In situ-generated acid is commonly employed in ultra-deep, high-temperature carbonate reservoirs during acid fracturing to increase the effective acid penetration distance. However, the variation pattern of acid-etched fracture conductivity with in situ-generated acid has not been systematically studied. This paper investigates the evolution of the conductivity of primary and secondary fractures through a series of experiments involving in situ acid displacement and acid-etched fracture conductivity measurement. Based on the experimental results, a calculation model for the conductivity of acid-etched fractures with in situ-generated acid was established. The study indicates that after acid etching, rough particulate points and grooved dissolution patterns form on the surfaces of primary and secondary fractures, respectively. The dissolution volume in primary fractures is greater than that in secondary fractures, with both showing a linear increase over time. Due to the presence of dissolution grooves on the surfaces of secondary fractures, their conductivity is higher than that of primary fractures under the same acid–rock contact time. The conductivity of both primary and secondary fractures increases with the acid–rock contact time. However, beyond approximately 70 min of contact time, the conductivity of primary fractures shows no significant increase. The conductivity of primary and secondary fractures with in situ-generated acid is slightly lower than that with gelled acid under the same contact time, but significantly higher than that with crosslinked acid. This study provides guidance for the design and parameter optimization of acid fracturing in ultra-deep, high-temperature carbonate reservoirs.

Forming a fracture network through fracturing stimulation is significant to efficiently developing shale oil resources. However, the complex lithological characteristics and dense laminas of continental shale oil strongly shield fracture propagation. The concept of "cyclic fluid injection induces rock fatigue" was introduced into shale oil fracturing technology, and the cyclic pressure shock fracturing method was designed. The horizontal well fracturing simulation experiments used prepared shale rock samples from the Permian Lucaogou Formation shale oil reservoir outcrop in Jimusar Sag, Junggar Basin. Two pressurization states were obtained through constant injection and rapid release of accumulated high pressure, corresponding to conventional and pressure shock conditions. The characteristics of fracture propagation under different fracturing methods were analyzed by combining acoustic emission monitoring and injection pressure curve response. Research has found that the dense laminas with a certain original width near the wellbore significantly inhibit the vertical propagation of hydraulic fractures (HFs), and conventional constant-rate fracturing methods make it difficult to stimulate the reservoir effectively. Fatigue fracturing can increase the complexity of near-wellbore fractures, but the HFs still tend to be arrested by the laminas. The bottom hole pressure (BHP) is artificially increased to a value far exceeding the rock breakdown pressure near the wellbore by applying the cyclic pressure shock fracturing method. It can avoid the communication between micro-cracks and horizontal laminas during the BHP constant rate increase process and overcome the inhibition of weak layers on vertical propagation. Besides, the fracture height and number of activated laminas positively correlate with the number of cycles. When the shock pressure is about 30 MPa, the fracture height of the three cycles increases by 50

层理发育是页岩储层的典型特征,水力裂缝能否穿过层理面继续扩展决定了裂缝形态的复杂程度,其中层理强度是影响水力裂缝穿层行为的关键因素.为了探究层理强度对水力裂缝穿层行为的影响,采用块体离散元方法,分别计算了层理面的抗剪强度(黏聚力)和抗拉强度对水力裂缝在层状地层内扩展行为的影响.结果表明,水力裂缝遇到水平层理后的形态可分为转向层理面扩展和继续竖向扩展两种类型.层理面强度对水力裂缝的穿层能力具有显著影响,当层理面的抗拉强度和抗剪强度均较低时,水力裂缝的穿层能力差,水力裂缝不能穿过层理;当层理面的抗拉强度和抗剪强度均较高时,水力裂缝的穿层能力增强,水力裂缝穿过层理面扩展;当层理面的某一个强度较低时(抗拉或抗剪),则低强度因素成为主控因素,另一强度参数的增加不会改变水力裂缝的穿层能力.厘清了层理强度对水力裂缝穿层行为的影响,对层理发育地层的水力压裂施工具有重要的理论指导意义.

为研究吉木萨尔页岩油藏人工裂缝导流能力动态变化规律,基于新疆吉木萨尔页岩油藏储层条件,采用钢板、岩板和粒径相同的陶粒和钢砂,开展不同闭合压力裂缝导流能力实验.结果表明:随着闭合压力增加,裂缝导流能力逐渐降低,导流可分为3个阶段.第一阶段,闭合压力小于20 MPa,支撑剂被压实;第二阶段,闭合压力为20～60 MPa,支撑剂随着闭合压力增加嵌入岩板深度增加;第三阶段,闭合压力为30～60 MPa,支撑剂随着闭合压力增加破碎率逐渐增大.裂缝导流能力降低的因素主要有3个:支撑剂被压实、支撑剂嵌入岩板和支撑剂破碎,影响程度及大小为压实(72.03％)＞嵌入(14.28％)＞破碎(8.64％).

CO2前置蓄能压裂焖井期间,CO2持续与储层岩石发生作用.为探索CO2对吉木萨尔页岩作用效果及变化规律,明确提高采收率机理,分别对浸泡前后的吉木萨尔页岩进行渗透率测试实验、X射线衍射实验和扫描电镜实验,在分析渗透率宏观变化规律的基础上,对矿物组成、微观表面形态和孔喉结构变化规律进行解释.实验结果表明:使用CO2水溶液对吉木萨尔页岩长期浸泡后,其渗透率增大,浸泡7天增大约65％,浸泡14天增大约1.4倍;CO2水溶液对碳酸盐岩矿物有明显的溶蚀作用,在地层条件下使用CO2水溶液对岩样碎块浸泡5天后,碳酸盐岩溶蚀率可达到45.2％;从微观表面溶蚀情况来看,经CO2水溶液浸泡后,原有孔隙被溶蚀扩大或出现新的孔隙,从而提高了渗透率.现场试验结果表明,通过增加裂缝复杂度、增加焖井时间和使用"CO2+水基压裂液"复合压裂的方法对增强碳酸盐岩矿物溶蚀及提高地层渗透率有显著影响.

中国页岩油资源丰富,实现页岩油高效开采的关键技术之一是水平井体积压裂.页岩油储层可压性的精准评价是避免盲目压裂、保证高效压裂效果的基础.页岩油储层具有明显的隔层特征,压裂缝的扩展过程受到隔层效应的影响,而现有可压性研究未考虑隔层效应的影响,因此对页岩油储层的适用性有限.为此,文中结合室内实验、数值模拟、图像处理及数理分析等手段,分析了隔层效应对储层可压性的影响,建立了页岩油储层可压性评价方法.研究结果显示:隔层效应不改变储层可压性的影响机制,高脆性、低抗张强度储层具有更好的可压性;隔层的存在对储层可压性具有抑制效应,随着隔层的强度增大、弹性增强、层间应力差变大,隔层的抑制效应更显著.此外,在高地应力、高地应力差条件下,储层可压性降低.综合储、隔层的地质力学特征,构建了页岩油储层可压性指数,并验证了该指数的适用性.研究成果可为水平井压裂分段分簇设计提供理论支撑.

针对吉木萨尔油页岩缝网压裂裂缝形态认识不清的问题,从页岩储层改造特征出发,结合弱面强度理论,研究吉木萨尔页岩储层水力压裂缝网形成机理,定量化改进水力裂缝与天然裂缝、层理面相交作用准则,分析缝网扩展延伸规律,确定体积改造的工程可控参数.研究表明,排量为12 m3/min、净液量为2596 m3、砂比为0.1～0.2可有效增大体积压裂裂缝改造效果,增大泄油面积.该研究为吉木萨尔页岩体积改造设计提供了理论依据和参数指导.

准噶尔盆地玛湖凹陷北斜坡三叠系百口泉组储层物性差,主力油层百二段厚度一般大于30m,油气显示及主要富集部位位于储层上部.由于纵向上无高应力遮挡层,常规水力压裂易导致裂缝高度向下部延伸,裂缝高度不易控制,加之支撑剂沉降,常导致顶部油气富集段支撑剂铺置效果差,压裂效果不理想.在对国内外控缝高压裂技术调研基础上,确立了适用于百口泉组的控缝高压裂技术优化条件.现场实验和回归分析方法研究表明,泥质隔层、压裂液粘度、二次加砂工艺、压裂参数对压裂缝高具有较好的控制作用,通过优化可降低支撑缝高10%~20%.该技术在百口泉组取得了较好的现场应用效果.

In Mahu depression of Baikouquan formation with low porosity and low permeability reservoir thickness,oil and gas shows at the top.There are lithology and stress shielding layer in the underpart of the reservoir,and the fracture tends to extend downward in the fracturing,the proppant is easy deposits in the lower part of the reservoir.In recent years,for the effective use of thick reservoirs,the technology of secondary sand fracturing and soluble fiber suspension and combination of bottom laying sand control is carried out.Through the continuous improvement of reservoir reconstruction technology,the effective use of high quality reservoirs has been realized.It shows that the bottom sand laying technology of combined process and soluble fiber suspension sand technology is better than that of the secondary sand fracturing.D13 well adopts combination technology to control bottom sand laying technology,the highest daily production oil is 40.55 cubic meters per day,Nissan gas is 3070m3,that productivity test is 165 days,accumulated oil production 2083.11m3.It has realized the effective transformation of reservoir.

为准确识别储层类型，针对准噶尔盆地西北缘三叠系储层的特点，提出了一种结合人工神经网络专家和模糊聚类分析的综合识别储层方法。该方法先用10个专家（用BP神经网络获取的知识）进行识别，如果有一半或者一半以上的专家识别结果一致，则得到识别结果，否则采用模糊聚类分析模型进行识别。对西北缘三叠系的17个层进行识别，符合率为76.47%。

准噶尔盆地环玛湖凹陷西斜坡三叠系百口泉组砂砾岩储层厚度大,具有低孔、低渗特征,油层居于储层上部,局部存在水层,储层压裂改造难点是控制人工裂缝向下延伸以及支撑剂的合理铺置.所谓二次加砂技术,是在压裂过程中,完成第一级加砂后停泵,待裂缝闭合,进行第二级加砂,每级加砂都是相对独立完整的泵注过程,该技术具有下列优点:控制裂缝高度向下延伸,具有控缝高作用,二次加砂压裂后的裂缝长度大于一次加砂(同等加砂规模下);支撑剂向上充填,正好充填在油层位置,有利于油气生产;压裂缝具有支撑裂缝宽度大,填砂浓度高,导流能力强等优点,满足低渗透油藏对裂缝导流能力的要求.在二次加砂技术基础上,针对不同的储层类型,开发出三种组合压裂工艺,分别为二次加砂+分层压裂组合工艺、二次加砂+前置滑溜水组合工艺、二次加砂+控缝高组合工艺.经过多井次试验,三种工艺均获得理想压裂效果.实践证明,二次加砂及其组合技术在玛湖凹陷储层具有很好的适应性.

<正>2012年10月12日,新疆油田公司工程技术研究院与井下作业公司联合对油田公司克拉玛依油田八530井区T87566井实施了压裂措施,整个施工过程历经1个多小时,压裂施工顺利完成。T87566井于2008年12月9日完钻,完钻井深3009.0m。钻探目的是落实八530井区白碱滩组油藏的储层展布、含油边界及油藏规模。

杜229块经过多年的蒸汽吞吐,目前已进入快速递减阶段,各种矛盾日益突出.区块油井采出程度高,日产油水平低、油汽比低、单位操作成本高.递减速度快,下步接替方式不明朗.从产量递减模型看月递减率2.14%,年采油速度最高4.04%,区块目前仍处于快速递减阶段,年综合递减率20%以上,针对油田的开发现状和目前面临的各种矛盾,必须开展本区开采特征分析,对油藏进行精细化管理.

In order to provide guidance for the next development and remaining oil recovery, using the method of reservoir engineering, development efficiency of studied area has been evaluated in this paper from following aspects of energy changes, water flooding effect, production decline, rationality of well network, final recovery efficiency etc. The reservoirs in the lower member of Es3 in Bijia, Binnan Oilfield, are typical complex-faulted ones with complicated geological conditions, developed faults and strong heterogeneity. And the development of those reservoirs has already entered into a medium -high water cut stage for strong heterogeneity in both vertical and planar directions, which results in stronger interlayer heterogeneity, severe water flooding and also accelerates the decline of production, and finally, development efficiency becomes poor obviously.