作者：杰西卡·怀特赛德（Jessica Whiteside），撰稿人

二叠纪盆地一项历时多年的技术研究证实，基于地面的压力信号分析能够实现水力压裂过程中裂缝行为的实时监测。这表明该方法具有动态调整作业、降低处理强度和成本的潜力。

专注于先进压力测量技术的ShearFRAC公司与Sabinal Energy（现为Mach Natural Resources的一部分）合作开展了该项目，该项目有两个相互关联的目标。第一个目标是验证地面压力分析在评估作业期间裂缝动态变化方面的有效性，从而实时了解各阶段处理措施的有效性。第二个目标是将基于地面压力分析获得的信息应用于后续井的完井设计优化。

地面压力分析是一种监测水力压裂作业过程中井下情况的方法。即使是微小的压力变化也能指示是否出现了新的裂缝，并帮助工程师测量裂缝网络的扩展情况，包括与邻近井的潜在相互作用。地面压力分析的实时性意味着作业人员可以在作业进行过程中及时发现并修正诸如压裂速率或支撑剂浓度等因素。项目团队旨在验证地面压力分析作为主要诊断工具的价值。

开发成熟领域

开发目标是二叠纪中央盆地台地中部克利尔福克组（Middle Clear Fork Formation）中一段厚度为1000英尺的水驱碳酸盐岩层，该油田是一个成熟油田，发现于20世纪50年代。ShearFRAC公司技术客户经理泰勒·西拉吉（Tyler Szilagyi）表示，该项目的出发点是假设该地层中可能存在许多未充分开采的层段，且剩余石油储量丰富。他于2月5日在德克萨斯州伍德兰兹举行的2026年SPE水力压裂技术会议上介绍了该项目的研究成果。

鉴于该油田的成熟度，该项目的一个关键驱动因素是避免过度开采，因为过度开采可能会增加先前开发层段发生不必要的水突破的风险。

“该项目的目标实际上是通过钻探和完井最经济高效的油井，最大限度地提高资本效率，这些油井是针对成熟注水单元中那些未开发区域量身定制的。”Szilagyi 先生说。

该项目于2021年至2024年分几个阶段实施。第一阶段钻探并完井了首批水平井，以验证未覆盖区域的生产潜力。第二阶段的重点是验证地面压力分析与其他诊断方法在监测裂缝行为方面的准确性。该阶段的经验教训被应用于第三阶段，用于开发和实施下一批井的最佳完井设计。

验证该技术

在第二阶段，A井场钻探了两口1英里长的水平井，并采用单点进入式连续压裂系统完成作业。为了监测压力变化，团队在井口安装了压力传感器。

由于一项关键目标是验证地面压力分析在追踪裂缝活动方面的性能，并将其与其他方法进行比较，因此他们为其中一口井配备了额外的诊断工具。这些工具通常提供在作业结束时进行分析的数据。它们包括用于空间裂缝测绘的高分辨率微地震阵列、用于流体注入变化的化学示踪分析以及地质测井解释。

该团队的测试发现，地表压力诊断与其他独立测量结果（包括裂缝事件计数、应力数据、生产数据和其他因素）之间存在很强的相关性。例如，归一化事件计数与通过微震阵列获取的应力数据以及通过地表压力分析获取的类似数据之间存在很强的相关性，这进一步证实了这些技术在检测裂缝发生时间和量化其强度方面的价值。

“通过这个项目，我们能够进一步验证我们的诊断方法，其与微震和示踪剂回收结果具有非常高的相关性，”Szilagyi先生说。“这证实了它作为实时诊断方法的可靠性。”

优化设计

该团队对A井场两口井的不同完井设计组合进行了评估，测试了各种段间距、流体装载量和支撑剂装载量，以及一些仅使用酸液的段。“我们希望真正了解和评估多种设计，以期最大限度地提高这些水平段的效率，”Szilagyi先生说。

地面压力分析使工程师能够从另一个角度观察压力，从而了解压裂作业过程中发生的关键因素，例如压裂事件的频率及其振幅或相对大小。Szilagyi 先生表示，由于该技术能够实时测量和显示这些因素，因此团队可以更好地评估每个阶段的有效性，并将不同的设计进行比较。

项目团队表示，注入更多流体和支撑剂的阶段表现出更高的总有效性——这符合预期，但并不直接等同于效率的提高。然而，他们深入分析了有效性数据，根据注入的清洁流体体积对结果进行标准化处理，发现处理强度较低的设计方案在注入量较低的情况下也能达到相似甚至更高的效率。

“由于我们真正关注的是这些油井的经济效益，力求尽可能提高效率，因此我们可以将效率除以每口井注入的净流体体积，从而找到效率开始下降的临界点，”Szilagyi 先生说道。“这使我们能够为该区域设计出最佳方案，采用中等井距，并在设计中采用中等流体和支撑剂用量。”

他们将“最佳匹配”设计应用于该项目第三阶段B井场钻探的两条8500英尺水平井，成功地将流体用量减少了28%，支撑剂用量减少了30%。这些减少使得完井成本相对于项目早期阶段有所降低。

“从第一阶段到第三阶段，我们成功地将每英尺的竣工成本降低了60%，这相当可观。即使从第二阶段到第三阶段，我们也成功地将每英尺的竣工成本降低了30%。”Szilagyi先生说道。

此外，第三阶段累计石油产量较第二阶段增长了28%。与此同时，产水量下降了19%，Szilagyi先生表示，这表明改进后的完井设计有助于最大限度地减少与邻近注水井的相互作用。总体而言，B井场钻井和完井的成本降低了18%。Szilagyi先生认为，地面压力衍生的裂缝测量数据帮助团队精准地发现了设计中的不足之处。

“通常来说，越大越好的设计往往会带来收益递减，而我们通过地面压力信号分析发现了这一点，并最大限度地提高了这些油井的资本效率，”他说道。“这项技术的应用已经证明了其经济价值。”

扩展应用

Szilagyi 先生表示，Middle Clear Fork 案例研究证明，通过表面压力分析测量的结果具有物理意义。

项目团队认为，表面压力分析既可以作为实时控制工具，也可以作为智能完井设计的培训平台。

“由于我们能够实时操作这个平台，因此我们可以实现很多决策流程的自动化。这取决于操作员和具体区域。但是，我们可以向系统中输入不同的基于例外情况的规则，以便对不同的情况做出适当的响应，”Szilagyi 先生说道。

他指出，可以将表面压力数据纳入多元分析，例如，用于对“假设”设计场景进行预测建模。“未来发展的方向在于真正实时利用这些测量数据，从静态设计过渡到实时自适应完井，并利用人工智能和机器学习等其他工具，使我们的作业更具预测性。” DC

更多信息，请参阅 SPE 230631，“从过度刺激到优化：基于地面压力的实时自适应完井工作流程”。

By Jessica Whiteside, Contributor

A multi-year technical program in the Permian Basin confirmed that surface-based pressure signal analysis can enable real-time monitoring of fracture behavior during hydraulic fracturing. This shows the potential to adjust operations on the fly and reduce treatment intensity and costs.

ShearFRAC, which specializes in advanced pressure measurement technologies, collaborated with Sabinal Energy (now part of Mach Natural Resources) on the project, which had two interrelated goals. The first was to confirm the validity of surface pressure analysis for evaluating fracture dynamics during active operations to gain real-time insights on the effectiveness of stage-level treatments. The second goal was to apply surface pressure-derived insights to optimize completion designs for subsequent wells.

Surface pressure analysis is a way to monitor what is happening downhole during hydraulic fracturing. Even small changes in pressure can indicate whether a new fracture has occurred and help engineers measure the growth of the fracture network, including potential interaction with offset wells. The real-time nature of surface pressure analysis means crews can flag the need for corrections to factors such as rate or proppant concentration while an operation is under way. The project team aimed to prove the value of surface pressure analysis as a primary diagnostic tool.

Tapping a mature field

The development target was a 1,000-ft-thick interval of waterflooded carbonate in the Middle Clear Fork Formation of the Permian’s Central Basin Platform, a mature field discovered in the 1950s. The project began with the hypothesis that there could be many underswept intervals left within this formation with high remaining oil in place, said Tyler Szilagyi, Technical Account Manager at ShearFRAC. He presented findings from the project at the 2026 SPE Hydraulic Fracturing Technical Conference in The Woodlands, Texas, on 5 February.

Given the maturity of the field, a key driver for the project was to avoid over-stimulation, which could raise the risk of undesirable water breakthrough from previously developed intervals.

“The objective for this project was really to maximize the capital efficiency by drilling and completing the most economically productive wells possible, tailored to those underdeveloped zones within that mature waterflood unit,” Mr Szilagyi said.

The project was executed in several phases from 2021 through 2024. Phase 1 saw initial horizontal wells drilled and completed to confirm the production potential of underswept areas. Phase 2 focused on validating the accuracy of surface pressure analysis against other diagnostic approaches for monitoring fracture behavior. Lessons from this phase were then applied in Phase 3 to develop and implement optimal completion designs for the next set of wells.

Validating the technology

In Phase 2, a pair of 1-mile horizontal wells were drilled from Pad A and completed with a single-point-entry coil-frac system. To monitor pressure variations, the team equipped the wellhead with a pressure transducer.

Because a key goal was to validate the performance of surface pressure analysis against other methods for tracking fracture activity, they equipped one of the wells with additional diagnostic tools. These tools typically provide data that is analyzed at the end of an operation. They included high-resolution microseismic arrays for spatial fracture mapping, chemical tracer analysis for fluid placement variation, and geological log interpretation.

The team’s testing found strong correlations between the surface pressure diagnostics and these other independent measurements with respect to fracture event counts, stress data, production data and other factors. For example, there were strong correlations between normalized event counts and stress data acquired through microseismic arrays and similar data captured through surface pressure analysis, reinforcing the value of these techniques for detecting when fractures occur and quantifying their intensity.

“Through this project, we were able to further validate our diagnostic with very high correlation to microseismic and tracer recovery,” Mr Szilagyi said. “This confirms its reliability as a real-time diagnostic.”

Optimizing design

The team evaluated different completion design combinations across the two Pad A wells, testing a variety of stage spacings, fluid loadings and proppant loadings, as well as some stages with acid-only designs. “We wanted to really understand and evaluate multiple designs, targeting maximum effectiveness for these laterals,” Mr Szilagyi said.

Surface pressure analysis allows engineers to look at pressure through another lens to understand key components that occur during frac operations, such as the frequency of fracturing events and their amplitude or relative size. Since the technology allows these factors to be measured and displayed in real time, it enables teams to better evaluate the effectiveness of each stage and compare one design with the next, Mr Szilagyi said.

Stages with larger volumes of fluid and proppant pumped showed higher total effectiveness – an expected result but one that does not directly equate to improved efficiency, according to the project team. However, they dug deeper into the effectiveness data, normalizing the results by clean fluid volume injected, and determined that designs with less intense treatment achieved similar or greater efficiency with lower injected volumes.

“Since we’re targeting really the economics of these wells, trying to be as efficient as possible, what this allows us to do is take that effectiveness, divide it by the clean volume that we’re injecting into each of these wells, and look for that rollover point where we start to lose some of this effectiveness,” Mr Szilagyi said. “This allowed us to come up with the optimal design for this area, with a medium spacing and some medium fluid and proppant loadings within that design.”

They applied their “best fit” design to two 8,500-ft laterals drilled on Pad B in Phase 3 of the project and succeeded in reducing fluid volumes by 28% and proppant by 30%. Those reductions contributed to lower completion costs relative to earlier phases of the project.

“From Phase 1 to Phase 3, we were able to reduce our completion cost per foot by 60%, which is quite significant. And then even from Phase 2 through to Phase 3, we were able to reduce that completion cost per foot by 30%,” Mr Szilagyi said.

Additionally, cumulative oil production in Phase 3 increased by 28% relative to Phase 2. At the same time, water production dropped by 19%, Mr Szilagyi said, indicating that the refined completion design had helped to minimize interaction with offset injecting wells. Overall, they achieved an 18% reduction in the dollar per barrel of oil equivalent spent on drilling and completing the Pad B wells. Mr Szilagyi credits the surface pressure-derived fracture measurements for helping the team to pinpoint design inefficiencies.

“The bigger-is-better designs typically hit diminishing returns, and we were able to identify this through our surface pressure signal analysis and maximize these wells for capital efficiency,” he said. “There’s proven economic value through the implementation of this technology.”

Expanding applications

The Middle Clear Fork case study is evidence that what is measured through surface pressure analysis is physically significant, Mr Szilagyi said.

The project team sees a role for surface pressure analysis as both a real-time control tool and a training platform for intelligent completion design.

“What we’re able to do through this platform, since we’re doing it in real time, is automate a lot of those decision-making workflows. It’s dependent on the operator and area. However, we can input different exception-based rules into the system to respond to different conditions appropriately,” Mr Szilagyi said.

He noted that surface pressure data could be incorporated into multivariate analysis to enable predictive modeling of “what-if” design scenarios, for example. “The path forward is really utilizing these measurements in real time, transitioning from static designs to real-time adaptive completions, and using other tools like AI and machine learning to be more predictive with our operations.” DC

For more information, please see SPE 230631, “From Overstimulation to Optimization: A Surface Pressure-Driven Workflow for Real-Time Adaptive Completions.”