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作者简介:

顾少华(1984—),男,河南南阳人,高级工程师,博士,从事气藏开发研究。E-mail:gush.syky@sinopec.com。

中图分类号:TE344

文献标识码:A

文章编号:1009-9603(2022)02-0117-07

DOI:10.13673/j.cnki.cn37-1359/te.2022.02.014

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目录contents

    摘要

    针对超深海相碳酸盐岩储层水侵特征复杂的特点,选取基质、含溶蚀孔、天然裂缝等不同类型介质岩心开展气水相对渗透率实验研究,搭建了高温高压(150 ℃,50 MPa)的气水相对渗透率测试实验装置,设计了实验流程及实验方案。当实验围压分别为10,30,50 MPa时,测得不同围压对应的气水两相相对渗透率并绘制曲线,分析气水两相相对渗透率曲线随围压的变化特征。研究结果表明:当围压增大时,气水相对渗透率曲线普遍向下移动,其中,天然裂缝岩心的气水相对渗透率下降幅度更为明显;气水相对渗透率等渗点向含水饱和度小的方向移动,相对渗透率曲线形态发生变化。不同介质的气水相对渗透率曲线两相同流区宽度也存在明显差异,其中,随围压升高,含溶蚀孔岩心的两相同流区宽度变化幅度最小。该实验结果可用于解释深层碳酸盐岩气田水侵特征及气井产水现象,为该类气藏水侵规律的确定提供依据。

    Abstract

    In view of the complex water invasion characteristics of ultra-deep marine carbonate reservoirs,cores with differ- ent types of medium,such as matrix,dissolved pores,and natural fractures are selected to carry out gas-water relative per- meability experiments. An experimental device with high temperature and high pressure(150 ℃ and 50 MPa)is built,and the experimental process and scheme are designed. The gas-water two-phase relative permeability is measured under dif- ferent confining pressures(10,30,and 50 MPa)to plot the relative permeability curves,and the variation characteristics of the curves with the confining pressure are analyzed. The results show that the gas-water relative permeability curves gener- ally move downward with the increase in the confining pressure,and the gas-water relative permeability of the natural frac- ture core decreases more obviously. The isotonic point of the gas-water relative permeability moves in the direction of low water saturation,and the shapes of the relative permeability curves change. Obvious differences are also observed in the width of the two-phase flow zones in the gas-water relative permeability curves of different media. With the increase in the confining pressure,the width of the two-phase flow zone of the core with dissolved pores undergoes the smallest change. The experimental results can be used to explain the water invasion characteristics of ultra-deep carbonate gas fields and the water production phenomenon of gas wells and provide a basis for determining the water invasion law of such gas reser- voirs.

  • 随着近年来深层海相碳酸盐岩气藏陆续投入开发,该类气藏在中国天然气产业中占据日趋重要的地位。深层海相碳酸盐岩气藏的开发普遍受水侵影响,目前已开发的该类气藏中 95% 以上存在边、底水,水侵强度为较强-极强的比例超过 75%[1-2]。深层海相碳酸盐岩气藏具有强非均质性,表现在两方面:第一,由于地层年代久远、埋藏深,储层经过固结成岩及多期矿物充填作用[3],基质孔隙度普遍较低,多小于 6%;第二,部分储层受构造作用影响,发育多期多次裂缝,且受溶蚀作用影响,还有部分储层发育溶洞[4]。因此可形成包括孔隙型、裂缝-孔隙型、裂缝-孔洞型以及裂缝型等多种类型储层,且在深部地层存在应力敏感性,开发过程中压力变化造成渗透性发生改变,导致气藏水侵特征更为复杂。在上述多重因素影响下,气井见水及产水规律难以预测,常出现水体非均匀突进以及气井暴性水淹等现象,严重影响气藏的高效稳定开发。开展相对渗透率实验,准确评价该类气藏的气-水两相流动特征,是实现气田高效开发的前提。

  • 现有的气水相对渗透率成果主要来自于研究低渗透致密砂岩气[5-11]、煤层气[12-14]、页岩气[15] 水力压裂以及油藏水气交注[16-18] 开发过程中的气水同流现象。但是低渗透致密砂岩气田、煤层气以及页岩气的水侵类型多以地层局限水体为主,不具备强边底水侵入特征,因此与碳酸盐岩气田存在较大差异。而水气交注的油藏为保压开采,地层压力变化不显著,难以体现出强应力敏感特征,因此对于海相碳酸盐岩气藏水侵特征研究参考性有限。针对上述问题,设计了高温高压气水相对渗透率测试实验装置,根据储层发育类型选取具有代表性的基质岩心、含溶蚀孔岩心、天然裂缝岩心等实验样品,改变围压以模拟深部地层应力敏感特征,测得不同围压下的气水两相渗流曲线,分析得到深层海相碳酸盐岩气藏气水两相渗流规律。

  • 1 实验设计

  • 1.1 实验装置

  • 常用的相对渗透率测试方法包括稳态法和非稳态法 2 种,虽然一般认为稳态法测试过程与实际驱替过程更为接近,但是其对实验条件要求极为苛刻,包括测试温度和压力不宜过高、两相流体性质应差异较小,岩心物性也应为中高渗透且较为均质,否则测试压力难以达到稳定,无法准确记录数据,且测试过程耗时费力。考虑超深海相碳酸盐岩地层具有高温、高压和应力敏感性的特点,优选非稳态法作为测试方法,并设计了高温高压气水相对渗透率测试实验装置,耐温、耐压界限分别为 150℃,50 MPa(图1)。装置主要组成部分包括:高压泵、中间容器、压力计、岩心夹持器、加湿器、回压阀、湿式流量计、恒温箱以及阀门等,其中核心部分是岩心夹持器,主要由岩心外筒、胶皮筒和轴向连接器组成。为模拟超深地层的高温环境,需要在恒温箱中进行驱替。为保证高温条件下的封闭性,选用耐热橡胶制成的胶皮筒,从而避免橡胶受热变形无法密封。为避免出现气体持续驱替而引起束缚水蒸发,导致测得的束缚水饱和度端点偏离实际值,在装氮气的中间容器出口处连接加湿器对泵入气体进行加湿。

  • 图1 高温高压气水相对渗透率测试实验装置

  • Fig.1 Gas-water relative permeability experiment device at high pressure and high temperature

  • 1.2 实验流程

  • 基于非稳态法相对渗透率测试实验装置,结合岩石中两相流体相对渗透率测定方法[19],设计了变围压高温高压气水相对渗透率测试实验流程。具体步骤包括:①选择恒压法进行测试,综合考虑岩心长度、孔隙度、渗透率以及测试流体性质等因素确定驱替压差,将 π1π2作为驱替压差的选取范围,驱替压差应大于π1且小于π2,其表达式分别为:

  • π1=0.00167σϕKg
    (1)
  • π2=0.002σLKg
    (2)
  • ②取出饱和水的岩样,用脱脂纱布将岩样表面上的液体擦拭后,立即用电子天平称量岩样的质量,并装入岩心夹持器中,使岩样的方向与气测渗透率方向保持一致。③升高恒温箱温度至 150℃,调节高压泵的阀门,增加岩心夹持器的围压,使其达到实验设计的目标围压;然后调节高压氮气瓶和压力倍增器,使岩心内的流体压力比围压低约8 MPa;最后调节回压阀,使驱替压差与步骤①确定的驱替压差保持一致。④记录湿式流量计和气水分离器显示的初始值,记录选择的入口压力和围压值,将气体流量计调零,电子计时器调零。⑤将气体增压泵接通至岩心夹持器入口处并泵入氮气,同时应用电子计时器开始计时。⑥准确记录见气点和见水点的累积时间,以及见气、见水后各个时刻所对应的累积时间、累积产气量和累积产水量。⑦当出水量明显减少,且经过 15 min后分离器中的累积产水量也不再继续增加时,切断上游的氮气,暂停电子计时器,打开回压阀放空岩心夹持器出口端的压力。⑧ 卸掉围压,取出岩样,用电子天平称量,精确到小数点后 4 位,并计算此时岩样的累积产水量和含水饱和度,其表达式分别为:

  • Wn=mw-mnρ
    (3)
  • Sw=mn-mdρVp×100%
    (4)
  • ⑨将岩心烘干,重新用水饱和岩样并将其装入夹持器,按步骤②—⑧重复开展实验,若2次相邻实验结果误差小于 2%,则表明数据具备可重复性,实验结果有效。否则应分析原因,并继续重复实验。

  • 2 实验样品及实验条件

  • 2.1 样品准备

  • 2.1.1 岩心样品选取

  • 选取川西雷口坡组气藏雷四段岩心样品开展气水两相流体实验。川西雷口坡组气藏中部深度约为6 100 m,主力产层雷四段沉积环境总体为局限台地-蒸发台地,目的层雷四段上亚段主要发育潮坪沉积,储层岩性以白云岩类为主,灰岩类次之,白云岩类以微-细晶为主,灰岩类以泥微晶为主[20-22]。该气藏储层类型多样,主要有白云石晶间溶孔、藻纹层(或层叠石)格架溶孔、藻黏结(或藻屑)粒间 (溶)孔、裂缝、溶洞、铸模孔等[23-28]。通过 5 口取心井 711 块样品资料的统计,雷四段储层孔隙度为 0.07%~23.7%,平均为 3.2%;渗透率为 0.000 73~710 mD,平均为 0.2 mD。气藏埋藏较深且发育边水,存在水侵风险。因此,需要针对该类超深复杂岩性储层开展气水两相渗流研究,以评价气藏水侵特征。

  • 该超深海相碳酸盐岩气藏高温高压(地层温度为 150℃,平均地层压力为 62.4 MPa),储层整体低渗透,具有强应力敏感性。局部发育裂缝和溶蚀孔隙,呈现出多重介质特征。应综合考虑气藏地质特点,选取可代表不同类型储层的岩心样品。因此从实钻岩心中选择基质岩心(l-151813)、含溶蚀孔岩心(1-154068)和天然裂缝岩心(1-152960)各 1 块 (图2)。

  • 2.1.2 岩心样品制备

  • 根据地层水分析结果复配实验用水,复配后需将实验用水过滤杂质,装入容器中备用。由于甲烷为易燃易爆危险气体,在选取实验气体时采用氮气代替。通过抽真空将选取的岩心充分饱和地层水,从而完成实验岩心的制备。

  • 2.2 实验条件

  • 将岩心置于夹持器中,氮气-水表面张力取值为 7.2 mN/m,各岩心参数及计算结果如表1 所示。由于雷口坡组气藏开发过程中地层压力可从 60 MPa 降低至 10 MPa,为了使实验具有代表性,同时考虑到仪器的技术安全规格限制,分别选取 10,30 和 50 MPa 的围压来模拟不同地应力。为保证实验结果具备对比性,各岩心在不同围压时需在同一驱替压差下开展实验。若地层围压达到50 MPa,会造成渗透率下降,采用过低压差难以进行驱替;又由于岩心长度有限,若采用高驱替压差易出现气窜,影响测试精度。最终,选取 π1π2的均值作为实验驱替压差。

  • 图2 实验岩心样品

  • Fig.2 Experimental core samples

  • 表1 实验岩心物性参数

  • Table1 Physical property parameters of experimental cores

  • 3 实验结果分析

  • 基质岩心、含溶蚀孔岩心以及天然裂缝岩心在地层温度(150℃)下,采用恒压法测定不同围压 (10,30,50 MPa)下的相对渗透率曲线(图3—图5)。不同围压下各岩心的相对渗透率曲线端点值及等渗点见表2。

  • 图3 基质岩心(l-151813)不同围压下气水相对渗透率曲线

  • Fig.3 Gas-water relative permeability curves of matrix core (l-151813)at different confining pressures

  • 图4 含溶蚀孔岩心(l-154068)不同围压下气水相对渗透率曲线

  • Fig.4 Gas-water relative permeability curves of core with dissolved pores(l-154068)under different confining pressures

  • 3.1 围压对岩心气水相对渗透率曲线的影响

  • 由图3—图5和表2可知,围压的影响首先体现在相对渗透率曲线形态的变化上。随着围压的增加,所有岩心的气相相对渗透率及水相相对渗透率曲线均有所下降,但气相相对渗透率曲线相对于水相相对渗透率曲线的下降幅度更为明显,导致等渗点不断向左移动。分析原因认为,各岩心相对渗透率曲线等渗点均大于 50%,表明该地层岩石均为水湿,围压增大,导致孔喉半径减小,两相同流时渗流阻力加大,由此造成两相相对渗透率曲线均有所下降。但孔喉半径减小导致孔隙中水相毛管压力不断增加,而孔隙中气相毛管压力的大小与水相相比可忽略不计,受水相毛管压力增加的影响,水相流动性降低幅度更小,因而其相对渗透率曲线降幅相对较小。

  • 图5 天然裂缝岩心(1-152960)不同围压下气水相对渗透率曲线

  • Fig.5 Gas-water relative permeability curves of natural fracture core(1-152960)under different confining pressures

  • 表2 不同岩心相对渗透率曲线端点值及等渗点参数

  • Table2 End point values and isotonic point parameters of relative permeability curves of different cores

  • 此外,围压对相对渗透率曲线的端点也有影响。围压增大则两相同流区宽度整体上呈逐渐收窄的趋势。说明围压增大,导致气水两相同流更为困难。具体将产生两方面影响:一方面,在气井未水淹时,水侵前缘在实际气藏中推进较为缓慢;另一方面,一旦气井见水,气相相对渗透率迅速下降,水相相对渗透率迅速增加,导致气井产水量剧增,气井的气水同产期更短,更易发生停喷。因此,该水侵特征可用于解释超深碳酸盐岩气井的暴性水淹现象,即部分气井一旦见水,短期内产水量迅速上升,产气量和井口压力迅速下降,最终导致气井在一个月乃至数天内完全停产。

  • 3.2 不同类型岩心气水相对渗透率曲线特征

  • 由图3—图5 以及表2 可知,3 种类型岩心的气水相对渗透率曲线特征存在部分差异。一方面,不同类型岩心的相对渗透率存在差异,天然裂缝岩心的相对渗透率最高,在围压为10 MPa时气相相对渗透率在束缚水端点处可达0.613,而含溶蚀孔岩心和基质岩心在围压为 10 MPa 时其值分别为 0.372 和 0.333。另一方面,不同类型岩心相对渗透率在围压变化过程中表现不同,天然裂缝岩心的相对渗透率下降最为明显,在围压增大到50 MPa时束缚水端点处的气相相对渗透率降至 0.137,降幅达 77.7%,而含溶蚀孔岩心和基质岩心在围压增大到 50 MPa 时分别为 0.123 和 0.157,降幅分别为 66.9% 和 52.8%。出现上述现象的原因为围压导致天然裂缝闭合,从而使得天然裂缝岩心的相对渗透率曲线形态更加趋近于基质岩心,因而相对渗透率曲线下降明显。含溶蚀孔岩心和基质岩心也受应力影响导致渗透率降低,但下降幅度均小于天然裂缝岩心,因而相对渗透率下降幅度相对较小。

  • 此外,不同类型岩心的相对渗透率端点特征有所不同。一方面,不同类型岩心的相对渗透率端点及两相同流区宽度在同一围压下存在差异。当围压为10 MPa时,基质岩心和天然裂缝岩心的两相同流区宽度明显较宽,分别为 39.45% 和 37%,而含溶蚀孔岩心的两相同流区宽度明显较窄,仅为33.3%。另一方面,不同类型岩心的相对渗透率端点及两相同流区宽度在不同围压下的变化也存在差异。其中,当围压从 10 MPa升至 50 MPa时,天然裂缝岩心的两相同流区宽度变化非常明显,从39.45%缩减至 32.66%;基质岩心变化也较为明显,从 37% 缩减至 29.45%;而含溶蚀孔岩心的两相同流区宽度变化幅度较小,从 33.3% 缩减至 32.25%。分析上述现象的原因,主要是存留在溶蚀孔中的流体体积较大且占比较高。且溶蚀孔保存流体的能力较强,即使受围压作用后孔隙度变化有限,使得流体也不易被驱替出。因而造成含溶蚀孔岩心相对渗透率端点和两相流动范围受围压影响不显著。

  • 3.3 与实际气井动态数据对比

  • 目前川西雷口坡组气藏尚未正式投产,可结合气井试气数据研究不同类型储层未来气井水侵特征,现有 2 口产水井的试气资料可作为研究依据。 PZ103井对雷四段下亚段储层(6 054.95~6 070.95, 5 990~6 040 m)开展酸压联作测试,放喷排液后采用一个工作制度,折算日产气量为 12.65×104 m3 /d,折算日产水量为 276 m3 /d,结合地质资料判断该区域储层为天然裂缝发育的含气水层,测试段位于气水界面以下的气水过渡带内,含气饱和度约为 44.3%。PZ3-5D 井测试层段埋深为 6 171~6 257 m,采用一个工作制度测试,放喷后求产,折算日产气量为37.67×104 m3 /d,折算日产水量为108 m3 /d,测试段位于气水界面以下的气水过渡带内,含气饱和度为 49.4%,结合地质资料判断该区域储层为天然裂缝相对不发育的含气水层。分析上述资料可知,当含气饱和度接近残余气饱和度时,天然裂缝储层产水能力明显强于基质,该结论与文中的相对渗透率规律一致。如表2 所示,当围压为 50 MPa 时,天然裂缝岩心在残余气饱和度处水相相对渗透率可达0.151,远高于基质岩心在残余气饱和度处的水相相对渗透率(0.113)。

  • 4 结论

  • 搭建了高温高压气水相对渗透率测试实验装置,设计了不同围压下的实验流程,测试得到了深层海相碳酸盐岩储层基质岩心、含溶蚀孔岩心和天然裂缝岩心在不同围压下的相对渗透率曲线。

  • 随着围压增加,岩心气水相对渗透率逐渐减小,等渗点不断向含水饱和度较小的方向移动,使岩心两相渗流特征发生改变;两相同流区宽度总体上逐渐收窄,导致气水两相同流更为困难,气井更易出现暴性水淹。

  • 3种类型岩心的相对渗透率大小依次为天然裂缝岩心、含溶蚀孔岩心、基质岩心。围压增加后天然裂缝岩心相对渗透率降幅最大,含溶蚀孔岩心次之,基质岩心下降最少。基质岩心与天然裂缝岩心的相对渗透率曲线两相同流区宽度较大,且受围压作用后缩减幅度较大。而含溶蚀孔岩心相对渗透率曲线的两相同流区较小,受围压作用后缩减幅度较小。

  • 符号解释

  • K g——岩样的气测克氏渗透率,D;

  • K rg——气相相对渗透率;

  • K rw——水相相对渗透率;

  • L ——岩样的长度,cm;

  • m n——时间为t n时岩样的质量,g;

  • m wm d——岩样饱和模拟地层水前、后的质量,g;

  • S w——岩样的含水饱和度,%;

  • V p——岩样孔隙体积,cm3

  • W n——时间t n内的累积产水量,mL;

  • π1π2——确定的初始驱替压差界限值,MPa;

  • ρ——水的密度,g/cm3

  • σ——气-水表面张力,mN/m;

  • ϕ ——岩样的孔隙度,%。

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    《油气地质与采收率》入选北大《中文核心期刊要目总览》2020年版