We demonstrate that pore pressure and stress changes resulting from several decades of oil and gas production significantly affect the likelihood of injection-related induced seismicity. We illustrate this process in the Delaware Basin (western Texas and southeastern New Mexico, USA), in which hydraulic fracturing and waste-water injection have been inducing numerous earthquakes in the southernmost part of the basin where there has been no prior oil and gas production from the formations in which the earthquakes are now occurring. In the seismically quiescent part of the basin, we show that pore-pressure and poroelastic-stress changes associated with prior oil and gas production make induced seismicity less likely. The findings of this study have important implications for the feasibility of large-scale carbon storage in depleted oil and gas reservoirs.Understanding where and how anthropogenic processes that increase pore pressure at depth (waste-water injection, hydraulic fracturing, CO2 injection, stimulation of geothermal wells, etc.) could potentially induce seismicity is important for seismic hazard mitigation. In this study, we show that while knowledge of the preexisting state of stress, pore pressure, and distribution of pre-existing faults enables one to predict the potential occurrence of induced seismicity, processes such as pore-pressure and stress changes associated with prior oil and gas production can significantly reduce the likelihood of induced seismicity. We investigate these phenomena in the Delaware Basin of western Texas and southeastern New Mexico (USA), where several studies link recent seismicity in the southernmost part of the basin to hydraulic fracturing and waste-water injection (e.g., Lomax and Savvaidis, 2019; Skoumal et al., 2020; Savvaidis et al., 2020). The Delaware Basin is the westernmost (and largest) part of the Permian Basin. Fluid injection associated with hydrocarbon development has long been suspected as triggering mechanisms for earthquakes at a number of sites in the Permian Basin since the 1960s (Rogers and Malkiel, 1979; Keller et al., 1981, 1987). The area also has occasional natural seismicity (Doser et al., 1991, 1992).In much of the Delaware Basin, there has been hydrocarbon production from the Delaware Mountain Group (DMG) and Bone Spring Group (BSG) since the early 1970s. Figure 1A shows the distribution of production wells in the DMG, and Figure 1B shows the distribution of BSG production wells. Each of the four maps in Figure 1 shows the locations of 4482 earthquakes (red dots) recorded by the TexNet seismic network (http://coastal.beg.utexas.edu/texnetcatalog) since 2017 (Savvaidis and Hennings, 2020). Although the TexNet catalog does not report earthquakes outside Texas and the station coverage is much better in the southern part of the Delaware Basin, it is striking in Figures 1A and 1B that the parts of the basin where hydrocarbon production from the DMG and BSG has occurred are essentially free of triggered seismicity. Figures 1D and 1E show the areal and depth distributions of horizontal drilling and hydraulic fracturing operations throughout the Delaware Basin, principally in the Wolfcamp Group (WG), a Permian-age unconventional oil reservoir. More than 9000 horizontal wells have been drilled in the WG since 2014, each with multiple (typically 20–50) hydraulic fracturing stimulations. Figures 1C and 1F show the areal and depth distributions of waste-water injection wells, principally in the DMG, a sequence of Permian-age formations that includes several depleted conventional oil reservoirs in some areas. As is the case with WG production wells, waste-water injection wells are located throughout the basin. The water being injected includes saline water that flows back to the surface after hydraulic fracturing as well as water that is co-produced with oil. It is obvious in Figure 1 that the triggered seismicity in the Delaware Basin is highly concentrated in the southernmost part of the basin, despite the fact that horizontal drilling and multi-stage hydraulic fracturing and wastewater disposal are occurring throughout the basin. One objective of this study is to identify the processes that seem to prevent induced seismicity from occurring in areas of prior oil and gas production.In our study, we do not address the mechanisms associated with the M 4.6 Mentone earthquake sequence of March 2020 (Savvaidis and Hennings, 2020), denoted by “M” in Figures 1A–1D. This earthquake sequence is spatially removed from the concentration of seismicity in Reeves and Pecos Counties (Texas) and appears to be associated with slip on deep, basement-rooted faults, possibly in response to waste-water injection at great depth occurring in that area. There are no deep injection wells in the area of seismicity in Reeves, Pecos, and Ward Counties (Texas) discussed here.Lund Snee and Zoback (2018) used wellbore stress indicators and earthquake focal plane mechanisms to demonstrate that normal faulting characterizes the entire Delaware Basin and that the direction of maximum horizontal compression (SHmax) gradually rotates clockwise from being approximately north-south in the northern part of the basin, to approximately east-west at the border between New Mexico and Texas, to northwest-southeast in the southern part of the basin (black lines in Fig. 2A). Correspondingly, focal mechanism data show that the orientation of fault planes rotates from north to south, consistently striking subparallel to the local direction of SHmax, as Coulomb faulting theory predicts.Using a methodology that incorporates the uncertainties associated with the parameters utilized in Coulomb failure analysis (Walsh and Zoback, 2016), we colored faults in Figure 2A to indicate the pore pressure required for slip on basement faults mapped by Hennings et al. (2020) throughout the Delaware Basin and the surrounding areas. Figure 2B is an enlargement of the area near the boundary between Reeves and Pecos Counties. The earthquakes shown by black circles in Figure 2 represent relocated hypocentral depths (after Sheng et al., 2020). Before the Sheng et al. study, earthquake depths were poorly determined due to the sparseness of the TexNet network. Earthquake epicenters shown by gray dots in Figure 2B are from a relocation of a limited number of events (Savvaidis and Peng, 2020) using hypoDD software (Waldhauser, 2001) to produce highly accurate relative earthquake locations. Note that the earthquakes occur along lineations that trend northwest-southeast, parallel to SHmax, as expected in an area of normal faulting. The colored faults in Figure 2B again indicate the pore pressure required to induce fault slip, but in this figure panel we show only shallow faults, principally in the DMG (after Hennings et al.,2020). The blue lines in Figure 2B show interpolated and smoothed directions of maximum horizontal stress used in the Coulomb slip analysis, which used a continuously varying stress field and the methodology described by Carafa and Barba (2013) and Carafa et al. (2015). Figure 2B emphasizes the fact that lineations of seismicity, focal plane mechanisms, and mapped faults at shallow depth all indicate that the earthquakes in this area are being triggered on faults optimally oriented for slip in the local stress field.Figure 3 presents a compilation of pore-pressure and stress data for the Reeves County area. As can be seen in Figure 3B, the detailed study of earthquake depths indicates that they are principally concentrated in the lower section of the DMG and the upper part of the BSG. The pore-pressure data in Figure 3A for Reeves County is principally from Luo et al. (1994), and the magnitude of the least principal stress, Shmin, and the vertical stress, Sv, are from Smye et al. (2020). Both the pore pressure and stress state shown represent those that existed prior to hydraulic fracturing in the WG or waste-water injection into the DMG. Shmin was determined from instantaneous shut-in pressures (ISIPs) associated with small-scale hydraulic fractures made specifically to determine Shmin. Note that pore pressure is essentially hydrostatic in the DMG and BSG but increases markedly with depth in the upper part of the WG, defining what is sometimes referred to as a pressure ramp (e.g., Rittenhouse et al., 2016). Correspondingly, the magnitude of Shmin increases suddenly with depth in the WG. This abrupt increase in the magnitude of Shmin implies that hydraulic fractures associated with WG wells would be expected to propagate upward into the BSG where Shmin is lower, an observation supported by microseismic events associated with wells hydraulically fractured in the upper WG (e.g., Parker et al., 2015).As shown by Zoback (2007), this equation accurately predicts the value of Shmin in sedimentary basins characterized by normal faulting for a coefficient of friction (μ) of ∼0.6. As indicated by the red straight line in Figure 3A, the value of Shmin from Equation 1 accurately predicts observed values of the least principal stress in the BSG, further indicating that the BSG is in a state of frictional equilibrium. There are very few available measurements of Shmin for the DMG in Reeves County. The four shallowest measurements are consistent with frictional equilibrium, while two measurements show higher values. The same is generally true in the WG—some of the Shmin measurements are consistent with frictional equilibrium (using a simplification of the pore-pressure ramp as shown), but other measurements indicate higher values than that predicted by Equation 1. We suggest that the magnitude of Shmin is higher than that predicted by frictional equilibrium because of viscoplastic stress relaxation in clay-rich lithofacies (Sone and Zoback, 2014), which reduces the difference between the maximum and minimum principal stress, Sv and Shmin, respectively (see discussion in Zoback and Kohli, 2019). Viscoplastic creep of the WG shales has been documented in laboratory tests by Rassouli and Zoback (2020) who showed measurements of the least principal stress with depth in the WG that vary between being consistent with critically stressed normal faults in relatively low-clay lithofacies and significantly higher values in clay-rich lithofacies.The Ochoan stratigraphic section above the DMG contains considerable evaporite deposits, resulting in a state of stress in which all three principal stresses are approximately equal. Consequently, it is not surprising that pore-pressure perturbations associated with either waste-water disposal or hydraulic fracturing operations occasionally trigger earthquakes in both the BSG and DMG. The shallow nature of the induced seismicity documented by Sheng et al. (2020) is consistent with the induced seismicity geomechanical mechanism presented here. Unfortunately, their results are limited to only a small area due to the relatively large station spacing of the TexNet array. Thus, further study of earthquake depths is required to thoroughly test the proposed induced seismicity mechanism.Figure 4 illustrates how pore pressure and stress evolve during depletion of the BSG reservoir from wells outside the seismically active area. This representation of stress and pore-pressure evolution with production as shown is based on the deformation analysis in reservoir space (DARS) representation of Chan and Zoback (2002). In Figure 4, Equation 1 is represented by the diagonal solid line, normalized by Sv so that data from different wells (where the BSG is at slightly different depths) can be shown together in the same figure. In other words, this line represents how the magnitude of Shmin varies as a function of pore pressure for a reservoir in a state of normal faulting frictional equilibrium (assuming μ = 0.6). At any given pore pressure, if the magnitude of Shmin is on this line, well-oriented normal faults are in a state of frictional faulting equilibrium. This is indicated by the green diamonds, which are equivalent to the data points for the BSG shown in Figure 3A. Data points that plot above this line indicate a stable stress state, which would require an increase in Pp (shifting the point to the right) to hit the failure line and induce slip. It is generally recognized that the change in the magnitude of the least principal stress with depletion in normal-faulting areas tends to suppress the tendency for normal faulting (see discussion in Zoback, 2007).Pore-pressure measurements for the BSG at different times are available for three wells in Eddy (New Mexico) and Loving (Texas) Counties just to the north of the area of triggered seismicity, at the locations shown by the black, red, and blue dots in the inset map in Figure 4. The red and blue dots in Figure 4 show the values of pore pressure at various times and Shmin values based on an assumed stress path, A, of 0.5 (Equation 2). Chan and Zoback (2002) present data for a number of depleted oil and gas fields that indicate stress paths of 0.5–0.6. Because depletion normally moves the stress state away from normal faulting, the representation of pore pressure and stress in Figure 4 indicates why seismicity is not occurring where BSG production has occurred. If we use appropriate values of Sv for the wells shown, the depletion-induced decrease in pore pressure in the BSG in 2013 was so large that it would require a significant pressure increase of 6.2 MPa to trigger normal faulting, even on the most optimally oriented faults.In the seismically active Reeves County–Pecos County area, potentially active normal faults trend NW-SE, parallel to the direction of maximum horizontal compression in that area. Hydraulic fracturing and waste-water disposal appear to be triggering slip on northwest-southeast–trending normal faults in the DMG and BSG in the part of the Delaware Basin where these faults were at frictional equilibrium at the initiation of horizontal drilling and multi-stage hydraulic fracturing activities in the WG and waste-water injection in the DMG. Elsewhere in the Delaware Basin, poroelastic stress changes result in a stress state that makes induced seismicity less likely. Analyses such as this will be essential in evaluating the potential for long-term sequestration of CO2 in depleted oil and gas reservoirs and thoroughly evaluating potential seismic hazards.The Stanford Center for Induced and Triggered Seismicity (Stanford, California, USA) funded this work. We thank Bill Ellsworth and Peter Hennings for helpful conversations. Well data were obtained from the Enverus DrillingInfo database (https://app.drillinginfo.com), FracFocus (https://fracfocus.org), Steven Misner of AIFE (aife@cox.net), and the Texas Railroad Commission (http://rrc.texas.gov). Earthquake data were obtained from the TexNet database (http://coastal.beg.utexas.edu/texnetcatalog). We also thank the GEOLOGY Science Editor, Marc Norman, and the reviewers Jeff Nunn and Steve Willson for their important comments.

中文翻译：

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先前的石油和天然气生产可以限制注入引起的地震活动的发生：美国德克萨斯州西部和新墨西哥州东南部特拉华盆地的案例研究

我们证明，几十年的石油和天然气生产导致的孔隙压力和应力变化显着影响注入相关诱发地震活动的可能性。我们在特拉华盆地（美国德克萨斯州西部和新墨西哥州东南部）说明了这一过程，在该盆地的最南端，水力压裂和废水注入引发了多次地震，那里以前没有石油和天然气生产从现在发生地震的地层。在盆地的地震静止部分，我们表明与先前油气生产相关的孔隙压力和孔隙弹性应力变化使诱发地震活动的可能性降低。这项研究的结果对枯竭油气藏大规模碳储存的可行性具有重要意义。地热井等）可能诱发地震活动对于减轻地震危害很重要。在这项研究中，我们表明，虽然了解预先存在的应力状态、孔隙压力和预先存在的断层分布可以预测诱发地震活动的潜在发生，但与先前石油相关的孔隙压力和应力变化等过程天然气生产可以显着降低诱发地震活动的可能性。我们在德克萨斯州西部和新墨西哥州东南部（美国）的特拉华盆地调查了这些现象，其中几项研究将盆地最南端最近的地震活动与水力压裂和废水注入联系起来（例如，Lomax 和 Savvaidis，2019 年；Skoumal等人，2020 年；Savvaidis 等人，2020 年）。特拉华盆地是二叠纪盆地最西端（也是最大）的部分。自 1960 年代以来，与油气开发相关的流体注入一直被怀疑是二叠纪盆地许多地点地震的触发机制（Rogers 和 Malkiel，1979；Keller 等，1981，1987）。该地区也偶有自然地震活动（Doser 等人，1991 年，1992 年）。在特拉华盆地的大部分地区，自 1970 年代初以来，特拉华山集团 (DMG) 和骨泉集团 (BSG) 一直在生产碳氢化合物。图1A为DMG生产井分布图，图1B为BSG生产井分布图。图 1 中的四张地图中的每张地图都显示了自 2017 年以来 TexNet 地震网络 (http://coastal.beg.utexas.edu/texnetcatalog) 记录的 4482 次地震（红点）的位置（Savvaidis 和 Hennings，2020）。尽管 TexNet 目录没有报告德克萨斯州以外的地震，而且特拉华盆地南部的台站覆盖范围要好得多，但在图 1A 和 1B 中引人注目的是，DMG 和 BSG 生产碳氢化合物的盆地部分发生了基本上没有触发地震活动。图 1D 和 1E 显示了整个特拉华盆地的水平钻井和水力压裂作业的面积和深度分布，主要是在 Wolfcamp Group (WG)，一个二叠纪时代的非常规油藏。自 2014 年以来，WG 已钻了 9000 多口水平井，每口井都有多个（通常为 20-50 个）水力压裂增产措施。图 1C 和图 1F 显示了废水注入井的面积和深度分布，主要位于 DMG，DMG 是一系列二叠纪地层，在某些地区包括几个枯竭的常规油藏。与 WG 生产井的情况一样，废水注入井遍布整个盆地。注入的水包括在水力压裂后流回地表的盐水以及与石油联产的水。从图 1 中可以明显看出，特拉华盆地触发的地震活动高度集中在盆地的最南端，尽管整个盆地都在发生水平钻井和多级水力压裂和废水处理。本研究的一个目标是确定似乎可以阻止先前油气生产地区发生诱发地震活动的过程。在我们的研究中，我们没有讨论与 2020 年 3 月 (Savvaidis和 Hennings，2020 年），在图 1A-1D 中用“M”表示。该地震序列在空间上与里夫斯县和佩科斯县（德克萨斯州）的地震活动集中区相分离，似乎与深部基底断层上的滑动有关，可能是为了应对该地区发生的大深度废水注入。此处讨论的里夫斯、佩科斯和沃德县（德克萨斯州）的地震活动区没有深注入井。 Lund Snee 和 Zoback（2018 年）使用井筒应力指标和地震焦平面机制来证明正断层是整个特拉华州的特征盆地的最大水平压缩方向（SHmax）逐渐顺时针旋转，从盆地北部的大约南北向，到新墨西哥州和德克萨斯州交界处的大约东西向，到南部的西北-东南部盆地的一部分（图 2A 中的黑线）。相应地，震源机制数据显示断层面的方向由北向南旋转，正如库仑断层理论所预测的那样，与 SHmax 的局部方向一致显着低于平行。使用一种方法，该方法结合了与库仑故障分析中使用的参数相关的不确定性（Walsh 和 Zoback，2016 年），我们在图 2A 中对断层进行了着色以指示孔隙Hennings 等人绘制的基底断层滑动所需的压力。(2020) 整个特拉华盆地及周边地区。图 2B 是里夫斯县和佩科斯县边界附近区域的放大图。图 2 中黑色圆圈所示的地震代表重新定位的震源深度（在 Sheng 等人之后，2020 年）。在盛等人之前。在研究中，由于 TexNet 网络的稀疏性，无法确定地震深度。图 2B 中以灰点显示的地震震中来自使用 hypoDD 软件（Waldhauser，2001）对有限数量的事件（Savvaidis 和 Peng，2020）进行重新定位，以生成高度准确的相对地震位置。请注意，正如在正常断层区所预期的那样，地震沿与 SHmax 平行的西北-东南走向的线发生。图 2B 中的彩色断层再次表明诱导断层滑动所需的孔隙压力，但在此图面板中，我们只显示了浅层断层，主要是在 DMG 中（在 Hennings 等人之后，2020 年）。图 2B 中的蓝线显示了库仑滑移分析中使用的最大水平应力的插值和平滑方向，该分析使用了连续变化的应力场以及 Carafa 和 Barba（2013 年）和 Carafa 等人描述的方法。(2015)。图 2B 强调了一个事实，即地震活动线、焦平面机制和浅层断层图都表明该地区的地震是在局部应力场中最佳滑动方向的断层上触发的。 图 3 显示了孔隙的汇编- 里夫斯县地区的压力和应力数据。从图 3B 中可以看出，对地震深度的详细研究表明它们主要集中在 DMG 的下部和 BSG 的上部。图 3A 中里夫斯县的孔隙压力数据主要来自于罗等人。(1994) 以及最小主应力的大小 Shmin 和垂直应力 Sv 来自 Smye 等人。(2020)。所示的孔隙压力和应力状态均代表 WG 中水力压裂或将废水注入 DMG 之前存在的那些状态。Shmin 是根据与专门用于确定 Shmin 的小规模水力压裂相关的瞬时关井压力 (ISIP) 确定的。请注意，DMG 和 BSG 中的孔隙压力基本上是静水压力，但随着 WG 上部的深度显着增加，定义了有时称为压力斜坡的内容（例如，Rittenhouse 等，2016）。相应地，Shmin 的大小随着 WG 深度的增加而突然增加。Shmin 量级的这种突然增加意味着与 WG 井相关的水力压裂预计将向上传播到 Shmin 较低的 BSG，由与上游 WG 中水力压裂井相关的微地震事件支持的观察结果（例如，Parker 等人，2015 年）。如 Zoback（2007 年）所示，该方程准确地预测了以正断层为特征的沉积盆地中的 Shmin 值摩擦系数 (μ) 约为 0.6。如图 3A 中的红色直线所示，公式 1 中的 Shmin 值准确地预测了 BSG 中最小主应力的观测值，进一步表明 BSG 处于摩擦平衡状态。里夫斯县 DMG 的 Shmin 测量值很少。四个最浅的测量值与摩擦平衡一致，而两个测量值显示更高的值。Rassouli 和 Zoback（2020 年）在实验室测试中记录了 WG 页岩的粘塑性蠕变，他们显示 WG 中最小主应力随深度的测量值在与相对低粘土岩相中的临界应力正断层一致和显着在富含粘土的岩相中的值更高。DMG 上方的 Ochoan 地层剖面包含大量的蒸发岩沉积物，导致所有三个主应力大致相等的应力状态。因此，与废水处理或水力压裂作业相关的孔隙压力扰动偶尔会在 BSG 和 DMG 中引发地震也就不足为奇了。盛等人记录的诱发地震活动的浅层性质。(2020) 与此处介绍的诱发地震地质力学机制一致。不幸的是，由于 TexNet 阵列的站间距相对较大，他们的结果仅限于一小部分区域。因此，需要进一步研究地震深度以彻底测试所提出的诱发地震活动机制。图 4 说明了在 BSG 储层从地震活动区以外的井中枯竭期间孔隙压力和应力的演变情况。如图所示，这种随生产的应力和孔隙压力演变的表示基于 Chan 和 Zoback (2002) 的储层空间变形分析 (DARS) 表示。在图 4 中，等式 1 由对角实线表示，通过 Sv 归一化，以便来自不同井（其中 BSG 的深度略有不同）的数据可以一起显示在同一图中。换句话说，这条线代表了在正常断层摩擦平衡状态（假设 μ = 0.6）下，作为储层孔隙压力函数的 Shmin 的大小如何变化。在任何给定的孔隙压力下，如果 Shmin 的大小在这条线上，则方向良好的正断层处于摩擦断层平衡状态。这由绿色菱形表示，它们相当于图 3A 中显示的 BSG 的数据点。绘制在这条线上方的数据点表示稳定的应力状态，这将需要增加 Pp（将点向右移动）才能达到破坏线并引起滑移。人们普遍认为，随着正常断层区的损耗，最小主应力大小的变化往往会抑制正常断层的趋势（见 Zoback，2007 年的讨论）。 BSG 在不同时间的孔隙压力测量是可用于位于触发地震活动区域以北的 Eddy（新墨西哥州）和 Loving（德克萨斯州）县的三口井，位于图 4 插图中黑色、红色和蓝色点所示的位置。红色图 4 中的蓝点和蓝点显示了不同时间的孔隙压力值和基于假定应力路径 A 为 0.5（方程 2）的 Shmin 值。Chan 和 Zoback (2002) 提供了许多枯竭油气田的数据，这些数据表明应力路径为 0.5-0.6。因为耗竭通常会使应力状态远离正常断层，图 4 中孔隙压力和应力的表示表明了为什么在 BSG 生产发生的地方没有发生地震活动。如果我们对所示的井使用适当的 Sv 值，2013 年 BSG 中枯竭引起的孔隙压力下降如此之大，以至于需要显着增加 6.2 MPa 的压力才能触发正常断层，即使是在最优化的方向上断层。在地震活跃的里夫斯县-佩科斯县地区，潜在的活动正断层呈 NW-SE 趋势，平行于该地区的最大水平压缩方向。水力压裂和废水处理似乎引发了特拉华盆地部分 DMG 和 BSG 中西北-东南向正断层的滑动，这些断层在水平钻井和多级水力钻井开始时处于摩擦平衡。 WG 中的压裂活动和 DMG 中的废水注入。在特拉华盆地的其他地方，多孔弹性应力变化导致应力状态，使诱发地震活动的可能性降低。此类分析对于评估枯竭油气藏中 CO2 长期封存的潜力以及彻底评估潜在的地震危害至关重要。斯坦福诱发和触发地震中心（美国加利福尼亚州斯坦福）资助了这项工作。我们感谢 Bill Ellsworth 和 Peter Hennings 的有益对话。井数据来自 Enverus DrillingInfo 数据库 (https://app.drillinginfo.com)、FracFocus (https://fracfocus.org)、AIFE 的 Steven Misner (aife@cox.net) 和德克萨斯铁路委员会 ( http://rrc.texas.gov）。地震数据来自 TexNet 数据库 (http://coastal.beg.utexas.edu/texnetcatalog)。我们还要感谢 GEOLOGY Science 编辑 Marc Norman 以及审稿人 Jeff Nunn 和 Steve Willson 的重要评论。