the micro-production characteristics of pore throats with different sizes and the mechanism of shale oil recovery by air flooding were analyzed. The effects of air oxygen content, permeability, gas injection pressure, and fractures on the air flooding effect in shale and crude oil production in pores with different sizes were analyzed. The recovery of shale oil can be greatly improved by injecting air into the depleted shale reservoir, but the oil displacement efficiency and the production degree of different levels of pore throats vary with the injection timing. The higher the air oxygen content and the stronger the low-temperature oxidation, the higher the production degree of pores with different sizes and the higher the shale oil recovery. The higher the permeability and the better the pore throat connectivity, the stronger the fluid flow capacity and the higher the shale oil recovery. As the injection pressure increases, the lower limit of the production degree of pore throats decreases, but gas channeling may occur to cause a premature breakthrough; as a result, the recovery increases and then decreases. Fractures can effectively increase the contact area between gas and crude oil, and increase the air sweep coefficient and matrix oil drainage area by supplying oil to fractures through the matrix, which means that a proper fracturing before air injection can help to improve the oil displacement effect under a reasonable production pressure difference.
Abstract (
)
Download PDF (
)
HTML
(
)
Knowledge map
Save
From the perspective of geological zone selection for coalbed methane (CBM) development, the evaluation parameters (covering geological conditions and production conditions) of geological sweetspot for CBM development are determined, and the evaluation index system of geological sweetspot for CBM development is established. On this basis, the fuzzy pattern recognition (FPR) model of geological sweetspot for CBM development is built. The model is applied to evaluate four units of No.3 Coal Seam in the Fanzhuang Block, southern Qinshui Basin, China. The evaluation results are consistent with the actual development effect and the existing research results, which verifies the rationality and reliability of the FPR model. The research shows that the proposed FPR model of geological sweetspot for CBM development does not involve parameter weighting which leads to uncertainties in the results of the conventional models such as analytic hierarchy process and multi-level fuzzy synthesis judgment, and features a simple computation without the construction of multi-level judgment matrix. The FPR model provides reliable results to support the efficient development of CBM.
Abstract (
)
Download PDF (
)
HTML
(
)
Knowledge map
Save
This study investigated experimentally the coupled effects of hydrophilic SiO2 nanoparticles (NPs) and low-salinity water (LSW) on the wettability of synthetic clay-free Berea sandstone. Capillary pressure, interfacial tension (IFT), contact angle, Zeta potential, and dynamic displacement measurements were performed at various NP mass fractions and brine salinities. The U.S. Bureau of Mines (USBM) index was used to quantify the wettability alteration. Furthermore, the NP stability and retention and the effect of enhanced oil recovery by nanofluid were examined. The results showed that LSW immiscible displacement with NPs altered the wettability toward more water wet. With the decreasing brine salinity and increasing NP mass fraction, the IFT and contact angle decreased. The wettability alteration intensified most as the brine salinity decreased to 4000 mg/L and the NP mass fraction increased to 0.075%. Under these conditions, the resulting incremental oil recovery factor was approximately 13 percentage points. When the brine salinity was 4000 mg/L and the NP mass fraction was 0.025%, the retention of NPs caused the minimum damage to permeability.
Abstract (
)
Download PDF (
)
HTML
(
)
Knowledge map
Save
The shale oil and gas exploitation in China is technically benchmarked with the United States in terms of development philosophy, reservoir stimulation treatment, fracturing parameters, fracturing equipment and materials, oil/gas production technology, and data/achievements sharing. It is recognized that the shale oil and gas exploitation in China is weak in seven aspects: understanding of flow regimes, producing of oil/gas reserves, monitoring of complex fractures, repeated stimulation technology, oil/gas production technology, casing deformation prevention technology, and wellbore maintenance technology. Combined with the geological and engineering factors of shale oil and gas in China, the development suggestions of four projects are proposed from the macro- and micro-perspective, namely, basic innovation project, exploitation technology project, oil/gas production stabilization project, and supporting efficiency-improvement project, so as to promote the rapid, efficient, stable, green and extensive development of shale oil and gas industry chain and innovation chain and ultimately achieve the goal of “oil volume stabilizing and gas volume increasing”.
Abstract (
)
Download PDF (
)
HTML
(
)
Knowledge map
Save
To further clarify the proppant transport and placement law in multi-branched fractures induced by volume fracturing, proppant transport simulation experiments were performed with different fracture shapes, sand ratios, branched fracture opening time and injection sequence of proppants in varied particle sizes. The results show that the settled proppant height increases and the placement length decreases in main fractures as the fracturing fluid diverts gradually to the branched fractures at different positions. The flow rate in branched fractures is the main factor affecting their filling. The diverion to branched fractures leads to low flow rate and poor filling of far-wellbore branched fractures. The inclined fracture wall exerts a frictional force on the proppant to slow its settlement, thus enhancing the vertical proppant distribution in the fracture. The increase of sand ratio can improve the filling of near-wellbore main fracture and far-wellbore branched fracture and also increase the settled proppant height in main fracture. Due to the limitation of fracture height, when the sand ratio increases to a certain level, the increment of fracture filling decreases. When branched fracture is always open (or extends continuously), the supporting effect on the branched fractures is the best, but the proppant placement length within the main fractures is shorter. The fractures support effect is better when it is first closed and then opened (or extends in late stage) than when it is first opened and then closed (or extends in early stage). Injecting proppants with different particle sizes in a specific sequence can improve the placement lengths of main fracture and branched fracture. Injection of proppants in an ascending order of particle size improves the near-wellbore fracture filling, to a better extent than that in a descending order of particle size.
Abstract (
)
Download PDF (
)
HTML
(
)
Knowledge map
Save
According to the variable toe-to-heel well spacing, combined with the dislocation theory, discrete lattice method, and finite-element-method (FEM) based fluid-solid coupling, an integrated geological-engineering method of volume fracturing for fan-shaped well pattern is proposed considering the geomechanical modeling, induced stress calculation, hydraulic fracturing simulation, and post-frac productivity evaluation. Besides, we propose the differential fracturing design for the conventional productivity-area and the potential production area for fan-shaped horizontal wells. After the fracturing of the conventional production area for H1 fan-shaped well platform, the research shows that the maximum reduction of the horizontal principal stress difference in the potential productivity-area is 0.2 MPa, which cannot cause the stress reversal, but this reduction is still conducive to the lateral propagation of hydraulic fractures. According to the optimized fracturing design, in zone-I of the potential production area, only Well 2 is fractured, with a cluster spacing of 30 m and an injection rate of 12 m3/min per stage; in zone-II, Well 2 is fractured before Well 3, with a cluster spacing of 30 m and an injection rate of 12 m3/min per stage. The swept area of the pore pressure drop in the potential production area is small, showing that the reservoir is not well developed. The hydraulic fracturing in the toe area can be improved by, for example, properly densifying the fractures and adjusting the fracture distribution, in order to enhance the swept volume and increase the reservoir utilization.
Abstract (
)
Download PDF (
)
HTML
(
)
Knowledge map
Save
Based on structural distribution and fault characteristics of the Luzhou block, southern Sichuan Basin, as well as microseismic, well logging and in-situ stress data, the casing deformation behaviors of deep shale gas wells are summarized, and the casing deformation mechanism and influencing factors are identified. Then, the risk assessment chart of casing deformation is plotted, and the measures for preventing and controlling casing deformation are proposed. Fracturing-activated fault slip is a main factor causing the casing deformation in deep shale gas wells in the Luzhou block. In the working area, the approximate fracture angle is primarily 10°-50°, accounting for 65.34%, and the critical pore pressure increment for fault-activation is 6.05-9.71 MPa. The casing deformation caused by geological factors can be prevented/controlled by avoiding the faults at risk and deploying wells in areas with low value of stress factor. The casing deformation caused by engineering factors can be prevented/controlled by: (1) keeping wells avoid faults with risks of activation and slippage, or deploying wells in areas far from the faulting center if such avoidance is impossible; (2) optimizing the wellbore parameters, for example, adjusting the wellbore orientation to reduce the shear force on casing to a certain extent and thus mitigate the casing deformation; (3) optimizing the casing program to ensure that the curvature radius of the curved section of horizontal well is greater than 200 m while the drilling rate of high-quality reservoirs is not impaired; (4) optimizing the fracturing parameters, for example, increasing the evasive distance, lowering the single-operation pressure, and increasing the stage length, which can help effectively reduce the risk of casing deformation.
Abstract (
)
Download PDF (
)
HTML
(
)
Knowledge map
Save
It is difficult to quantify and certify the greenhouse gas (GHG) emission reduction in the entire process of a project of carbon capture, utilization and storage (CCUS)-enhanced oil recovery (EOR). Under the methodological framework for GHG voluntary emission reduction project, the carbon emission reduction accounting method for CCUS-EOR project was established after examining the accounting boundaries in process links, the baseline emission and project emission accounting methods, and the emission and leakage quantification and prediction models, in order to provide a certification basis for the quantification of GHG emission reduction in the CCUS-EOR project. Based on the data of energy consumption, emission and leakage monitoring of the CCUS-EOR industrial demonstration project in Jilin Oilfield, the net emission reduction efficiency is determined to be about 91.1% at the current storage efficiency of 80%. The accounting and prediction of carbon emission reduction for CCUS-EOR projects with different concentrations and scales indicate that within the project accounting boundary, the certified net emission reduction efficiency of the low-concentration gas source CCUS-EOR projects represented by coal-fired power plants is about 37.1%, and the certified net emission reduction efficiency of the high-concentration gas source CCUS-EOR projects represented by natural gas hydrogen production is about 88.9%. The proposed method is applicable to the carbon emission reduction accounting for CCUS-EOR projects under multiple baseline scenarios during the certification period, which can provide decision-making basis for the planning and deployment of CCUS-EOR projects.
Abstract (
)
Download PDF (
)
HTML
(
)
Knowledge map
Save
To investigate the impacts of water/supercritical CO2-rock interaction on the micro-mechanical properties of shale, a series of high-temperature and high-pressure immersion experiments were performed on the calcareous laminated shale samples mined from the lower submember of the third member of Paleogene Shahejie Formation in the Jiyang Depression, Bohai Bay Basin. After that, grid nanoindentation tests were conducted to analyze the influence of immersion time, pressure, and temperature on micro-mechanical parameters. Experimental results show that the damage of shale caused by the water/supercritical CO2-rock interaction was mainly featured by the generation of induced fractures in the clay-rich laminae. In the case of soaking with supercritical CO2, the aperture of induced fracture was smaller. Due to the existence of induced fractures, the statistical averages of elastic modulus and hardness both decreased. Meanwhile, compaction and stress-induced tensile fractures could be observed around the laminae. Generally, the longer the soaking time, the higher the soaking pressure and temperature, the more significant the degradation of micro-mechanical parameters is. Compared with water-rock interaction, the supercritical CO2-rock interaction caused a lower degree of mechanical damage on the shale surface. Thus, supercritical CO2 can be used as a fracturing fluid to prevent the surface softening of induced fractures in shale reservoirs.
