犹他大学  土木与环境工程与能源与地球科学研究所的Z. DVORY和BJ MCPHERSON以及化学工程与能源与地球科学研究所的JD MCLENNAN

介绍 

犹他州东南部宾夕法尼亚纪 Paradox 地层的 Cane Creek 油气藏被认为是美国极具前景但极具挑战性的非常规致密油气藏，其历史上一直存在钻井和完井困难。该油气藏最初于近一个世纪前被发现，直到 20 世纪 90 年代初随着水平钻井技术的出现，才恢复大规模勘探。  

尽管有些油井取得了成功，但实现大规模生产仍遥遥无期。这项由美国能源部资助的研究旨在利用该盆地的地质力学知识，制定可持续且经济的刺激战略。当地运营商普遍认为，开发 Cane Creek 油田的主要挑战是成功获取天然裂缝。  

然而，Walton & McLennan (2013) 等研究表明，天然裂缝可能不会对生产力产生重大贡献。我们承认，当存在大量相对较大的导电裂缝或断层，或者当它们相对于应力场的方向最适合滑移时，天然裂缝刺激方法是有效的。考虑到与滑移相关的导电性，我们认识到两种可能引发滑移的机制：(1) 由于扩展水力裂缝附近的孔隙压力上升，有效应力降低；(2) 由于应力阴影传播，裂缝表面的差应力增加。 

图 1. Paradox 盆地的研究地点横跨犹他州、科罗拉多州、亚利桑那州和新墨西哥州。黑线代表 Dvory 等人 (2024) 划定的最大水平应力 (SHmax) 的方向。该地图还划定了 Paradox 盆地的沉积和构造边界，包括 Uncompahgre 和 San Luis 隆起。盆地盐墙结构的位置用灰色多边形标记，与 Trudgill (2011) 和 Baars (1966) 的发现一致。

这两种机制取决于水力裂缝的扩展和刺激液向岩石中的泄漏——从基质角度来看，后者相对较小。最近对 Eagle Ford、Permian 和 Junggar 盆地的研究报告了水力裂缝扩展的详细表征。这些研究从倾斜岩心裂缝特征和光纤研究中表明，这些油气田中的水力裂缝通常以裂缝群的形式分布，这些裂缝群的方向朝向最大水平应力（Gale 等人，2018 年、2021 年；Raterman 等人，2017 年、2019 年；Shi 等人，2022 年；Ugueto 等人，2021 年）。   

具体而言，Ugueto 等人 (2021) 展示了偏移井中大致线性的裂缝撞击，这意味着裂缝扩展行为（例如分支和跨步）仅限于小规模。这些发现表明，在代表致密储层的渗透率范围内（0.01-0.1md），远场孔隙压力分布的影响是局部的，因此提高了应力阴影分布引发滑移的可能性。微地震，特别是水平井多级水力压裂，主要归因于预先存在的裂缝和断层的剪切滑移。 

本研究通过汇编两口试验井的地质力学数据，以及由 Dvory 等人 (2024) 执行的平面裂缝建模方法 (McClure 等人，2020) 获得的应力阴影模拟，评估了 Cane Creek 地层的天然裂缝和断层剪切潜力。  

甘蔗溪剧 

Paradox 盆地的 Cane Creek 油气田位于犹他州东南部和科罗拉多州西南部，延伸至亚利桑那州和新墨西哥州（图 1）。天然裂缝在该油气田的几个生产井的功能中起着关键作用，但通过诱导水力裂缝进行增产的成功率并不一致。 

图 2. 根据 FMI 测井数据（a），以及沿着 State 16-2 垂直井 100 英尺岩心（b）的裂缝分布。

据推测，增加该油田的产量将取决于更精确的基本表征，特别是更准确地量化应力状态。从 State 16-2 垂直测试井和 State 16-2 Ln 水平井收集了一个新的数据集，包括约 110 英尺的岩心测井记录，包括地层微成像仪 (FMI) 图像记录和诊断性裂缝注入测试 (DFIT)。Cooper 和 Lorenz (2022) 对 State 16-2 垂直井岩心的天然裂缝分布进行了详细评估。图 2显示了 State 16-2 Ln 井横向剖面岩心分析和 FMI 测井的裂缝分布。 

根据钻井曲线得到 N104E 的饾醜_Hmax方位(Dvory & McLennan, 2014)，并在该地区绘制了走滑断层模式，饾醜_V >饾醜_Hmax >饾醜_hmin，其中饾醜_V为垂直主应力，饾醜_hmin表示最小水平主应力 (Lund Snee & Zoback, 2020)。  

莫尔图的启示 

在陆地地壳中，脆性岩石承受着临界应力，这意味着在环境应力场中，滑移的最佳方向断层保持着摩擦平衡状态。然而，在 Paradox 盆地的准各向同性应力状态下，盐和碎屑岩层中的粘塑性应力松弛过程需要额外的孔隙压力增加约 840 psi 才能开始滑移。 

图 3. 通过莫尔圆说明随着孔隙压力的增加，天然裂缝的激活情况。彩色点表示裂缝到失效的距离。黑点表示失效模式中的裂缝。a) 在摩擦失效平衡状态下，从 FMI 测井中识别出天然裂缝。b) 在摩擦失效平衡状态下，沿岩心观察到天然裂缝。c) 来自 FMI 测井的诱导裂缝和 d) 来自压裂梯度孔隙压力水平（Pp ≤ 100MPa）的岩心。

图 3a、b显示了岩心的裂缝映射和 FMI 测井图，该图以垂直应力为标准，以 Mohr 图表示。该图描绘了在给定测量的应力状态和孔隙压力的情况下，在每个平面上解析的剪切和法向有效应力。彩色刻度表示裂缝接近失效的程度。在这里，对于最佳方向的裂缝（用红点表示），孔隙压力的轻微上升可能会引发滑动，而用深蓝色点表示的裂缝则是稳定的。 

在增产过程中，流体注入逐渐增加，直到达到压裂梯度（Pp-铊hmin）。当前分析不包括增产过程中铊_{hmin以上的}压力上升，通常约为几 MPa（几百 psi），这是由高速率泵送粘稠流体引起的。随着压力上升，更多次优取向的平面可能会滑动（图 3c，d—摩擦平衡线上方的黑色圆点）。在此阶段，天然裂缝和断层经历剪切增产，变得具有渗透性，它们的不同取向有助于形成相互连接的裂缝网络。 

值得注意的是，虽然预计大多数平面在达到压裂梯度时会滑动，但有几个平面不会滑动（摩擦平衡线下方的彩色点）。图 4显示了图 3c中的 177 个次优定向平面，它们可能沿着穿透 16-2 Ln 井的 7,064 英尺滑动。平均而言，每 40 英尺可以刺激一次裂缝，与 HFTS 2 的水力压裂作业记录性能相比，覆盖率相对较差，其中裂缝之间的平均距离为 1.9 英尺（Gale 等人，2021 年）。    

图 4. 16-2 Ln 州在 Cane Creek 油气田中的井位。FMI 测井曲线中的黄点诱发裂缝（图 3c）。

应力阴影是否会引发 Cane Creek 应力状态下的天然裂缝滑移？ 

在水力压裂中，“应力阴影”一词指的是由于相邻裂缝的扩展而导致应力动态发生改变的区域。 

裂缝在形成或扩展时会对周围的岩石施加压力，从而改变周围的应力场。应力影的传播是一个复杂的地质力学过程，超出了本研究的范围。尽管如此，我们认识到它对应力场的贡献可能在任一主要方向上。应力影的大小不是一个固定值。它取决于与地质环境和水力压裂操作细节相关的因素。  

在正在进行的分析中，我们考虑了应力阴影效应的两个组成部分。第一个是多孔弹性变化，第二个是由于裂缝张开而引起的应力变化。对于多孔弹性应力变化，我们在应力阴影前沿使用了 500 psi 的值来探索“远场”中的裂缝破坏潜力，其中孔隙压力扰动的影响可以忽略不计。在这里，我们通过应力阴影幅度提高了三主应力，并探索了新的应力状态及其对裂缝破坏潜力的影响。  

图 5. 由于在每个主轴上施加了附加应力（－）而导致应力状态发生变化。

图 5说明了有效应力与施加到每个主应力上的附加应力 ( -)的关系。当此“附加”被添加到最大水平应力时，它不会改变应力状态，因为原位应力已经处于正断层状态。然而，对于垂直应力，应力状态转变为正断层应力状态。如果最小最小应力升高，则应力状态转变为逆断层，而两个水平应力则互换。  

在沃斯堡盆地也观察到了类似的模式，那里存在类似的应力状态。在这里，对巴奈特页岩增产期间获得的微地震事件进行焦平面机制分析，显示出一系列正常和走滑行为（Kuang 等人，2017 年）。多孔弹性响应可能产生的高应力增加了滑动趋势。在这种情况下，水平应力之间的差异（饾憜_Hmax -饾憜_hmin）高于多孔弹性响应（并且很可能高于应力阴影），因为没有记录逆断层行为。 

图 6. 对每个主应力补充 500 psi 后的应力阴影效应。

图 7. 应力阴影大小引起滑移的临界阈值。

图 6显示了每个主应力施加 500 psi 的情况。由于 Cane Creek 油田的初始应力状态远未达到临界状态，尽管系统增加了额外的应力，但每个裂缝平面上的剪切应力并未达到临界值。图 7显示了应力阴影大小诱发滑动的临界阈值。我们证明，在S _Hmax方向增加 1,650 psi 将使储层转变为失效模式。 

通过平面断裂模型评估应力阴影 

我们利用“平面裂缝建模”技术来模拟多孔弹性响应和应力阴影分布（McClure 等人，2020 年）。我们的模型基于 Dvory 等人（2024 年）的裂缝扩展研究，该研究制定了一种限制裂缝长度的方法。平面裂缝模型的基础是拉伸，而不是剪切破坏。我们的滑移分析与从数值模拟中获得的多孔弹性和应力阴影变化严格相关。  

Dvory 等人 (2024) 详细描述了我们的建模策略和结果。我们的模拟过程从校准开始，使用第 11 阶段的数据和相关的生产数据集。随后，我们对断裂韧性曲线进行了敏感性分析，并评估了不同的簇间距如何影响裂缝长度。图 8显示了第 11 阶段关闭前S _hmin方向上的孔隙弹性效应。 

图 8. 16-2 Ln 井第 11 阶段关闭前沿 Shmin 方向的孔隙弹性应力变化（有关其他模拟参数，请参阅 Dvory 等人 2024）。

我们的结果表明，最大应力影在井附近形成，达到约 232 psi。仅此值不足以引起滑移。图 9显示了阶段关闭时沿最小水平应力方向的应力影大小。总应力变化包括孔隙弹性效应和与裂缝张开相关的远程机械应力。关闭时近场的最大应力影约为 850 psi（图 9中的红色）。Cane Creek 单元的横向应力变化小于 100 psi。后者意味着远场裂缝不太可能滑移，因为应力变化低于 1,650 psi（图 7）。 

图 9. 16-2 Ln 井第 11 阶段关闭前沿 Shmin 方向的应力阴影。此处的应力阴影包括多孔弹性和裂缝张开效应（有关其他模拟参数，请参阅 Dvory 等人，2024 年）。

讨论  

我们的研究结果突出了 Cane Creek 油田的地质力学行为，强调了触发天然裂缝的复杂性。虽然传统观点强调了天然裂缝在生产力中的作用，但我们的研究证实了新出现的共识，即此类裂缝的刺激可能与生产力没有内在联系。相反，这项研究强调了裂缝扩展动力学的临界性和应力阴影效应在裂缝刺激中的作用。 

水力裂缝扩展研究（例如 Eagle Ford 页岩和 Permian 盆地的研究）揭示了裂缝群的方向偏好，并强调了应力方向对裂缝轨迹的影响的重要性（Raterman 等人，2019 年；Gale 等人，2021 年；Ugueto 等人，2019a；2019b）。我们对 Cane Creek 油田的分析扩展了这些见解，表明孔隙压力分布和应力阴影扩展是增产过程中的决定性因素。局部孔隙压力效应和应力阴影引发的滑移潜力为致密储层中的裂缝行为提供了细致入微的理解。 

本研究采用的平面裂缝建模方法通过提供天然裂缝和断层的剪切潜力的粒度视图，进一步加深了我们的理解（Dvory 等人，2024；Dvory 和 McLennan 2024）。应力阴影效应的敏感性分析结合了孔隙弹性和裂缝开口成分，表明 Cane Creek 油田的应力状态本质上不利于滑动，除非应力发生显著变化。这一观察结果与其他盆地（如沃思堡盆地）的记录行为相一致（Kuang 等人，2017），为评估应力阴影在不同地质环境中的作用提供了一个比较框架。 

结论  

这项对 Paradox 地层内 Cane Creek 油藏的研究揭示了天然裂缝和断层在致密油藏中的作用。我们证明了传统上认为天然裂缝的刺激是提高油井生产率的基石，但这可能与提高产量没有直接关系。相反，关键因素似乎是裂缝扩展的方向性和应力阴影效应的复杂动态。 

我们对裂缝扩展行为的研究表明，虽然水力压裂作业成功产生了裂缝群，但其生产率可能取决于局部孔隙压力上升和有效操纵应力阴影扩展的能力（这只是理想情况）。我们的研究结果强调，在 Cane Creek 油田目前的地质力学状态下，提炼天然裂缝刺激的潜力有限，因为需要显著改变应力条件才能启动滑移裂缝面。 

平面裂缝建模已对相邻、遥远的天然裂缝和断层的剪切势有了细致入微的了解，表明现有应力状态在这种地质环境下，若不进行实质性应力修改，则不足以引发滑动。这与在其他盆地观察到的行为一致，并提供了应力阴影在不同地质背景下的作用的比较视角。 

考虑到这些发现，我们主张对水力压裂方法进行修订，优先详细评估应力状态和裂缝扩展动力学。这种方法可以更好地管理应力阴影，从而提高压裂作业的可预测性和效率，从而实现更可持续、更经济的资源开采。 

进一步的研究应量化孔隙压力动态、应力阴影发展和裂缝方向之间的复杂关系。了解这些关系是逐步改进非常规油气增产技术的关键，有可能改变水力压裂策略的进程，以实现经济可行性和环境管理的双重目标。 

致谢 

本文基于 ARMA（美国岩石力学协会）24-1158 号论文，该论文于 2024 年 6 月 23 日至 26 日在美国科罗拉多州戈尔登举行的第 58 届美国岩石力学/地质力学研讨会上发表。本文提到的研究由 DOE 项目资助：提高新兴悖论油田的产量 DE-FE0031775。作者感谢 Mark McClure 的有益评论和 ResFrac 学者。  

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• 石绍兴、卓荣、程玲、项燕、马晓燕和王婷 (2022)。中国西北地区准噶尔盆地砾岩水力压裂试验场 (CHFTS) 斜岩心裂缝特征及分布。过程，10 (8)，1646。https://doi.org/ 10.3390/pr10081646 
• Trudgill, BD (2011)。北部 Paradox 盆地盐结构的演化：蒸发岩沉积、盐墙生长和盐上地层结构的控制因素：北部 Paradox 盆地盐结构的演化。盆地研究，23 (2)，208-238。https://doi.org/10.1111/j.1365-2117.2010.00478.x 
• Ugueto, GA、Wojtaszek, M.、Huckabee, PT、Savitski, AA、Guzik, A.、Jin, G.、Chavarria, JA 和 Haustveit, K. (2021)。水力压裂试验场 2 中水力诱导裂缝几何形状的综合视图。第 9 届非常规资源技术会议论文集。非常规资源技术会议，美国德克萨斯州休斯顿。https://doi.org/10.15530/urtec-2021-5396 
• Walton, I. 和 McLennan, J. (2013)。天然裂缝在页岩气生产中的作用。《有效和可持续水力压裂》。InTech。https://doi.org/10.5772/56404 

1. 现任博士 ZACH DVORY是犹他大学土木与环境工程及能源与地球科学研究所的研究助理教授。他拥有耶路撒冷希伯来大学地球科学学士学位、耶路撒冷希伯来大学地球物理学硕士学位以及内盖夫本·古里安大学流体动力学博士学位，研究项目：补给与流动。Dvory 博士的职业经历包括 ITM 技术实验室经理、以色列地球物理研究所地质学家/地球物理学家、自然资源开发有限公司地质学家和项目经理以及 Etgar A. Engineering Ltd. 首席地质学家/首席地质学家。Dvory 博士的研究兴趣集中在纳米至储层尺度的孔隙压力扰动和热化学演化的地质力学响应。”
2. BRIAN MCPHERSON是犹他大学土木与环境工程系 USTAR 教授，也是能源与地球科学研究所的教授。他拥有俄克拉荷马大学地球物理学学士学位，并在犹他大学获得地球物理学硕士和博士学位。McPherson 博士的专业经验包括担任美国地质调查局的水文学家、新墨西哥矿业技术学院地球物理研究中心的研究水文学家、新墨西哥矿业技术学院水文学助理教授、新墨西哥理工学院石油回收研究中心的高级科学家以及新墨西哥矿业技术学院水文学副教授。McPherson 博士的技术重点领域包括地下水和水库模拟、多相流分析和模拟、岩石变形以及地下化学反应传输分析和模拟。”
3. 约翰·麦克莱南是犹他大学化学工程教授，也是能源与地球科学研究所的教授。他拥有多伦多大学地质工程学士学位，以及多伦多大学土木工程硕士学位和博士学位。麦克莱南博士的职业经历包括在 TTI Geotechnical Resources Ltd.、Dowell Schlumberger、TerraTek, Inc.、Advantek International Corporation 和 ASRC Energy Services E & P Technology 担任过越来越重要的职位。他曾从事煤层气回收、机械性能测定、采出水和钻屑回注以及与压实有关的套管设计问题。麦克莱南博士最近的工作重点是优化页岩和松散地层的天然气生产。 

Z. DVORY and B. J. MCPHERSON, Civil & Environmental Engineering & Energy and Geoscience Institute, and J. D. MCLENNAN, Chemical Engineering & Energy and Geoscience Institute, University of Utah  

Introduction 

The Cane Creek play in the Pennsylvanian-age Paradox formation in southeastern Utah is regarded as a promising-yet-challenging, unconventional tight oil play in the U.S., with a history marked by drilling and completion difficulties. Initially identified nearly a century ago, substantial exploration resumed only in the early 1990s with the advent of horizontal drilling technology.  

Despite some successful wells, achieving substantial production remained elusive. Research, sponsored by the U.S. Department of Energy, aims to leverage the basin's geomechanics knowledge and develop sustainable and economic stimulation strategies. A common hypothesis that local operators hold is that the main challenge in developing the Cane Creek play is successfully accessing natural fractures.  

Yet, studies such as Walton & McLennan (2013) have shown that natural fractures may not significantly contribute to productivity. We acknowledge that the natural fractures stimulation approach is valid when there is a tractable number of relatively large conductive fractures or faults or possibly when their orientation relative to the stress field is optimal for slippage. Considering slippage-related conductivity, we recognize two mechanisms that might trigger slip: (1) the decrease in the effective stress, due to pore pressure rise in the vicinity of the propagating hydraulic fracture; and (2) the increase of the differential stress over the fracture surface, due to stress shadow propagation. 

Fig. 1. Research site location in the Paradox basin stretches across Utah, Colorado, Arizona, and New Mexico. The black lines represent the orientations of the maximum horizontal stress (SHmax) delineated by Dvory et al. (2024). This map also demarcates the Paradox basin's depositional and tectonic boundaries, including the Uncompahgre and San Luis uplifts. The positions of the basin's salt wall structures are marked, using gray polygons, aligning with the findings of Trudgill (2011) and Baars (1966).

The two mechanisms depend on the hydraulic fracture propagation and the stimulation fluids leak-off into the rock—the latter will be relatively small from a matrix perspective. Recent Eagle Ford, Permian and Junggar basin studies reported a detailed characterization of hydraulic fracture propagation. These studies showed, from slant core fracture characteristics and fiber optic studies, that hydraulic fractures in those plays typically spread in strands of fracture swarms that are oriented in the direction of the maximum horizontal stress (Gale et al., 2018, 2021; Raterman et al., 2017, 2019; Shi et al., 2022; Ugueto et al., 2021).   

Specifically, Ugueto et al. (2021) showed broadly linear fracture hits in offset wells, which implies that fracture propagation behaviors, such as branching and stepovers, are limited to a small scale. Those findings suggest that in a permeability range representing tight reservoirs (0.01-0.1md), the effect of pore pressure distribution in the far field is localized and, therefore, levels up the potential for slip triggered by the stress shadow distribution. Microseismicity, specifically for multi-stage hydraulic fracturing in horizontal wells, is primarily attributed to shear slip on pre-existing fractures and faults. 

The current study assesses the Cane Creek formation’s natural fracture and fault shearing potential by compiling geomechanical data from two test wells with a stress shadow simulation obtained by a planar fracture modeling approach (McClure et al., 2020) executed by Dvory et al. (2024).  

The Cane Creek Play 

The Cane Creek play in the Paradox basin is in southeastern Utah and southwestern Colorado and extends to Arizona and New Mexico, Fig. 1. Natural fractures play a pivotal role in the functionality of several of the play’s producing wells, yet the success rate of stimulation via induced hydraulic fractures isn't consistent. 

Fig. 2. Fracture distributions along State 16-2 Ln—a horizontal well—from an FMI log (a) and along the 100-ft core of State 16-2 vertical well (b).

It's hypothesized that augmenting production within this play will hinge on a refined fundamental characterization, particularly a more accurate quantification of the stress state. A new dataset, comprising around 110 ft of core well logs, including a Formation Microimager (FMI) image log and a diagnostic fracture injection test (DFIT), was gathered from the State 16-2 vertical test well and the State 16-2 Ln horizontal well. A detailed assessment of the natural fracture distribution in the core from the State 16-2 vertical well was carried out by Cooper and Lorenz (2022). Figure 2 illustrates the fracture distribution from the core analysis and the FMI log of the lateral section of State 16-2 Ln well. 

The 𝑆_Hmax orientation of N104ºE obtained from well logs (Dvory & McLennan, 2014) and a strike-slip faulting regime was mapped in this locality, with 𝑆_V > 𝑆_Hmax > 𝑆_hmin, where 𝑆_V is the vertical principal stress and 𝑆_hmin represents the minimum horizontal principal stress (Lund Snee & Zoback, 2020).  

Insights from Mohr Diagrams 

In the terrestrial crust, brittle rocks are critically stressed, meaning optimally oriented faults for slip within the ambient stress field maintain a state of frictional equilibrium. However, in the Paradox basin's quasi-isotropic stress state, viscoplastic stress relaxation processes in the salts and clastic formation require an additional pore pressure increase of about 840 psi before slip initiation. 

Fig. 3. Natural fracture activation with increased pore pressure illustrated through Mohr circles. Colored dots represent the fracture distance to failure. Black dots are fractures in failure mode. a) Natural fractures are identified from the FMI log under a frictional failure equilibrium state. b) Natural fractures are observed along the core under a frictional failure equilibrium state. c) induced fractures from the FMI log and d) from the core at the frac gradient pore pressure level (Pp ≈ 𝑆hmin).

Figure 3a,b shows fractures mapped in the core and the FMI log in a Mohr diagram normalized by the vertical stress. This plot depicts the shear and normal effective stresses resolved on each plane, given the measured stress state and pore pressure. The colored scale represents the fracture’s proximity to failure. Here, a slight rise in pore pressure for an optimally oriented fracture (colored in red dots) may trigger slip, while fractures colored by dark blue dots are stable. 

During stimulation, fluid injection progressively augments until reaching the frac gradient (Pp ≈ 𝑆_hmin). The current analysis excludes the pressure rise over 𝑆_hmin during stimulation, typically around a few MPa (a few hundred psi) caused by high-rate pumping of a viscous fluid. As pressure ascends, more sub-optimally oriented planes potentially slip (Fig. 3c,d—black dots above the frictional equilibrium line). At this stage, natural fractures and faults undergo shear stimulation, becoming permeable, and their diverse orientations contribute to an interconnected fracture network. 

Notably, while most planes are anticipated to slip upon reaching the frac gradient, several will not (colored dots below the frictional equilibrium line). Figure 4 shows the 177 sub-optimally oriented planes from Fig. 3c that potentially slip along the 7,064 ft that penetrated well 16-2 Ln. On average, a fracture could stimulate every 40 ft, which is relatively poor coverage, compared to the documented performance of the hydraulic fracturing operations at the HFTS 2, where the average distance between fractures is 1.9 ft (Gale et al., 2021).    

Fig. 4. State 16-2 Ln well placement within the Cane Creek play. Yellow dots-induced fractures from the FMI log (Fig. 3c).

Could the stress shadow trigger natural fracture slippage at the Cane Creek stress state? 

In the context of hydraulic fracturing, the term "stress shadow" refers to a zone where the stress dynamics have been altered, due to the expansion of an adjacent fracture. 

Upon creation or expansion, a fracture exerts pressure on the surrounding rock, changing the stress field around it. The propagation of a stress shadow is a complex geomechanical process that falls beyond the ambit of the present study. Nonetheless, we recognize that its contribution to the stress field could be in either principal direction. The magnitude of a stress shadow is not a fixed value. It depends on factors related to the geological setting and the specifics of the hydraulic fracturing operation.  

We considered two components of the stress shadow effect for the ongoing analysis. The first is a poroelastic change, and the second is the stress change, due to the fracture opening. For the poroelastic stress change, we have used a value of 500 psi at the stress shadow front to explore the fracture failure potential in the ‘far field,’ where the effect of the pore pressure perturbation is negligible. Here, we elevated the three-principal stress by the stress shadow magnitude and explored the new stress state and its implication on the failure potential of fractures.  

Fig. 5. Modification of stress state, due to the application of additional stress (∆P) to each principal axis.

Figure 5 illustrates the effective stress as a function of additional stress (∆P) applied to each principal stress. When this “supplement” is added to the maximum horizontal stress, it does not alter the state of stress, since the in-situ stress is already in a normal faulting state. However, for the vertical stress, the stress state transitions to a normal faulting stress state. If the least minimum stress is elevated, then the state of stress transfers to reverse faulting, while the two horizontal stresses interchange.  

A comparable pattern was observed in the Fort Worth basin, where a similar stress state exists. Here, a focal-plane mechanisms analysis of microseismic events obtained during a Barnett shale stimulation exhibits a range of normal and strike-slip behavior (Kuang et al., 2017). The elevated stress that may arise from the poroelastic response increases the tendency to slip. In this case, the difference between the horizontal stresses (𝑆_Hmax - 𝑆_hmin) was higher than the poroelastic response (and most likely higher than the stress shadow), since no reverse faulting behavior was documented. 

Fig. 6. The stress shadow effect after supplementing 500 psi to each principal stress.

Fig. 7. Critical threshold for the stress shadow magnitude to induce slip.

The application of 500 psi for each principal stress is shown in Fig. 6. Since the initial stress state in the Cane Creek play is far from critical, the shear stress on each fracture plane does not reach the critical value despite the additional stress added to the system. Figure 7 illustrates the critical threshold for the stress shadow magnitude to induce slip. We demonstrate that adding 1,650 psi in the S_Hmax direction will transition the reservoir to a failure mode. 

STRESS SHADOW ASSESSMENT FROM PLANAR FRACTURE MODELING 

We utilized a "planar fracture modeling" technique to simulate the poroelastic response and the stress shadow distribution (McClure et al., 2020). Our model is based on the Dvory et al. (2024) fracture propagation investigation that formulated a methodology for constraining fracture length. The basis of the planar fracture model is tensile, not a shear failure. Our slippage analysis strictly relates to the poroelastic and stress shadow changes obtained from the numeric simulation.  

A detailed description of our modeling strategy and results is shown in Dvory et al. (2024). Our simulation process began with calibration, using data from Stage 11 and the associated production dataset. Subsequently, we conducted a sensitivity analysis on the fracture toughness profile and evaluated how varying cluster spacing influences fracture length. Figure 8 shows the poroelastic effect in the S_hmin direction before the Stage 11 shutdown. 

Fig. 8. Poroelastic stress change along the Shmin direction before stage 11 shutdown in well State 16-2 Ln (For additional simulation parameters, see Dvory et al. 2024).

Our results show that the maximum stress shadow develops close to the well and reaches ~232 psi. This value, alone, would not be sufficient to induce slip. Figure 9 illustrates the stress shadow magnitude along the minimum horizontal stress orientation at the stage shutdown. The total stress change comprises the poroelastic effects and the remote mechanical stress associated with fracture opening. The maximum stress shadow at shutdown is around 850 psi in the near-field (red in Fig. 9). The lateral stress change in the Cane Creek unit is less than 100 psi. The latter implies that far-field fractures are less likely to slip since the stress change is below 1,650 psi (Fig. 7). 

Fig. 9. Stress shadowing along the Shmin direction before stage 11 shutdown in well State 16-2 Ln. The stress shadow here includes the poroelastic and the fracture opening effects (For additional simulation parameters, see Dvory et al. 2024).

DISCUSSION  

Our findings highlight the geomechanical behavior of the Cane Creek play, emphasizing the intricacies involved in triggering natural fractures. While traditional perspectives have underscored the role of natural fractures in productivity, our investigation corroborates the emerging consensus that the stimulation of such fractures may not be inherently linked to productivity. Instead, this study highlights the role of fracture propagation dynamics' criticality and stress shadow effects in fracture stimulation. 

Hydraulic fracture propagation studies, like those from the Eagle Ford shale and Permian basin, shed light on the directional preferences of fracture swarms and underscore the importance of stress orientation in influencing fracture trajectories (Raterman et al., 2019; Gale et al., 2021; Ugueto et al., 2019a; 2019b). Our analysis of the Cane Creek play extends these insights, suggesting that pore pressure distribution and stress shadow propagation are decisive factors in the stimulation process. The localized pore pressure effects and the potential for slip triggered by stress shadows provide a nuanced understanding of fracture behavior in tight reservoirs. 

The planar fracture modeling approach adopted in this study further advances our understanding by providing a granular view of the shear potential of natural fractures and faults (Dvory et al., 2024; Dvory and McLennan 2024). The sensitivity analysis of stress shadow effects, incorporating both poroelastic and fracture opening components, reveals that the stress state in the Cane Creek play is not inherently conducive to slip without significant stress alteration. This observation aligns with the documented behavior in other basins, like the Fort Worth basin (Kuang et al., 2017), offering a comparative framework for assessing the role of stress shadows in different geological settings. 

CONCLUSIONS  

This study of the Cane Creek play within the Paradox formation has brought to light several insights regarding the role of natural fractures and faults in tight oil plays. We demonstrated that the stimulation of natural fractures, traditionally believed to be a cornerstone for well productivity, may not directly correlate with enhanced production. Instead, the critical factors appear to be the directionality of fracture propagation and the intricate dynamics of stress shadow effects. 

Our examination of fracture propagation behavior suggests that while hydraulic fracturing operations successfully generate fracture swarms, their productivity may hinge on localized pore pressure rise and the ability to manipulate stress shadow propagation effectively (which is aspirational only). Our findings underscore the limited potential for distilling natural fracture stimulation under the current geomechanical state of the Cane Creek play, as significant alterations in stress conditions are required to initiate slip-on fracture planes. 

Planar fracture modeling has yielded a nuanced understanding of the shear potential across adjacent, remote natural fractures and faults, indicating that the existing stress state is less than optimal for inducing slip without substantial stress modification in this geologic setting. This aligns with behavior observed in other basins and provides a comparative perspective on the role of stress shadows in various geological contexts. 

Considering these findings, we advocate for a revised approach to hydraulic fracturing that prioritizes a detailed assessment of stress states and fracture propagation dynamics. Such an approach could enable better stress shadow management and, consequently, improve the predictability and efficiency of fracturing operations, leading to more sustainable and economically sound resource extraction. 

Further research should quantify the intricate relationship between pore pressure dynamics, stress shadow development, and fracture orientation. Understanding these relationships is key to incrementally improving stimulation techniques in unconventional plays, potentially altering the course of hydraulic fracturing strategies to meet the dual goals of economic viability and environmental stewardship. 

ACKNOWLEDGMENTS 

This article is based on paper ARMA (American Rock Mechanics Association) 24-1158, presented at the 58th U.S. Rock Mechanics/Geomechanics Symposium held in Golden, Colo., USA, June 23-26, 2024. The study referred to in this article was funded by the DOE project: Improving Production in the Emerging Paradox Oil Play DE-FE0031775. The authors thank Mark McClure for his useful comments and the ResFrac academic.  

References 

• Baars, D. L. (1966). Pre-Pennsylvanian Paleotectonics—Key to Basin Evolution and Petroleum Occurrences in Paradox Basin, Utah and Colorado. AAPG Bulletin, 50. https://doi.org/10.1306/5D25B70D-16C1-11D7-8645000102C1865D 
• Dvory, N. Z., McLennan J. D. & Singh, A. (2024), in review. Avoiding the Salts: Strategic Fracture Propagation Management for Enhanced Stimulation Efficiency in the Cane Creek Play. SPE/AAPG/SEG Unconventional Resources Technology Conference 2024.  
• Dvory, N. Z., & McLennan J. D. (2024), in review. Stress Field Dynamics and Fault Slip Potential in the Paradox Basin. Journal of Geophysical Research: Solid Earth.  
• Gale, J. F. W., Elliott, Rysak, Ginn, C. L., Zhang, N., Myers, R. D., & Laubach, S. E. (2021). Fracture Description of the HFTS-2 Slant Core, Delaware Basin, West Texas. Proceedings of the 9th Unconventional Resources Technology Conference. Unconventional Resources Technology Conference, Houston, Texas, USA. https://doi.org/10.15530/urtec-2021-5175 
• Gale, J. F. W., Elliott, S. J., & Laubach, S. E. (2018). Hydraulic Fractures in Core From Stimulated Reservoirs: Core Fracture Description of HFTS Slant Core, Midland Basin, West Texas. Proceedings of the 6th Unconventional Resources Technology Conference. Unconventional Resources Technology Conference, Houston, Texas, USA. https://doi.org/10.15530/urtec-2018-2902624 
• Kuang, W., Zoback, M., & Zhang, J. (2017). Estimating geomechanical parameters from microseismic plane focal mechanisms recorded during multistage hydraulic fracturing. GEOPHYSICS, 82(1), KS1–KS11. https://doi.org/10.1190/geo2015-0691.1 
• Lund Snee, J. E., & Zoback, M. D. (2020). Multiscale variations of the crustal stress field throughout North America. Nature Communications, 11(1), 1–9. https://doi.org/10.1038/s41467-020-15841-5
• McClure, M., & Kang, C. (2018). ResFrac Technical Writeup. http://arxiv.org/abs/1804.02092 
• McClure, M., Picone, M., Fowler, G., Ratcliff, D., Kang, C., Medam, S., & Frantz, J. (2020). Nuances and Frequently Asked Questions in Field-Scale Hydraulic Fracture Modeling. 1, 1–19. https://doi.org/10.2118 /199726-ms 
• Raterman, K. T., Farrell, H. E., Mora, O. S., Janssen, A. L., Gomez, G. A., Busetti, S., McEwen, J., Davidson, M., Friehauf, K., Rutherford, J., Reid, R., Jin, G., Roy, B., & Warren, M. (2017). Sampling a stimulated rock volume: An Eagle Ford example. SPE/AAPG/SEG Unconventional Resources Technology Conference 2017, 1–18. https://doi.org/ 10.15530/urtec-20172670034 
• Raterman, K. T., Liu, Y., & Warren, L. (2019). Analysis of a drained rock volume: An eagle Ford example. SPE/AAPG/SEG Unconventional Resources Technology Conference 2019, URTC 2019, 1–20. https://doi.org/10.15530/urtec-2019-263 
• Shi, S., Zhuo, R., Cheng, L., Xiang, Y., Ma, X., & Wang, T. (2022). Fracture Characteristics and Distribution in Slant Core from Conglomerate Hydraulic Fracturing Test Site (CHFTS) in Junggar Basin, Northwest China. Processes, 10(8), 1646. https://doi.org/ 10.3390/pr10081646 
• Trudgill, B. D. (2011). Evolution of salt structures in the northern Paradox Basin: Controls on evaporite deposition, salt wall growth and supra-salt stratigraphic architecture: Evolution of salt structures in the northern Paradox Basin. Basin Research, 23(2), 208–238. https://doi.org/10.1111/j.1365-2117.2010.00478.x 
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1. NO’AM ZACH DVORY is research assistant professor of civil and environmental engineering, as well as the Energy and Geoscience Institute, at the University of Utah. He holds a B.Sc. degree in earth science from Hebrew University of Jerusalem, an M.Sc. degree in geophysics from Hebrew University of Jerusalem, and a Ph.D. in fluid dynamics from Ben Gurion University of the Negev, project: Recharge and Flow. Dr. Dvory’s professional experience includes technical lab manager at I.T.M.; geologist/geophysicist at Geophysical institute of Israel; geologist and project manager at Natural Resources Development Ltd.; and CVO/chief geologist at Etgar A. Engineering Ltd. Dr. Dvory’s research interests focus on nano to reservoir scale geomechanical responses for pore pressure perturbations and thermo-chemical evolution. 
2. BRIAN MCPHERSON is USTAR professor of civil & environmental engineering, as well as the Energy and Geoscience Institute, at the University of Utah. He holds a a B.Sc. degree in geophysics from the University of Oklahoma and earned M.S. and Ph.D. degrees in geophysics from the University of Utah. Dr. McPherson’s professional experience includes hydrologist at the U.S. Geological Survey; research hydrologist in the Geophysical Research Center at New Mexico Institute of Mining and Technology; assistant professor of hydrology at New Mexico Institute of Mining and Technology; senior scientist for the  New Mexico Tech Petroleum Recovery Research Center; and associate professor of hydrology at New Mexico Institute of Mining and Technology. Dr. McPherson’s technical focus areas include groundwater and reservoir simulation, multiphase flow analysis and simulation, rock deformation, and subsurface chemically reactive transport analysis and simulation. 
3. JOHN MCLENNAN is professor of chemical engineering, as well as the Energy and Geoscience Institute, at the University of Utah. He earned a B.A.Sc. degree in geological engineering from University of Toronto, as well as an M.A.Sc. degree and a Ph.D. in civil engineering from University of Toronto. Dr. McLennan’s professional experience includes positions of increasing responsibility at TTI Geotechnical Resources Ltd., Dowell Schlumberger, TerraTek, Inc., Advantek International Corporation and ASRC Energy Services E & P Technology. He has worked on coalbed methane recovery, mechanical properties determinations, produced water and drill cuttings reinjection, as well as casing design issues related to compaction. Dr. McLennan’s recent work has focused on optimized gas production from shales and unconsolidated formations.