In the process of CBM development, the fracturing effect has always been a major controlling factor for CBM productivity. The coal fragmentation degree is a special geological feature in the process of CBM development and research, and other types of reservoirs are not involved in this study. This paper addresses the problem of the inaccurate prediction of the reservoir fragmentation degree by studying the influence of the reservoir type and depth plane curvature on the reservoir fragmentation degree based on the coalbed characteristics of a block. It also studies the influence of faults on the reservoir fragmentation degree based on the reservoir geological characteristics and seismic inversion results. Combined with dynamic data on coalbed methane production, the influence of different geological characteristics on the productivity of coalbed methane wells is studied. The research results show that the reservoir fragmentation degree is mainly affected by the reservoir type. In the coal-forming period or after coal forming, the stronger the tectonic movement is, the higher the reservoir fragmentation degree is. Another manifestation of tectonic movement is faults. The effect of the reservoir fragmentation degree on production is negative. The better the reservoir fragmentation degree is, the worse the reconstruction effect of the coalbed methane well is, and the worse the later production effect is. At the same time, the faults generated by tectonic movement affect not only the reservoir fragmentation degree but also the water production of coalbed methane wells. The closer a well is to a fault, the greater the risk is of high water production and low gas production. Therefore, in the process of selecting a desert area, a complex reservoir fragmentation degree and areas with strong tectonic movement should be avoided. This study takes a structural control block as the research object to study the main controlling factors of coalbed methane reservoir productivity in complex structures. At present, there is no relevant research on this structure in terms of controlling productivity at home or abroad. The research in this paper can provide technical support for the development of similar CBM reservoirs. This method can guide the development of coalbed methane fields and lay a foundation for the selection of favorable coalbed methane reservoir areas.

Recent years, domestic and foreign scholars have done a lot of exploration and practice on seismic prediction methods of the gas content of the coalbed. Amplitude variation with offset (AVO) analysis technique can be applied to the coalbed gas, but it is different from the “established conclusion” of conventional natural gas. Take K area as an example, Modulus attributes and density of the coalbed are sensitive to coalbed gas through petro-physical analysis. That means the higher the gas content, the lower the modulus property and density value, moreover, the negative correlation between gas content and modulus attributes is more obvious. Through AVO forward modeling analysis, 8+9# coalbed in K area shows the type IV of AVO abnormal characteristics, and high gas content corresponds to strong abnormal, low gas content corresponds to weak abnormal. AVO attribute of “A-B” can predict the gas content of 8+9 coalbed in K area, which shows good application effect.

To explore the impact of different bedding angles on the fractures propagation of coal hydraulic fracturing in coal-rock formations, based on the zero thickness Cohesive unit damage criterion, a finite element model of coal and rock hydraulic fracturing fractures propagation at different bedding angles (0°, 30°, 45°, 60°, 90°) is established. The hydraulic fracturing results at different bedding angles are characterized by hydraulic fracture propagation morphology, the number of branch fractures and joint widths. The hydraulic fracture width and pore pressure of coal rock under different horizontal geo-stress difference at different bedding angles are analyzed and verified in well FG-T29 of Shenfu Block. The results show that when the bedding is 0°, the hydraulic fracture spreads after penetrating the first bedding; when the bedding is 30°, the fractures first pass through the first bedding, extend along the direction of the second bedding, and then turn at the bedding; when the bedding is 45°, the fractures turn after extending along the first layer; the cracks of 60° and 90° bedding did not extend to the bedding surface. Compared with the other 4 bedding angles, 45° bedding coal rock has the largest number of branch fractures (15) and the largest fracture width (6.19 mm) during fracturing. With the increase of horizontal geo-stress difference, the crack width of hydraulic fracture decreases and the initiation pressure increases for all the five bedding angles.

This paper proposes a coal structure prediction technology based on deep learning, which uses logging data to achieve single-well prediction of the coal structure. This paper introduces the genetic algorithm (GA) to optimize the BP neural network, which can speed up its convergence to the global optimal solution, improve its training speed, and avoid the problems of easily producing the local optimal value and requiring a long training time. Taking the main coal seam of the Shizhuang block in the south of the Qinshui Basin as the research object and using the coal core data and logging data of nine parameter wells, the mapping relationship between the logging curve and coal structure is constructed based on the GA-BP neural network structure, and the coal structure is predicted. The prediction results are highly consistent with the coal structure measured from coal core sampling, with only a small error, and the prediction accuracy is 90%. It is shown that the GA-BP neural network structure can be used to effectively identify the coal structure, as well as predict the coal structure of uncored wells. Moreover, the findings of this study will be helpful for efforts to study the distribution law of the coal structure.

Carbonate conglomerate in the lower part of the third member of the Eocene Shahejie Formation comprises one of the most important petroleum exploration targets in the Bohai Bay Basin. Based on core observations and thin-section identifications, the carbonate conglomerate is divided into five types in the central area of the Shulu Sag. Reservoir space types are studied by observation through casting thin sections, fluorescent thin sections and scanning electron microscopes. The category of carbonate conglomerate is grouped into five classes: clast-supported extraformational calcirudite (LF1), clast-supported mixed-source calcirudite (LF2), clast-supported intraformational calcirudite (LF3), matrix-supported extraformational calcirudite (LF4) and matrix-supported mixed-source calcirudite (LF5). The mixed-source calcirudites and intraformational calcirudites are relatively rare and consist of gravel-sized micritic intraclasts formed from the intra-basin soft lime mud sediments and terrigenous clasts from the surrounding provenance areas. The conglomerate rocks in the Shulu Sag can be primarily attributed to two genetic types: ‘fan delta formed by alluvial fan and lacustrine’ and ‘seismic-induced slump fan’. The rock types formed by fan deltas mainly include LF1 and LF4. The rock types formed by seismic-induced slump fans are more complex and include LF1, LF2, LF3, LF4 and LF5. The reservoir space consists of various types, including intra-granular pores (e.g. dissolution pores in pyrite and intercrystalline dissolution pores in dolomite), intergranular pores, fractures (tectonic fractures, fractures around grains, diagenetic shrinkage fractures and fractures in the allogenic grains) and organic matter pores. The reservoir spatial distribution is mainly affected by the content of terrigenous grain and matrix, grain composition and fracture density. LF1 exhibits the best reservoir properties. LF2 and LF4 have the second best reservoir quality. They are all excellent tight oil reservoirs in the Shulu Sag.

C6 reservoir in the Ordos Basin is mainly composed of medium fine-grained arkose with a burial depth of 1500–2000 m. The pore structure of reservoir space is complex, the throat is fine and the sorting is poor. The average permeability of the reservoir is 0.01–100.00 mD, and the porosity is generally less than 19

Different from conventional gas reservoirs, the permeability of coalbeds is affected by stress sensitivity and matrix shrinkage during production. These two conditions lead to lower permeability in the reservoir and affect the production efficiency of the gas well. In addition, coalbed methane wells have single-phase water flow in the initial stage of production. When the reservoir pressure is reduced to its critical desorption pressure, the adsorbed gas in the reservoir desorbs into the pore space and participates in the flow. The flow state in the reservoir changes from single-phase to two phase, and the permeability of the reservoir decreases. The occurrence of these three damage mechanisms is related to the flow rate of fluid in the reservoir. At present, there is a lack of research on the optimization of drainage and production systems considering the damage mechanism of coal reservoirs. This study comprehensively considers how to optimize the production rate of coal reservoirs under the influence of stress sensitivity, matrix shrinkage and two phase flow in the production process to achieve the purpose of production with the least damage to the reservoir.

基于经典层序地层学理论,分析沁水盆地柿庄地区太原组含煤岩系高分辨率层序地层,探讨薄煤层及 15 号厚煤层的旋回样式,研究陆表海背景下高分辨率层序地层格架下的聚煤模式.结果表明:以煤层底面、古土壤层及沉积相转换面作为四级层序的界面,以灰岩底界或障壁砂、潟湖泥岩底界为最大海泛面,将太原组分为 6 个四级层序,包含 12个体系域;提出含煤岩系进积非对称型、进积对称型、退积非对称型、退积对称型 4 种旋回样式;在缓慢海平面变化中,退积对称型旋回样式形成薄煤层和厚煤层的夹矸;在快速海侵过程中,进积非对称型、进积对称型、退积非对称型厚煤层用于解释 15 号煤层向陆方向、中部、向海方向的旋回样式.该结果明确陆表海背景下高分辨率聚煤模式由泥炭堆积速率和可容空间变化速率决定,为相同地质背景下煤层气勘探开发提供地质依据.

In Jiaozuo coalbed methane exploration block of Henan province,the coal seam Ⅱ1 of Shanxi Formation has the characteristics of large thickness and high gas content.The parameter wells of coalbed methane,drilled and drained at western slope zone and gentle slope of central nose shaped structural zone,have achieved a breakthrough in production in the year of 2022.Even possessing abundant coalbed methane resources,no breakthrough on coalbed methane exploration has been achieved yet.Through the study on structural evolution and faults,reservoir separation mechanisms of favorable coalbed methane exploration area and gas production attribution analysis,the following new understandings have been gained in terms of structural and sedimentary characteristics,gas bearing characteristics of coal reservoirs and coal structure and permeability law:①The multiple tectonic revolutions lead to structural morphology of stepped fault block distribution,which results in significant differences in the burial depth of coal seam;②The tectonic coal reservoir formed by the strong compression and kneading of the structure is an important adverse factor for the poor gas production of coalbed methane wells;③Focusing on reservoirs with optimized gas bearing conditions and coal body structure in the weakly affected area of fault structures is profit to ensure the effectiveness of stimulation and transformation and the high production of gas wells.Successful drilling of new parameter wells realizes the overshoot in the exploration of medium-deep coal seams in Jiaozuo block and has important guiding significance for revitalizing the block,rolling exploration and improving reserves in the later stage.

不同聚煤模式下控制的煤层分布规律制约着煤层气的勘探开发.为明确三角洲平原含煤岩系聚煤模式,选取沁水盆地柿庄地区山西组3号煤层及其下伏和上覆岩层为研究对象,在岩心观察、建立高分辨率层序格架的基础上,对含煤岩系沉积相进行划分.研究表明:①研究区山西组为三角洲平原沉积,自下而上呈现逐步海退、陆相作用增强、从北向南逐渐进积的过程.②三角洲平原中发育分流河道、天然堤、决口扇及分流间湾等沉积微相类型,在垂向上形成由砂岩、泥岩构成的煤层顶、底板,组成了 4种类型复合砂体叠置模式.其中,分流间湾泥岩夹煤是对煤层气保存最优的叠置模式类型.③在泥炭沼泽发育过程中,初期的地势低洼处优先形成低位泥炭沼泽,但灰分产率较高,而后形成高位泥炭沼泽,形成厚煤层,灰分产率降低.泥炭沼泽发育前、发育过程及终止后三个阶段形成的空间组合共同组成了三角洲平原聚煤模式.该模式为三角洲平原煤层气的勘探开发提供地质理论依据.

为解决煤层气勘探开发过程中煤岩品质评价问题,梳理出煤岩品质评价关键要素为"三结构"即煤层结构、煤体结构和宏观煤岩类型结构.以沁水盆地SZB区块3号煤层为例,依托27 口煤层气参数井煤岩描述和常规测井资料,分别建立了基于测井响应的煤岩"三结构"定量表征方法,形成了一套煤岩品质定量化评价体系.依据煤岩品质评价结果,研究区以Ⅰ类优质煤岩和Ⅱ类良好煤岩为主,主要特征表现为夹矸不发育或者发育较薄,以原生结构煤和碎裂煤为主,光亮煤和半亮煤发育,平面上主要发育在研究区东部和中部;Ⅲ类较差煤岩主要发育在研究区西部.该评价方法不仅可应用于煤层气优质储量和可采性评估,还可以用于指导煤层气井位部署、射孔选层以及排采制度制定等.

In recent years, with the government’s continuous attention to coalbed methane (CBM) exploration and development and the scholars’ extensive research on CBM, China CBM industry has achieved rapid development. It has grown from an annual production of 0.3 billion cubic meters in 2005 to 4.96 billion cubic meters in 2017, forming two important CBM production bases in the Qinshui Basin and the eastern margin of the Ordos Basin. However, the rapid increase in annual CBM production mainly depended on the increase in the number of producing wells because of the low average gas production of CBM wells. There are many reasons to explain why the single well production is so low, but the principal one is that geological conditions of coal reservoirs are complex, such as low permeability, under-pressure, strong plasticity and so on. Besides, there is another important and crucial factor, affecting the production performance, that the exploitation technology is relatively simple and unsuitable for those geological conditions. This study takes the SY block located in the north of the Qinshui Basin as an example to analyze the production performance and technical advantages of a multi-lateral horizontal well as well as the production performance of the adjacent vertical wells. The results show that, for low permeability coal reservoirs, multi-lateral horizontal wells have great reservoir contact area compared with vertical wells with hydro-fracturing, which is beneficial to the rapid drainage and depressurization of coal reservoirs, causing the peak shifting forward and enhancing economic returns. The horizontal section, extending from the low part of the structure to the high, is conducive to change the gas-water flow characteristics with the gas-water gravity differentiation effect so that water flows to the lower part by gravity effect and gas flows to the high part by buoyancy effect, avoiding the presence of massive gas-water two-phase flow and Jamin effect to consuming reservoir energy, which is particularly advantageous for the development of under-pressured reservoirs. The special wellbore trajectory facilitates on-site workover and drainage management to ensure the continuity and stability of coal reservoir drainage. It is obvious that multi-branch horizontal wells have better technical advantages in developing low-permeability, under-pressure CBM reservoirs, which is the typical ones in China, than vertical well fracturing wells do.

近20年来,我国煤层气产业稳步实现商业开发,但产业发展瓶颈日益凸显:低效井占比大、达产率低,储产量规模与我国预期的规划目标存在较大差距.为查明煤层气井产能影响因素,研究了相适应的地质选区评价、工程工艺措施及排采管控技术.围绕沁水盆地南部水平井大规模投产实践,在分析地质特征和气井生产动态的基础上,重点结合构造、工程因素与排采管理,探讨了影响该区煤层气水平井产能的主控因素,并针对性地提出了提高水平井产能的对策建议,以期实现煤层气水平井规模化高效开发.研究表明:受气水重力分异影响,处于构造高部位的水平井见气早、上产快,效果明显优于低部位水平井;处于低部位的上翘性水平井见气晚、产水较大、上产慢;受渗透性非均质性影响,区内水平段有效长度与峰值产量相关性较弱,但侧钻易沟通邻近水层并导致局部井眼应力集中,造成气井产水大、煤粉多等问题;排采连续性与产气存在密切关系,停排时间长、次数多引起储层压力频繁扰动,破坏储层降压持续性,进而影响产气恢复速率及整体效果;此外,排采早期降压速率过大易引起压敏和速敏效应,伤害煤储层渗透率,进而影响气藏压降漏斗扩展及整体降压范围,最终影响气水产出效果.因此,建议优化水平井井位,加大低部位水平井的排采强度;定期环空注水稀释井底煤粉,降低停泵检修频次,提高排采连续性,将排采早期压降速率合理控制在0.02 MPa/d内.

为了探讨高阶煤吸附性的影响因素,以柿庄地区山西组3#煤为研究对象,采用灰色关联分析方法定量评价了煤储层不同性质与其吸附能力的相关性.结果 表明,在温压条件和吸附质相同的条件下,高煤阶煤的固定碳、镜质组与Langmuir体积呈正相关关系,煤的变质程度、孔隙度与Langmuir体积显示出阶段性的变化规律,而挥发分、灰分、水分、惰质组、无机组分与Langmuir体积呈现负相关关系.其中,固定碳对高煤阶煤的吸附能力的正效应最为显著,次为镜质组;挥发分对煤的吸附能力的负效应最为明显,次为灰分、水分和惰质组.

为定量评价煤储层渗透率,从煤层气井压降规律出发,以压降传播到边界为界限,将煤层气井排水降压段的压降规律分为两个阶段,且压力传播到边界之后的阶段为拟稳定流阶段.在此基础上,基于渗流力学理论和物质平衡原理,结合拟稳定流时地层各点压降速度相等,推导得到基于平均地层压力、井底流压、产水量等数据计算煤层渗透率的计算方法,并对该方法的优点及适用性进行论述,形成计算流程.以A区块为例,采用煤层渗透率拟稳定评价方法对A区块7口井进行煤储层渗透率计算,与稳定流法计算结果进行对比可知,拟稳定评价方法的稳定性及合理性明显优于稳定流法;并形成了A区块渗透率平面分布规律,与该区块排采井产气量变化趋势一致;即高渗区高产、低渗区低产,进一步论证了拟稳定评价法计算煤储层渗透率的可靠性.

A systematic study into the origin and potential formation processes of condensates in the Pinghu Slope Belt of the Xihu Depression, East China Sea Basin, was conducted using fluid inclusion analysis, petroleum geochemistry, and rock gold-tube pyrolysis. Grains containing Oil Inclusions (GOI (TM)) technique, well logging, and formation testing together indicate that the present-day gas condensate layer has evolved from a paleo-oil layer. Biomarkers from oil inclusions indicate that these paleo-oils were generated from coal measures at a moderate maturity level. Based on organic macerals, elemental ratios of kerogens, Rock-Eval pyrolysis, and results from gold-tube pyrolysis experiments, the coal measures are evaluated as source rocks prone to gas generation and capable of oil formation at moderate levels of maturity. This maturity level coincides with present-day condensate maturities determined from a series of molecular maturity ratios (vitrinite reflectance similar to 0.7-1.0% R-o). Biomarkers related to specific sources suggest that the condensates are also coal-derived. These observations suggest that the condensates are derived from secondary alteration following paleo-oil accumulation, rather than being related to the thermal degradation of resin-rich organic matter at a low maturity level, or the thermal cracking of kerogen at a high maturity level. Some condensates are characterized by a significant loss of n-alkanes with low carbon numbers and relatively high toluene/n-heptane (Tol/nC(7)) ratios. This indicates that the paleo-oil reservoirs have been subjected to varying degrees of gas washing, which resulted in condensate formation, as opposed to the process of oil cracking under high temperatures. Subsequent interactions between gas and paleo-oils resulted in oil inclusions showing fluorescence varying from near-yellow to blue. Variable vapor volume fractions measured in the same oil assemblage are the result of two-phase trapping of oil and gas. The widely observed presence of bitumen (asphaltene) in the reservoir pores and bitumen-bearing oil inclusions is considered to be due to gas deasphalting. Homogenization temperatures (Th) of associated aqueous inclusions and burial-thermal curves suggest that the initial paleo-oil reservoirs formed in the late Miocene. Excess gas, composed of local mature gas and heterochthonous high-to over-mature gas, migrated into the paleo-oil reservoirs later, in the Quaternary. This process not only resulted in the formation of condensates, but also led to vertical differentiation of density and wax content in the reservoirs.

进行二氧化碳地质封存或用于驱油实现部分封存,是减少温室气体排放的有效手段之一.为了对油气处理厂产生的高浓度二氧化碳气源进行封存,对附近海域封存构造、海上驱油油田的适宜性进行分析,选择确定了目标封存地和日标油气田,并对其封存方案、驱油方案进行了研究,对方案的经济性进行了分析.

The Xihu Depression in the East China Sea Basin is one of the prime gas and light oil-producing regions of eastern China. Overpressure evolution and origin in the sandstone reservoirs of the Pinghu (E(2)p) Formation in the Pinghu slope belt of the Xihu Depression were investigated through a combination of fluid inclusion analyses and basin numerical modeling, combined with measured pore pressures (drill stem and wireline formation tests), well loggings, gas geochemistry, and casting thin section data. Four oil inclusion types, exhibiting different API gravities and hydrocarbon gas inclusions, were identified, using inclusion petrography, microscopic fluorescence, and Raman spectra. Homogenization and ice melting temperatures of coeval aqueous inclusions, determined using microtherrnometry, combined with burial-thermal histories determined by basin numerical modeling, suggested multiple episodes of oil and natural gas charge in the E(2)p reservoirs, from the Miocene to the present day. Pore pressure evolution history, reconstructed with fluid inclusion PVTx analysis, indicated that the Pinghu Formation experienced three phases: overpressure generation, followed by overpressure release, and then further overpressure generation. The first phase of weak overpressure was generated during burial in the middle-late Miocene. Currently, it is hard to definitely determine the origin of the first phase of overpressuring. Nevertheless, it can be speculated that the origin may be related to disequilibrium compaction, oil generation and tectonic compression based on burial, tectonic and hydrocarbon generation histories. Following this, a sudden uplift of formations led to overpressure release in the late Miocene, and then, the second phase of moderate overpressure generation occurred during burial in the late Pliocene and Quaternary. Based on well-log signatures, vitrinite reflectance data of mudstones and gas geochemistry, combining with seismic analysis, the second phase of overpressuring was interpreted to have been mainly caused by fluid expansion, which resulted from local gas generation by kerogen maturation and long-distance vertical and lateral pressure transfer.

为分析A煤层气区块地应力剖面与平面分布特征,基于测井信息,建立了A区块地应力预测模型.依据地应力与渗透率之间的相关性,研究了渗透率的平面差异性.结果表明,A区块中部,3号煤层埋深适中,最小水平主应力在12 MPa以下,煤储层地应力状态主要表现为σv＞σH＞σh(垂直主应力＞最大水平主应力＞最小水平主应力);埋深处于740～1 100 m时,最小水平主应力为12～22 MPa,煤储层地应力状态表现为σH≥σv.在侧压系数小于1.0的区域,煤层埋藏较浅,垂直主应力占主导地位,平均产气量在500 m3/d以上的井位占比为64.2％.渗透率随最小水平主应力的增加呈指数降低的趋势,区块中部煤层渗透率最高可达0.2× 10-3 μm2以上,平均产气量相对较高.

Apart from conventional gas in the middle-shallow formation in the Xihu depression in the East China Sea Basin, low permeability gas sandstone layers in the middle-deep formation have recently been discovered. On the basis of integrated analysis of reservoir petrology and diagenesis, geochemistry of gas and source rocks, basin numerical modeling, gold-tube pyrolysis experiment of rocks and fluid inclusion, a comprehensive investigation of the characteristics of low-permeability reservoirs, gas origin, generation and charge in the sub-structural belts (West Slope Belt and West Sub Sag) has been performed. Strong mechanical compaction, filar authigenic illite, siliceous and carbonate cements are key factors for the formation of low permeability reservoirs. The comprehensive analysis of molecular components, stable carbon isotope compositions of gases and light hydrocarbons indicated that the low permeability gases in the WSB are mainly coal-derived and can be divided into two types: (1) mature gases sourced from local coal-measure rocks in the Pinghu Formation, (2) exogenous highly mature gases sourced from the coal-measure rocks in the Pinghu Formation in the WSS. Mature gases were injected into the low permeability reservoirs in the middle-lower Pinghu Formation at approximately 2.8Ma∼0Ma. In the meantime, partial highly mature gases generated from source rocks in the WSS also migrated to the WSB. On the whole, the gas charge in the WSB is characterized by dual-sourcing and late-stage. The low permeability gases in the WSS almost are highly mature and composed of most coal-derived gases generated from local coal-measure rocks in the Pinghu Formation and a small amount of oil-derived gases generated from local dark mudstones containing sapropelic-type organic matters in the Pinghu Formation. In addition, mature coal-derived gases generated from source rocks in the lower Huagang Formation are also present but very limited. The charge of highly mature gases in the low permeability reservoirs in the lower Huagang Formation in the WSS occurred at approximately 3.9Ma∼0Ma.