During drilling process, water phase invades into reservoirs through capillary force and positive differential pressure, causing water phase trapping in tight sandstone gas reservoirs, and resulting in wrong logging data explanation of pay zones to water zones, hindering timely discovering and accurately appraising of tight sandstone gas reservoirs. To understand the self-imbibition behavior of water phase in tight sandstone gas reservoir, plug cores from a typical tight sandstone gas reservoir were used to simulate self-imbibition by end contact of plug core with water when water comes into contact with reservoir rocks at the moment when the reservoir is first drilled, self-imbibition by soaking of rocks when fractures are flooded with water, and forced imbibition by capillary force under the action of positive differential pressure. The influences of contact area and differential pressure on capillary self-imbibition of water to tight sandstone are analyzed. The simulation test results show that imbibition rate is affected by imbibition area and the development of fracture. The more developed the fractures and the greater the contact area, the higher the imbibition rate, and the imbibition process is easier to reach equilibrium. Positive differential pressure accelerates capillary imbibition in rocks whose physical properties in turn affect the imbibition process. When the physical properties of rocks are low to a certain extent, the imbibition behavior is mainly affected by capillary force. For the dense part of a tight gas reservoir matrix, positive differential pressure has minor effect on imbibition. When fractures are developed in the dense part of the tight gas reservoir matrix, the contact area for flow is increased, and ahigh positive differential pressure enhances the imbibition rate. It is thus concluded that water invasion into tight sandstone reservoirs during drilling and completion can be prevented mainly by plugging fractures and by controlling differential pressure to minimize water-rock contact and the amount of water entering into reservoir rocks.%钻完井过程中,水相通过毛管自吸和正压差进入储层,会引起致密砂岩气藏水相圈闭损害,导致储层测井解释错判为水层,阻碍致密砂岩气藏的及时发现和准确评价.为了揭示致密砂岩气藏水相自吸行为,选取典型致密砂岩气藏柱塞岩样,分别模拟了钻开储层时水相接触岩石的岩样端面自吸、裂缝水淹后的岩样浸泡自吸和正压差下的毛管强制渗吸实验,分析了接触面积与压差对致密砂岩水相毛管自吸的影响.结果表明:自吸速率受到渗吸面积与裂缝发育程度的影响,裂缝越发育,接触面积越大,渗吸速率越快,渗吸越易达到平稳阶段;正压差促进岩石毛管渗吸作用,但受岩石物性影响明显,当岩石物性低到一定程度时,渗吸作用主要受到毛管力的控制;裂缝的存在既增加渗吸接触面积,又进一步强化正压差作用,使渗吸能力显著增加.结合实验研究认为,在钻完井过程中,预防致密砂岩气藏水相侵入应以封堵裂缝、控制压差来减少水岩接触面积和水相侵入量为主.
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