Authigenic minerals from Chang 8 sandstones can preserve a precise paleotemperature record. Petrographic observations and geochemical characteristics provide a new insight into the formation mechanism of chlorite and calcite and resolve the problems of mobile elements between them. Chlorite is the most widely distributed mineral in the study area. In contrast, kaolinite is absent in some wells and intervals, which has implications for complete chloritization in the sandstones with abundant metamorphic and volcanic rock fragments due to the mixed provenances. Two stages of calcite cement can be identified: (i) early mesogenic, blocky calcite cement (GPI-Ca) precipitated from 84 to 107 °C in the oil-bearing sandstones (δ13CVPDB from -4.8‰ to -17.5‰; δ18OVPDB from -14.5‰ to -17.1‰); and (ii) late mesogenic, poikilotopic calcite cement (GPII-Ca) precipitated from 122 to 137 °C along the sandstone and mudstone (δ13CVPDB from -3.6‰ to -6.8‰; δ18OVPDB from -19.7‰ to -21.6‰). Grain-coating chlorite appeared to form from berthierine precursors from 70 to 110 °C, corresponding to the precipitation temperature of GPI-Ca. Pore-filling chlorite from kaolinite and illite formed at a temperature higher than 125 °C, corresponding to the precipitation temperature of GPII-Ca. GPI-Ca is characterized by nonferroan cement because the isomorphism contributes little at low temperatures and early-stage chloritization suppresses Fe into calcite. GPII-Ca without abundant metamorphic and volcanic rock fragments shows that ferrocalcite coexists with nonferroan calcite, but ferrocalcite does not exist in the sandstones with mafic minerals. Therefore, the chloritization of kaolinite is suitable for more Fe into the octahedral sites of chlorite in the diagenetic system rather than into calcite cement. The results of this study demonstrate the formation mechanism between chlorite and calcite through fluid-rock interactions. Better insights of the diagenetic sequence are significant to reconstruct the pore evolution history.

Carbonate reservoirs, characterized by extensive fractures and cavities, are prone to gravity displacement during drilling when the bottom-hole pressure approaches equilibrium. This phenomenon, driven by density differences between drilling and formation fluids, can result in simultaneous overflow and leakage, posing significant well control risks such as kicks or blowouts. The occurrence of gravity displacement downhole makes its timely detection through conventional annular flow monitoring techniques challenging. This study investigates the triggering conditions and safe density window for gravity displacement in fractured and cavernous formations. Through theoretical analysis and experimental simulation, we examined the displacement mechanisms in both fractured and cavernous conditions. Computational fluid dynamics (CFDs) simulations were used to validate critical fluid column heights for fractured formations and the proposed safe density window. Based on these findings, practical methods to mitigate the hazards associated with gravity displacement overflow are proposed. The results offer valuable guidance for the field identification and mitigation of such incidents, contributing to managed pressure drilling and enhancing drilling safety in complex carbonate reservoirs.

During the development of multi-layer tight sandstone gas reservoirs in Ordos Basin, China, it has not been easy to calculate accurately the production of each individual layer in gas wells. However, production allocation provides a vital basis for evaluating dynamic reserves and drainage areas of gas wells and remaining gas distributions of gas layers. To improve the accuracy and reliability of production allocation of gas wells, a new model was constructed based on the seepage equation, material balance equation, and pipe string pressure equation. In particular, this new model introduced the seepage equation with an elliptical boundary to accurately capture the fluid flow characteristics within a lenticular tight gas reservoir. The new model can accurately calculate the production and reservoir pressure of each individual layer in gas wells. In addition, the new model was validated and applied in the Sulige gas field, Ordos Basin. The following conclusions were drawn: First, The gas production contribution rates of pay zones based on the new model are fairly close to the measurements of the production profile logging, with errors less than 10%. Second, The overall drainage area of a gas well lies among those of each pay zone, and the total dynamic reserves of the well are close to the sum of the dynamic reserves of pay zones. Third, Higher permeability may lead to higher initial gas production of the pay zone, but the ultimate gas production contributions of pay zones are affected jointly by permeability and dynamic reserves. Finally, The new model has been successfully applied to the SZ block of the Sulige gas field, in which the fine evaluation of dynamic reserves, drainage areas, gas production, recovery factors, and remaining gas distributions of different layers was delivered, and the application results provide technical support for the future well placement and enhanced gas recovery of the block.

Deep coal-rocks in China are widely distributed and characterized by greater thickness, and coal-rock methane (CRM) resource potentials have been suggested to be huge. In recent years, the exploration and development of deep CRM have achieved major breakthroughs, attracting widespread attention. Based on recently published data, this paper systematically summarizes the exploration and development history, geological and distribution characteristics of the coal-rocks, and the main controlling factors of deep CRM enrichment in China. Deep CRM is mainly widely distributed in the northern and southwestern areas of China and primarily developed in three sets of strata: the Carboniferous, Permian, and Jurassic systems. Deep coal-rocks exhibit high total organic carbon contents, with organic matter types mainly classified as types II2 and III, generally in the mature to highly mature stages, demonstrating strong gas generation capacity. The maceral composition is dominated by vitrinite, and the industrial composition is primarily fixed carbon, which is classified as high-quality coal. The distribution of sedimentary facies, high thermal evolution degree, development of pores and microfractures, and favorable preservation conditions are significant factors contributing to the high CRM content. The primary occurrence states of deep CRM consist of adsorbed and free states. Under geological conditions, the adsorbed CRM content is mainly controlled by temperature, showing a clear negative correlation, while the reservoir pressure has a lesser impact on CRM content. Based on the analysis of the controlling factors for the enrichment and high production of deep CRM in China, it is concluded that CRM reservoirs can be classified into two accumulation models: self-sourcing and self-reservoiring and endogenous sourcing with external reservoiring.

The Lower Cambrian shale gas resources in southern China have huge potential. However, the reservoirs generally contain a relatively high content of nonhydrocarbon gases, which has a significant impact on the exploration and development of shale gas. The source of nonhydrocarbon gases in the Lower Cambrian shales has become a research hotspot. Based on recently published data, this paper systematically summarizes the geological and distribution characteristics, gas-bearing properties, and genesis mechanism of Lower Cambrian shale gas in southern China. The Lower Cambrian shales in southern China are widely distributed in the Yangtze Platform. The overall total organic carbon (TOC) content is relatively high. The kerogen type is mainly type I, and the equivalent vitrinite reflectance (EqRo) value ranges from 2.5 to 6.0%. The mineral components of the Lower Cambrian shales are mainly quartz, clay minerals, and carbonate minerals, and the main lithofacies types are mainly siliceous shale and mixed (siliceous-clay) shale. The gas-in-place (GIP) content of the Lower Cambrian shales varies greatly in different regions. Currently, shale gas, mainly composed of CH4, has only been discovered in the southwestern Sichuan, western Hubei, northeastern Chongqing, and northern Guizhou areas, while in other Yangtze regions, the GIP content of shales is very low or almost nonexistent. The distribution of δ13C1, δ13C2, and δ13C3 in the Lower Cambrian shale gas shows a significant inversion. Among the nonhydrocarbon gases, N2 mainly originates from atmospheric and/or pyrolysis, CO2 is mainly of organic origin, while He exhibits typical shell-source characteristics, which may be from the ancient basement and/or the radioactive decay accumulation of U and Th in the shale. On this basis, an evolution model of the Lower Cambrian shale gas was constructed. Hydrocarbon generation in the Lower Cambrian shales can continue until EqRo = 3.5%, after which N2 is mainly produced. CO2 is mainly formed in the low mature stage, and the He content shows continuous generation throughout the shale evolution process.

More than 50% of global coalbed methane (CBM) resources are estimated to reside in deep coal seams (depth >1500 m). The CBM retained in deep coal seams has higher free gas content with less formation water compared to the CBM in shallow coal seams, leading to different production methods. Current research has primarily addressed the shallow CBM extraction, with limited transferability to deep CBM (DCBM) reservoirs due to the distinct reservoir characteristics and occurrence state. In this work, we developed a slit-pore model to investigate the adsorption behaviors and production mechanisms of DCBM using molecular dynamics simulations. The slit-pore model includes a micropore, a macropore, and a fracture/cleat to simulate the flow unit of anthracite. We analyzed the adsorption patterns at different production stages and quantitatively evaluated the production performance of pressure-relief production and pressure-control production. DCBM components (CH4, C2H6, N2, and CO2) are heterogeneously distributed in the multiscale model, with higher proportions of CH4, C2H6, and CO2 in the micropore due to the high adsorption affinity and small molecular diameters. CH4, C2H6, and CO2 exhibit monolayer adsorption in the micropore, and the production methods do not affect the adsorption pattern. Compared to the pressure-relief production, the pressure-control production yields higher DCBM production. The mass transfer from the macropore and the water-blocking effect in the micropore collectively constrain the fluid release from the micropore during pressure-relief production. This work provides a comprehensive understanding of the DCBM adsorption behaviors and production mechanisms.

This study systematically reviews the development history and key technological breakthroughs of large gas fields in the Ordos Basin, and summarizes the development models of three gas reservoir types, low-permeability carbonate, low-permeability sandstone and tight sandstone, as well as the progress in deep coal-rock gas development. The current challenges and future development directions are also discussed. Mature development models have been formed for the three representative types of gas reservoirs in the Ordos Basin: (1) Low-permeability carbonate reservoir development model featuring groove fine-scale characterization and three-dimensional vertical succession between Upper and Lower Paleozoic formations. (2) Low-permeability sandstone reservoir development model emphasizing horizontal well pressure-depletion production and vertical well pressure-controlled production. (3) Tight sandstone gas reservoir development model focusing on single-well productivity enhancement and well placement optimization. In deep coal-rock gas development, significant progress has been achieved in reservoir evaluation, sweet spot prediction, and geosteering of horizontal wells. The three types of reservoirs have entered the mid-to-late stages of the development, when the main challenge lies in accurately characterizing residual gas, evaluating secondary gas-bearing layers, and developing precise potential-tapping strategies. In contrast, for the early-stage development of deep coal-rock gas, continuous technological upgrades and cost reduction are essential to achieving economically viable large-scale development. Four key directions of future research and technological breakthroughs are proposed: (1) Utilizing dual-porosity (fracture-matrix) modeling techniques in low-permeability carbonate reservoirs to delineate the volume and distribution of remaining gas in secondary pay zones, supporting well pattern optimization and production enhancement of existing wells. (2) Integrating well-log and seismic data to characterize reservoir spatial distribution of successive strata, enhancing drilling success rates in low-permeability sandstone reservoirs. (3) Utilizing the advantages of horizontal wells to penetrate effective reservoirs laterally, achieving meter-scale quantification of small-scale single sand bodies in tight gas reservoirs, and applying high-resolution 3D geological models to clarify the distribution of remaining gas and guide well placement optimization. (4) Further strengthening the evaluation of deep coal-rock gas in terms of resource potential, well type and pattern, reservoir stimulation, single-well performance, and economic viability.

To address the challenges of characterizing commingled production from multiple channel sand layers with varying boundaries and shapes in tight gas reservoirs, a novel Rate Transient Analysis (RTA) model was established based on the principle of equivalent seepage volume (ESV). This model enables the determination of boundary sizes and permeabilities of individual channel sand layers within commingled tight reservoirs using modern production decline analysis theory. The production decline behavior under different channel sizes, numbers, and configurations was systematically investigated through type curve analysis. The results reveal the existence of five distinct stages in the production decline curves for unequal-width channel sands. The intermediate transient flow stage serves as a diagnostic indicator for identifying boundary disparities among layers. Furthermore, reservoirs with smaller boundary distances, fewer wide channel sand layers, and lower thickness proportions of wider channels exhibit poorer productivity and tend to experience accelerated production decline during early and middle transient flow stages. The proposed method provides an effective approach for characterizing boundary parameters of commingled tight reservoirs and offers a theoretical foundation for evaluating individual layer contributions and productivity.

Through systematic investigation of deep coal-rock gas in the Ordos Basin, NW China, this work analysed the thickness distribution of the entire Upper Paleozoic coal-rock intervals, quantified the resource potential of representative areas (a 12 000 km2 rectangular block in the eastern Ordos Basin roughly centered on Yulin City), clarified the occurrence characteristics of coal-rock gas, and identified key development indicators for gas wells, thereby defining the direction for iterative optimization of key technologies. (1) The total coal-rock gas in-place of the Upper Paleozoic coal seams 1#–10# in the resource evaluation region is assessed at 5.66×1012 m3, of which coal seam 8#, currently the main target interval, contains about 3.08×1012 m3, accounting for roughly 54% of the total. (2) Deep coal-rock gas is characterized by a high ratio of free gas. Under the conditions of 2 000 m burial depth, 6.35% porosity, 95% free gas saturation, and 22.13 m3/t total gas content, the free gas content of the reservoir is estimated to be ca. 40% of the total gas. (3) Three productivity evaluation models (triangular, convex, concave) are developed for horizontal wells, of which the triangular model can serve as the reference model for predicting the estimated ultimate recovery (EUR) throughout the lifecycle of coal-rock gas wells. Using the triangular model with a 7 m coal thickness, 1 500 m effective lateral length and 400 m well spacing, the average single-well EUR is determined to be 4 621.28×104 m3. (4) Development of the coal seam 8# should employ horizontal wells with pressure-controlled production. Meanwhile, it can be further optimized by adopting the cost-effective strategies of Sulige Gas Field in the Ordos Basin, China. (5) To achieve cost-effective development and increase primary recovery factor, key technologies must undergo continuous iteration and upgrading, focusing on accelerating drilling, extending effective lateral lengths, high-intensity reservoir stimulation, and well-pattern optimization.

In view of the characteristics of low permeability, strong heterogeneity, small effective sand scale and poor connectivity of tight gas reservoir, well pattern infilling optimization is the main method to improve gas recovery. Taking Sulige gas field as an example, based on the study of sedimentary facies, effective sand-body distribution, combined with production performance and engineering parameters, the well control drainage was obtained. Meanwhile, the interwell connectivity and interference probability was qualitatively analyzed by interference well test, and the critical well spacing density was determined. In order to quantitatively reveal the gas grabbing degree at different well spacing density and determine whether the final cumulative gas production of gas wells with interference is economical and feasible, the evaluation index of "gas well production interference ratio (GWPIR)" was defined specifically, and the intersection plot of GWPIR relating to gas reserve abundance and well spacing density was draw. Different from the traditional method of well number interference probability, through the combination of GWPIR plot and economic evaluation, well pattern optimization from both two perspectives of pursuing higher economic benefits and recovery degree can be realized, providing technical support for improving gas recovery and long-term stable production of gas field.

The western Sulige gas field is a new and key reserve area for the rolling development of the Sulige gas field in China. However, due to the complex gas–water relationship and the difficulty in identifying gas and water formation, the scale and benefit deployment of the gas field are seriously restricted. In particular, almost all of the wells in the area produce water, and no water measurements have been carried out for any single well, which leads to an unclear understanding of the dynamic characteristics of the production wells, thus affecting the productivity calculations of the gas wells and the overall regional productivity evaluation. Based on the testing data for a gas well, the impacts of the reservoir property parameters on the gas and water production were analyzed by combining the production performance and static geological characteristics. It was determined that the physical parameters K, Kh, and φSg had good positive correlations with gas production but not with water production; thus, effective prediction cannot be obtained for water production in gas well testing. After the analysis of the liquid-loading law, the gas wells were classified into three types: continuous liquid-carrying production, slight liquid-loading, and liquid-loading wells. In general, up to 96% of the gas wells were liquid-loaded. According to the different production performances exhibited in the different stages of the gas wells, five types of methods for diagnosing water production wells were proposed (gas testing, pilot production, gas–liquid two-phase measurement testing, liquid level detection, and production performance analysis), as well as the diagnostic criteria and corresponding solutions. To obtain real-time water production data for each well and investigate the change in the water–gas ratio (WGR) during the whole production process, a water production splitting method for gas wells based on three-dimensional geological modeling and numerical simulation combined with the constraints of the total water production of gas gathering stations was explored and established. The splitting results can be used to evaluate the water and gas productivity of gas wells and determine the best deliquification period. The gas well productivity when water production was considered was about 10% lower than that when water production was not considered. The best deliquification period was determined to be 125 days for wells with small water production, 20 days for wells with moderate water production, and 3 days for wells with serious water production. The results of this study could provide technical support for the scientific evaluation of gas well production indicators, reduction in development costs, and improvement in oil recovery.

Based on the abundant static and dynamic data of horizontal wells in Sulige gas field, we carried out the fine description and development dynamic response analysis of the effective reservoir of the actually drilled horizontal wells and put forward three effective reservoir spatial distribution modes, which were block concentrated development, medium thin layer superposition, and thin layer isolation. We established the reservoir classification standard for the deployment of horizontal wells. Based on the core indexes such as dynamic reserves, drainage area, initial reasonable production, and decline rate of horizontal wells, the quantitative identification and division standard of horizontal well development effect were also established. The dynamic reserves of horizontal wells in three types of reservoirs are more than 8×10~7 m~3, 6×10~7～8×10~7 m~3, less than 6×10~7 m~3, the initial outputs are 6 × 10~4, 4 × 10~4, and 2 × 10~4 m~3/d, and the initial decline rates are 32.9%, 35.0%, and 40.0% respectively. The dynamic and static horizontal well development effect evaluation system established in this paper could support the optimal deployment of horizontal wells in Sulige gas field in the future.

苏里格气田勘探发现以后效益开发面临极大挑战,为吸收借鉴国际先进的开发技术和管理经验实现开发突破,确立了与法国道达尔公司共同开发、中方担任作业者的国际合作开发模式.10余年的合作开发实践表明,在相同的储层地质条件下国际合作区单井开发指标明显高于自主开发区,系统梳理关键开发技术并进行系统总结对提升自主开发区开发效果具有重要意义.与自主开发区追求规模效益与低成本控制的开发理念不同,国际合作区以经济效益、正现金流策略为目标,以风险控制为核心.经过多年集中攻关与实践检验,形成了三维地震—地质融合储层评价、网格分区棋盘丛式标准化井网部署、批量实施工厂化钻完井作业、TAP Lite分层压裂储层改造、适度放压间歇生产气井管理、速度管柱主导的措施增产6项关键核心特色开发技术,通过与自主开发区技术对比,落实了5项可供借鉴的特色开发技术,并总结了 3条重要启示:(1)持续深化地质研究支撑高质量部署;(2)加强顶层优化设计支撑科学有序实施;(3)强化全过程管理与质量控制助推开发效果提升.国际合作区关键核心开发技术与重要经验的吸收借鉴可对致密气新区开发效果的提升提供有力支撑.

苏里格致密砂岩气田储层物性差、垂向上发育多层透镜状有效砂体、规模小、非均质性强,现有井网对储层控制不足,采收率偏低.井网优化调整是致密气提高储量动用程度及采收率的最有效手段之一.根据储层结构及气井生产开发效果,将气田可效益动用储层划分为3种类型,分别对应储量丰度为:>1.8×108 m3/km2、(1.3～1.8)×108 m3/km2、(1.0～1.3)×108 m3/km2.基于不同储层条件下的密井网试验区实际生产数据,结合储层规模分析和气井泄气范围评价,兼顾开发效益和提高采收率,从采收率增幅拐点、区块整体有效、新井能够自保等方面开展适宜井网密度综合分析,明确了3类储层的适宜井网密度分别为3口/km2、4口/km2、4口/km2.苏里格致密砂岩气田剩余可动储量1.23×1012 m3,新的差异化布井方式相比于600 m×800 m井网,可多钻井1.2万口,多建产能450×108 m3,累计多产气2000×108 m3,可将采收率由32％提升至48.5％.

苏里格气田是典型的致密砂岩气田,年产气量达250×108 m3,气田西区是苏里格气田长期稳产的重要后备储量区.由于该区低阻气层和富集区识别困难,生产井气水同产、携液能力弱,制约了该区天然气的有效开发.为此,以气藏地质特征为基础,从动、静态结合角度出发,开展了产层测井识别、气水分布控制因素、富集区优选及不同天然气富集级别区差异化开发技术对策等研究.结果 表明:①西区具有气水分异差,气、水层混杂分布,无统一气水界面的气水分布特征;②生烃强度、储集层非均质性对气水分布具有主控作用,生烃强度控制了气、水分布的宏观格局,区域生烃强度越大,气层相对越发育,储层非均质性则控制天然气的局部充注和聚集成藏;③气水分布模式纵向上可划分为上水下气型、上气下水型、上下水夹气型、巨厚储层气水混存型及纯气型5种类型;④针对气田开发主要面临的4个方面的挑战,提出了以产层测井识别、富集区优选、产水劈分、生产制度及排采周期优化为核心的高含水致密砂岩气藏差异化开发技术对策.结论 认为,形成的高含水致密砂岩气藏差异化开发技术对策能够解决苏里格气田开发面临的4个挑战,可为气田持续稳产提供技术支撑,且对同类型气藏开发具有参考和借鉴意义.

As one of the important types of unconventional gas, tight gas is widely distributed in various major petroliferous basins in the world. The breakthrough of reservoir reconstruction technology and the reduction of development cost promote the scale and industrial development of tight gas. China is the third largest tight gas producer in the world and its yearly tight gas production is up to 470 × 108 m3 in 2020. In order to evaluate the development prospect of tight gas in China, this paper systematically summarizes domestic key technical series developed in the last 20 years' tight gas practice, after briefly analyzing the distribution and development history of tight gas resources all over the world. Then, the prospect of tight gas development in China is based on CNPC's fourth resource evaluation results. And the following research results are obtained. First, tight gas resource in China is abundant, accounting for about 10% of global resources, and its development is divided into two stages, i.e. the development evaluation stage and the development adjustment stage. Second, key technologies in the development evaluation stage include the establishment of genesis unit of effective reservoir, enrichment area selection, development index evaluation, well pattern and type optimization, reservoir reconstruction, and development scheme optimization. Third, the core in the development adjustment stage is enhanced gas recovery (EGR). The main technical means are well pattern optimization and infilling. Which can increase the recovery factor by 10%–20%. In addition, layer reviewing and reperforating, old well sidetracking, secondary fracturing, drainage and gas recovery, and pressurized production are also effective technologies. In conclusion, tight gas still has greater production potentials and development prospects in China. The potential tapping of produced proved reserves, the development of unproduced proved reserves and the effective development of new proved reserves are three important aspects to ensure the mid- and long-term development of tight gas. The first two aspects can support the yearly tight gas production to reach the peak of (700–800) × 108 m3 in 2030–2035 and keep stable production for more than 10 years. Moreover, the continuous development of new proved reserves will further support the stable production of tight gas until 2050–2060.

Successful exploitation of tight sandstone gas is one of the important means to ensure the “increasing reserves and production” of the oil and gas initiative and also one of the important ways to ensure national energy security. To further improve the accuracy of historical matching of field data such as gas production and bottom-hole pressure during the production process of this type of gas reservoir, in this study, a new expression of wellbore pressure for the uniform flow of vertical fractured wells in Laplace space based on the point sink function model of vertical fractures in tight sandstone gas reservoirs is constructed. This innovation is based on a typical production data analysis plot of the Blasingame type that uses the numerical inversion decoupling mathematical equation. After analyzing the pressure and pressure derivative characteristics of each flow stage in the typical curves, a new technique of type-curve matching was proposed. In order to verify the correctness of the model and the application value of the field, based on the previous production data of Sulige Gas Field in China, a new set of production data diagnostic chart of tight sandstone gas reservoir was formed. A case analysis showed that the application of the production data analysis method and data diagnosis plot in the field accurately evaluated the development effect of the tight sandstone gas reservoirs, clarified the scale of effective sand bodies, and provided technical support for optimizing and improving the well pattern and realizing the efficient development of gas fields.

鄂尔多斯盆地低渗透—致密气藏储量规模虽大,但储层物性差、非均质性强、储量动用程度低且差异大,要实现气藏的长期稳产及效益开发难度大.为此,以该盆地5个主力气田为研究对象,以效益开发为导向,以内部收益率为核心评价指标,结合动、静态特征对低渗透—致密气藏进行储量评价单元划分、储量分类评价和储量接替序列的建立,并针对不同类型的储量提出相适应的开发技术对策.研究结果表明:①该盆地单井动态储量小、产气量低,产气类型可以划分为多层协同供气和单层主力供气两种;②基于地质条件和单井动态特征相近的原则,结合开发管理区块分布情况,将该盆地内5个主力气田划分为11个储量评价单元,以内部收益率30％、8％和5％作为界限,把储量评价单元划分为高效、效益、低效和难动用4种储量类型;③以内部收益率8％为有效开发的基准,将其对应的井均估算最终开采量(EUR)与各个储量评价单元实际的井均EUR对比,按照效益由高到底的顺序,建立了储量评价单元经济有效动用序列;④高效储量适宜采取增压开采和局部井网调整对策,效益储量需通过井网加密提高储量动用程度,低效储量应采取富集区优选、滚动开发对策,难动用储量需加大技术攻关以实现效益开发.结论 认为,该研究成果有助于提高鄂尔多斯盆地天然气储量的动用程度,可以为该盆地天然气长远开发战略的制订提供技术支撑.

鄂尔多斯盆地东部神木气田是长庆气区目前增储上产的重要组成部分,系统研究其储层特征、空间叠置结构及水平井开发适用性对气田科学开发具有重要意义.实验分析表明,神木气田山西、太原组储层岩石类型主要为岩屑石英砂岩、岩屑砂岩及石英砂岩,孔隙类型以溶蚀孔、晶间孔及粒间孔为主,储层孔隙度分布于2.0％～ 10.0％,平均为6.6％,渗透率分布于0.10～1.00 mD,平均为0.83 mD,整体属低孔、致密砂岩储层.测试分析表明,孔隙度5.0％、渗透率0.10 mD、含气饱和度45％为有效储层物性下限标准.基于密井网解剖,将有效砂体空间结构类型划分为多层孤立分散型、垂向多期叠加型、侧向多期叠置型等3种.研究表明,神木气田不适合开展大规模水平井开发,可在有限地区进行局部式水平井部署.

国内致密砂岩气藏普遍存在含气砂体分布零散、储集体内非均质性强的特征,含气砂体准确预测的难度较大.对于水平井开发方式而言,2口相向水平井靶点B之间留有较大间距,将造成储量平面控制和动用程度降低.从国外致密气开发实践调研入手,基于鄂尔多斯盆地苏里格致密砂岩气藏有效砂体空间展布、规模尺度及开发动态特征分析,结合数值模拟方法,论证水平井在不同部署方式下的开发效果,提出水平井的优化部署方案.研究表明:相向2口水平井靶体B点接近重合、压裂段等间距部署,可以大幅度提高水平井对储量的控制和动用程度,同时有效提高气田整体开发经济效益.研究成果在致密气实际开发中具有可操作性和推广应用前景.