This study addresses the challenges in understanding production patterns during well shut-in and reopening in tight sandstone gas reservoirs caused by complex pore structures and high water saturation, aiming to elucidate seepage mechanisms during well operations, identify key influencing factors, and establish theoretical guidance for field well selection and intervention timing during production adjustment. By analyzing field data quantifying gas and water production variations before and after shut-in periods unaffected by external interventions, we identified two critical parameters—shut-in duration and water production levels—and classified four distinct shut-in types. Integrated core experimental data revealed the influence mechanisms of afterflow effects, imbibition phenomena, and pressure-sensitive effects of relative permeability curves during well operations. A productivity model was developed to qualitatively analyze parameter variations based on flow mechanisms. Research demonstrates that Early-stage gas production variations during reopening reflect the macroscopic manifestation of competing mechanisms: permeability reduction (negative effect) from imbibition in near-wellbore small pore throats versus production enhancement (positive effect) from pressure buildup. Late-phase production changes predominantly manifest macroscopic alterations in gas phase flow capacity caused by pressure-sensitive characteristics of relative permeability curves. Shut-in operations should prioritize low-water production periods regardless of causes, as prolonged shut-ins during high-water production stages significantly impair productivity, while short-term closures exhibit minimal impact. These findings provide critical guidance for optimizing well selection and operational timing during production adjustment, effectively mitigating unnecessary production losses from field operations or output optimization.

Tight gas reservoirs generally produce water, which significantly impacts gas reservoir productivity. The influence of water on gas flow capacity is usually represented by relative permeability curves. In this paper, differences in relative permeability curves under various displacement pressures are analyzed through laboratory experiments, and the influence of gas reservoir pressure on the variation of relative permeability curves and productivity is discussed. Firstly, the steady-state method is adopted to test the gas–water relative permeability curves under different displacement pressure differences. Based on the analysis of the variation pattern of relative permeability curves and the microscopic flowing mechanism, the mechanism of water phase interference is further obtained. Secondly, a productivity model for fractured vertical wells considering changes in relative permeability curves is established to explore the impact of water phase interference on gas well productivity. The study finds that as the displacement pressure difference increases, the saturation of irreducible water and residual gas decreases, while the curvature of the relative permeability curve increases. The mechanism of water phase interference is that changes in the displacement pressure difference lead to variations in the flowable space and movable water saturation, which in turn cause corresponding changes in the effective permeability and relative permeability of the gas phase. In terms of gas well productivity, a threshold of production pressure difference exists. Beyond this value, the negative impact of water phase flow becomes more significant than the positive effect of increasing pressure difference, resulting in a decreased productivity as the production pressure difference increases. Consequently, a “turnaround” phenomenon appears at the end of the IPR curve. Moreover, different reservoirs vary in the severity and ease of water phase interference. The mechanistic study can guide the development of tight gas reservoirs and reduce the influence of the water phase.

ObjectiveGeothermal fields serve as a crucial geological condition controlling the phases and seepage of deep coalbed methane (CBM). Investigating geothermal fields facilitates the assessment and efficient development of deep CBM resources.MethodsThis study explored the Nos. 8 and 9 coal seams in the Linxing-Shenfu block using data from drilling, well logging, well tests, and experiments. Specifically, this study summarized the regional distribution patterns of geothermal fields in deep coal reservoirs in the block, analyzed the impacts of the geothermal fields on the gas-bearing and physical properties of the reservoirs, and revealed the controlling factors and mechanisms of the geothermal fields. Furthermore, it proposed differential control modes of regional geothermal fields in the block.Results and ConclusionsThe results indicate that coal seams in the study area have a present-day average temperature of about 52 ℃ and geothermal gradients ranging from 1.72 ℃/hm to 2.64 ℃/hm (average: 2.21 ℃/hm), suggesting slightly low to normal geothermal gradients. The geothermal fields in the study area are negatively correlated with the adsorption capacity and mechanical properties of coal seams but are weakly positively correlated with their permeability. Specifically, higher geothermal gradients and reservoir temperatures correspond to lower critical depths of gas content in coal seams, a higher amount of adsorbed gas converted to free gas, and improved reservoir permeability. In contrast, higher geothermal gradients are associated with lower peak strength, smaller modulus of elasticity, and enhanced plasticity of coals. The geothermal fields in the study area are influenced by multiple factors, including burial depth, structures, groundwater, and the thermal conductivity of rocks. The small differences in the lateral thermal conductivity of strata result in the lateral heat transfer, followed by heat accumulation in uplift zones. As a result, high-temperature geothermal fields are formed. In contrast, faults destroy strata or connect groundwater, leading to thermal diffusion. Consequently, lower-temperature geothermal fields are formed. Four temperature control modes of geothermal fields in the study area are identified: (1) The universal mode with temperature controlled by horizontal strata, characterized by normal geothermal gradients but reservoir temperatures varying with the burial depth. (2) The mode with temperature primarily governed by lateral heat transfer, occurring in Zijinshan basement uplift. (3) The mode with temperature primarily influenced by faults, observed in the northern Linxing and western Shenfu blocks. (4) The composite mode with temperature dominated by both faults and groundwater, occurring in the eastern Shenfu block. This study reveals the distribution patterns of geothermal fields in the study area and their impacts on the physical properties of deep coal reservoirs. Under similar geological conditions, structurally higher parts with high-temperature geothermal fields are more enriched in free gas. Therefore, it is recommended that these parts serve as significant zones for resource assessment to promote the high production of deep CBM.

Hydraulic fracturing is a necessary measurement to realize the commercial exploitation of oil and gas, but its application in multilayered thin tight sandstone gas reservoirs is still not perfect, which usually have thin gas layers mixed with complex intervals, and shows a dramatic variation in geological and geomechanical properties in the vertical direction. When conventional hydraulic fracturing methods are applied to this kind of reservoir, it is hard to get proper fracture propagation, especially for fracture height control. Facing this situation, this paper proposes a numerical study of the hydraulic fracturing mechanism and analyzes its influencing factors in the multilayered thin tight sandstone gas reservoir. Relying on a real reservoir in the Ordos Basin in China, relevant geological and geomechanical parameters of major gas layers and interlayers are obtained. According to these parameters, the hydraulic fracturing simulation in the multilayered thin tight gas reservoir model is carried out, based on which, the sensitivity analysis of different geological and fracturing parameters which affect the fracture propagation is performed. Furthermore, a real low-production well after fracturing in this kind of reservoir is selected as an example, and based on the analysis, an optimized fracturing scheme is proposed to adapt to the characteristics of the reservoir. According to the comparison of fracturing and production simulations, the optimized fracturing scheme can prevent hydraulic fractures from breaking through thin interlayers, control the fracture height, and prevent fractures from communicating strata with a high water-bearing layer. At the same time, with the same amount of proppant and fracturing fluid, longer fracture length and better fracture conductivity are created, so that the productivity of the optimized fracture has been greatly improved.

In the production process of tight gas wells, reservoir fluid distribution and gas-water relative permeability vary with time. However, traditional models fail to handle the time-dependent mechanism and stress sensitivity effect in the reservoir, leading to significant errors in the dynamic analysis results. To address this issue, this article presents a prediction model for fractured well production in tight gas reservoirs. It is based on a three-dimensional embedded discrete fracture model (EDFM), which considers the influences of the time-dependent mechanism and stress-dependent reservoir permeability. Transient flow equations are treated by using the finite volume method to obtain the solution of the model. The accuracy and reliability of the model are verified by comparison with the results of the commercial simulator Eclipse and the field application. Based on the model's solution, this study emphasizes the analysis of the impact of the time-dependent mechanism and reservoir stress sensitivity on gas well productivity. Simulation results show that the time-dependent relative permeability curve can decrease the level of irreducible water saturation and promote the migration of irreducible water, resulting in an increase in water permeability and a decrease in gas permeability. This effect will reduce the period of stable gas production and increase the level of water production. Besides, reservoir stress sensitivity will reduce daily water production and accelerate gas well decline. It is necessary to control the production pressure difference reasonably during the production process to effectively reduce the negative impact of stress sensitivity effects. The results indicate that when the relative permeability curve and the reservoir permeability are constant, the real gas production capacity of the reservoir will be strengthened. The application of field case studies shows that the theoretical model exhibits stronger adaptability, achieves better fitting results, and can guide the compilation and adjustment of development plans for water-bearing tight gas reservoirs. These findings provide insights into understanding the effects of the time-dependent mechanism on gas production rates in tight gas reservoirs. Furthermore, this study offers useful guidance for the prediction of field-scale gas production.

由于致密气井试气时间短，现场常用的“一点法”测试实则是一种不稳定“一点法”,计算无阻流量较真实无阻流量要高。运用“一点法”公式和瞬态二项式产能方程对不稳定“一点法”误差进行分析，结果表明：测试时间对无阻流量具有较大影响，且渗透率越小，影响越大；经验系数和测试生产压差对无阻流量也具有一定影响，但当经验系数大于6,无因次压力大于0.8时，影响在4%以内，可忽略不计。经综合分析，神府区块“一点法”测试经验系数和测试生产压差对其计算无阻流量影响不大，测试时间过短造成无阻流量偏高20%左右。神府区块20口典型井应用表明：不稳定“一点法”测试误差平均为18.72%,评价真实无阻流量平均为2.76×10~4m~3/d。基于此，提出了不稳定“一点法”产能评价推荐做法，包括测试时间、工作制度和经验系数的确定方法，进一步规范了现场“一点法”测试工艺，指导致密气产能认识和合理配产。

A novel colloidal dispersion gel (CDG) was synthesized by cross-linking polysaccharide-based hyperbranched polymer (SMHBP) with aluminum citrate. Four factors affecting gelation properties were investigated including SMHBP concentration, the weight ratio of polymer to cross-linker, NaCl concentration, and additive concentration. Environmental scanning electron microscope (ESEM) was used to observe the morphologies of the CDG to understand the cross-linked mechanism. The CDG is cross-linked by both intramolecular and intermolecular, and the formation of the CDG is dominated by the intramolecular crosslinking reaction. Core displacement experiments demonstrated that the novel CDG obtained excellent profile modification performances at a high temperature and high salinity.

致密砂岩气藏在开发过程中普遍存在产水现象,容易造成井筒积液、产量快速递减甚至停产等问题,认识致密砂岩地层水赋存规律,从而评价产水规律及其对产能的影响,是致密气规模化开发必须解决的关键问题.以中国海油鄂尔多斯盆地矿区盒八段致密储层为研究对象,选取典型岩心8块,每一块岩心均依次开展了孔渗分析、核磁共振实验、高压驱替实验和恒速压汞实验,从而揭示致密砂岩束缚水饱和度及与之一一对应的微观孔喉量化关系.实验结果表明,临兴矿区盒八段致密储层束缚水饱和度整体在40％～70％,且赋存在小于0.1μm的孔隙内以及较大孔隙的亲水表面上;束缚水饱和度随着喉道半径平均值、渗透率的增加而降低,具有较好的线性关系.本文所提出的方法为定量评价致密砂岩气藏的产水能力提供了基础依据和指导.

致密砂岩气井产能预测受气水两相流特征和裂缝渗流参数影响大,相比于数值模拟,基于解析模型的产能预测计算快、应用较广,但传统的解析模型在处理两相渗流方程非线性问题时简化过大,造成动态分析结果误差较大.针对这一问题,考虑了储层和裂缝中的气水两相流动特征,利用三线性流模型表征压裂缝及储层应力敏感性,建立了致密砂岩气井气水两相产能预测模型.将流动物质平衡方程与牛顿迭代法结合,利用平均地层压力逐步更新渗流模型非线性参数,并通过逐次迭代将气水两相模型线性化,获得了模型的半解析解.通过与商业数值模拟软件结果对比以及矿场实例应用验证了模型的准确性,并绘制了气水两相产能预测曲线,分析了敏感性参数对产能的影响规律.研究结果表明,所建立的半解析求解方法能够高效地处理气水两相非线性渗流问题,快速准确地获取致密气井产能预测曲线;致密储层产水严重影响了气井产能,合理的裂缝参数对提高气井产能至关重要;气藏开发过程中应合理控制生产压差,降低应力敏感效应对致密气井产能的影响.

针对层内水来源的产水气井动态储量评价,分析了现有动态储量评价方法在产水致密气井中的适应性,对比了不同水气比现有方法计算误差,在此基础上,建立了层内水来源的产水气井气水两相流流动物质平衡方程,形成了此类井动态储量求解流程,并运用理论模拟方法对新方法及流程进行验证.结果表明:层内水产出对气井储量评价特征曲线形态影响较小,但对储量计算结果具有一定影响;当水气比小于5 m3/104 m3,相对误差约5％,认为现有方法仍适用,但大于该值则不适用;新方法能有效减小误差,经验证,水气比11 m3/104 m3时误差在1.4％,能够满足工程应用的需要.所提方法应用于鄂尔多斯盆地东缘临兴区块,为该区产能准确认识、井距优化部署提供了新方法.

Shale oil and gas reservoirs are developed by MFHWs. After large-scale hydraulic fracturing, it is hard to forecast the production rate using the theoretical method. In the engineering application field, the empirical method of DCA is often used to forecast the production rate of shale oil and gas produced by MFHWs. However, there are some problems in using DCA, like how to find out the proper decline model and switch point of two contiguous flowing periods and how to deal with the unsteady operation condition which causes a lot of uncertainty in production forecast. In order to solve these problems, firstly, a straight line model, representing the linear flow period in the life cycle of shale oil and gas produced by MFHWs, in the Q,lg q coordinate system is proven to be theoretically proper. Secondly, the duration of the linear flow period is verified to be over 10~15 years by using an analytical model to do the calculation with the method of Monte Carlo random sampling taking a large amount of parameter combinations of Eagle Ford shale oil and gas reservoirs into calculation. And a field data analysis of Barnett and Eagle Ford also shows that the duration of linear flow period can be more than 10~15 years. Thus, a method of production forecast taking advantage of the straight line feature in the Q,lg q coordinate system is raised. After practical use, it is found that the method is robust and can increase the forecast efficiency and decrease the manual error. Moreover, it can increase the accuracy of production forecast and deal with some unsteady operation conditions. Therefore, this new method has good promotional value in the engineering field.

由于致密气、煤层气二者的赋存机理与开发方式存在着很大的不同,业界对于两气合采干扰及开发效果仍存在着较大的顾虑.为了充分认识致密气-煤层气(两气)合采存在的层间干扰问题及进一步探讨两气合采可行性,从两气合采层间干扰机理入手,分析了不同机理对合采层间干扰的影响,结合数值模拟方法总结了两气合采干扰控制因素.研究结果表明:①合采过程会出现层间水倒灌现象,但相对于整个开发过程持续时间短;②影响合采效果的关键因素是致密储层水锁效应强度,物性参数差异影响合采时各层产能贡献比例,但对最终合采效果的影响可忽略.基于此,提出了两气合采选层原则:①非产水致密层不宜与煤层合采;②物性参数差异性不作为合采选层的考虑因素;③产水致密层可与煤层合采,但需确定技术经济可采参数界限值.基于研究结果,创建了"六图版四象限"两气合采快速选层法,能够运用于现场两气合采层系快速优选.

Water breaks through along fractures is a major concern in tight sandstone reservoirs with a bottom aquifer. Analytical models fail to handle the three-dimensional two-phase flow problem for partially penetrating inclined fractures, so time-consuming numerical simulation are often used for this problem. This paper presents an efficient semianalytical model for this problem considering three-dimensional fractures and two-phase flow. In the model, the hydraulic fracture is handled discretely with a numerical discrete method. The three-dimensional volumetric source function in real space and superposition principle are employed to solve the model analytically for fluid flow in the reservoir. The transient flow equations for flow in three-dimensional inclined fractures are solved by the finite difference method numerically, in which two-phase flow and stress-dependent properties are considered. The eventual solution of the model and transient responses are obtained by coupling the model for flow in the reservoir and discrete fracture dynamically. The validation of the semianalytical model is demonstrated in comparison to the solution of the commercial reservoir simulator Eclipse. Based on the proposed model, the effects of some critical parameters on the characteristics of water and oil flow performances are analyzed. The results show that the fracture conductivity, fracture permeability modulus, inclination angle of fractures, aquifer size, perforation location, and wellbore pressure drop significantly affect production rate and water breakthrough time. Lower fracture conductivity and larger inclination angle can delay the water breakthrough time and enhance the production rate, but the increment tends to decline gradually. Furthermore, water breakthrough will occur earlier if the wellbore pressure drop and aquifer size are larger. Besides, the stress sensitivity and perforation location can delay the water breakthrough time.

Two-phase (gas+water) flow is quite common in tight sandstone gas reservoirs during flowback and early-time production periods. However, many analytical models are restricted to single-phase flow problems and three-dimensional fracture characteristics are seldom considered. Numerical simulations are good choices for this problem, but it is time consuming in gridding and simulating. This paper presents a comprehensive hybrid model to characterize two-phase flow behaviour and predict the production performance of a fractured tight gas well with a three-dimensional discrete fracture. In this approach, the hydraulic fracture is discretized into several panels and the transient flow equation is solved by the finite difference method numerically. A three-dimensional volumetric source function and superposition principle are deployed to capture the flow behaviour in the reservoir analytically. The transient responses are obtained by coupling the flow in the reservoir and three-dimensional discrete fracture dynamically. The accuracy and practicability of the proposed model are validated by the numerical simulation result. The results indicate that the proposed model is highly efficient and precise in simulating the gas/water two-phase flow and evaluating the early-time production performance of fractured tight sandstone gas wells considering a three-dimensional discrete fracture. The results also show that the gas production rate will be overestimated without considering the two-phase flow in the hydraulic fracture. In addition, the influences of fracture permeability, fracture half-length, and matrix permeability on production performance are significant. The gas production rate will be higher with larger fracture permeability at the early production period, but the production curves will merge after fracturing fluid flows back. A larger fracture half-length and matrix permeability can enhance the gas production rate.

页岩超低渗、强非均质性以及复杂缝网特征使得解析模型法产量预测参数输入不确定性大,生产历史拟合多解性强,产量预测难度大.基于页岩气井生产长时间段呈线性流动的特点,开展线性流分析和解析模型产量预测工作,提出首先通过线性流分析解释确定解析模型参数初值和范围、再进行历史拟合和产量预测的思路和方法流程.研究表明:根据页岩气流动阶段诊断可以初选解析模型;运用流动物质平衡方法可确定动用储量和气藏尺寸;采用线性流不确定性分析可以确定渗透率和裂缝半长等参数范围.该方法可提高解析模型历史拟合和产量预测精度,同时提高了工作效率,经8口井应用测试结果表明:方法提高单井历史拟合速率40％以上,提高产量预测精度18.1％.

页岩油气产量受地质、工程等多重因素影响,常规产量预测方法难以反映其真实生产特征,因此引入了机器学习方法进行页岩油气产量预测.以美国Eagle Ford页岩某区块400余口生产井地质、油藏、工程数据为学习样本,对人工神经网络模型进行训练和优化,确定了最佳模型参数;结合交叉验证等手段改进了训练方法,提高计算效率和预测精度,得到了初始产量、递减率、递减指数等产量递减参数与地质、油藏、工程参数之间的关系模型,进而形成了基于静态参数的页岩油气单井产量预测技术.实例应用表明,投产5年内,本文模型产量预测精度可达90％.在没有生产数据或生产数据较少情况下,本文模型预测产量具有突出优势.

针对页岩油气产能影响因素具有参数多、关系复杂、难以量化评价的特点,利用因子分析、多元回归等方法,对某页岩区块数百口生产井的地质、油藏、工程等数据进行数据分析.研究从数据关联角度,将产能影响参数归纳为泄流范围、储层特征和改造强度等相互独立的三类,利用这三类参数可以对研究区特征进行详细刻画;同时研究中结合多元回归等方法,对产能的影响因素进行量化评价,确定了不同产区的产能主控因素.结果表明,在各方面条件均优的情况下,泄流范围对产能影响权重占40％,储层特征占40％,改造强度占20％.当储层含油气性好,物性好,储层能量足时,储层特征的影响程度会有所提高,反之,则泄流范围影响处于主导地位.改造强度影响程度则随着储层中人工裂缝密度和复杂程度的增加而提高.

为准确获取煤层气井物理性能参数,提出了一种简便的基于生产初期排水数据的产能分析新方法,首先,考虑煤层普遍具有的低渗特征,引入调查半径公式,计算各个时刻煤层气井压力波前缘位置,然后,基于连续稳态方法,推导各个时刻考虑应力敏感与压力波扩展的稳态渗流方程;最后,对渗流方程进行线性化处理,得到适用于低渗欠饱和煤层气井的产能分析新方法,该方法的可靠性与应用性通过与数值模拟以及现场实例对比进行研究.研究结果表明:新方法预测的渗透率与实际渗透率间的误差为2.38％,表皮因子的误差为6.59％,满足现场工程应用需求,新方法能够准确获取储层物性参数,为气井后期产能预测,生产制度调整提供有效理论依据.

本文从层间干扰机制出发,分析了倒灌现象、物性差异以及开发方式对层间压力干扰的影响,并运用数值模拟手段进行合采生产特征和控制因素分析,研究表明:合采时出现短时的水倒灌现象,对开发效果影响不大,但倒灌后形成的水锁效应强弱是影响合采的关键;渗透率等物性差异不影响合采效率,但渗透率、解吸压力、工作制度等是影响两气合采经济性的重要参数.

The complexity of fracture geometry for multi-stage fractured horizontal well increases the difficulty in predicting shale gas productivity.Based on the assumption that the fracture geometry includes main fractures and complex fracture network system, the tri-porosity linear flow model for shale gas multi-stage fractured horizontal well considering the main fractures is established.The Laplace space solution is obtained by dimensionless treatment and Laplace transformation, then the new type curves are drawn by programming calculation, which shows that both the main fractures and the fracture network contribute the fracture linear flow.Compared with the dual-porosity model, the tri-porosity model increases the main fractures system that not only determines the seepage flow pattern in shale reservoir, but also affects the production of shale gas well.Analysis of the effect of the main fracture system on the shale gas production shows that:Firstly, the fracture half-length xF affects each flow stage, the lager the xF is, the higher the production is, the sooner the flow reaches the boundary.Besides, the fracture width wF affects fracture linear flow stage and transitional flow stage, the larger the wF is, the higher the production is, but the fracture linear flow duration isconstant, and the duration of transitional flow is shortened.At last, the effect of xF on productionis greater than wF.The tri-porosity model can not only guide shale gas well fracturing operation, but also provide a productivity prediction and analysis method for multi-stage fractured horizontal well with main fractures, and improve the accuracy of production prediction.