作者：Stephen Whitfield，高级编辑

与油田的其他行业一样，水力压裂的关键在于提高性能，建造新压裂船队和相关设备的公司在设计时必须考虑到性能。增加马力仍然是压裂服务提供商最吹捧的功能 - 2,500 至 3,000 马力的拖车曾经很常见，但较新的系统，例如 NexTier Completion Solution 的 Emerald 电动压裂 (e-frac) 系统，可以单个拖车可输出高达 6,000 马力的功率。但马力并不是帮助提高压裂作业性能的唯一方法。 

“你只能为 5 英寸发动机提供这么多马力。套管; 你只能承受这么多的压力。你不能一直把它调到 11，也不应该。”NexTier 数字运营副总裁 Doug Taylor 说道。“差异化因素在于我们提供的设备的可靠性以及帮助操作员做出实时战略决策。”

帮助操作员在决策中获得优势意味着开发可以帮助他们提高利润的工具，无论是通过节省燃料成本、减少排放还是减轻可能增加非生产时间或导致井下严重后果的功能障碍。对于服务提供商来说，这可能意味着改进市场上已有的系统或创建新的工作流程来帮助他们发现潜在问题。 

无论他们采取什么步骤，目标都是释放新的效率，以帮助运营商最大限度地提高压裂性能。 

“基本上，我们如何获得一种工具来帮助这些压裂公司和运营商取得成功？”GeoDynamics 的高级运营经理 Zach Wade 说，GeoDynamics 是一家专门从事完井和废弃工具开发的技术开发商。“这些人有大量的劳动力前往这些压裂现场，进行大量的操作，大量的卡车，大量的拖车。他们有足够的成本和物流需要管理。如果我们能够走出去，为他们提供合适的工具，他们就能获得丰厚的利润，我们也能获得丰厚的利润。” 

采用电子压裂的挑战

随着行业碳足迹的日益受到关注，电子压裂船队已成为一种潜在的有价值的工具。这些系统使用在模块化天然气发电机上运行的电动压力泵，而不是传统压裂系统的柴油驱动泵。发电机使用压缩天然气、液化天然气或现场生产的现场天然气发电，否则这些天然气可能会被燃烧。这可以节省燃料并减少碳排放。

“使用双燃料时，您总会有一些与您的操作相关的柴油，具体取决于您压裂油井的方式、您拥有的设备数量以及客户对某些设备的要求。 NexTier 战略与数字开发副总裁 Ben Dickinson 说道。“发动机将使用任何天然气与柴油组合，以最优化的方式运行。因此，总是需要一系列柴油。另一方面，电力由 100% 天然气发电提供燃料。”

虽然电子压裂船队的碳减排潜力更大，但其物流和建造成本使其成为运营商难以接受的难题。例如，NexTier 于 2022 年推出了 Emerald，这是其首款电子压裂产品，之后于 2023 年第四季度与 Patterson-UTI 合并。然而，截至 2024 年 2 月，NexTier 的活跃压裂船队中只有一个是 Emerald 船队。该公司预计到 2024 年中期，运营电力将达到约 140,000 马力。其大部分运行的车队都是 Tier IV 双燃料车队，使用柴油和天然气燃料发动机的组合来运行。

“如果运营商今天想要订购新建的电动车队，可能需要 12 到 18 个月才能交付，因为我们必须为其构建一个包。然后在电力方面，与其说是对设备的挑战，不如说是对发电的挑战。与内置发电的 Tier IV 电站相比，这是额外的成本。”泰勒先生说。 

更广泛采用电动压裂车队的另一个障碍是仍然悬而未决的问题，即谁为电动车队提供动力的基础设施买单——运营商还是服务公司？NexTier 等服务公司希望运营商提供电力资金，因为这是一项巨大的前期成本。然而，运营商希望压裂供应商提供发电服务，因为从历史上看，压裂供应商也为柴油和双燃料车队使用的发动机付费。 

目前，第三方可能是缓解这一问题的关键，通过提供基础设施来为运行电子压裂系统的发电机供电。例如，Voltagrid 是一家交钥匙电力公司，为工业项目提供移动电网；该公司正在为 Emerald Frac Fleet 提供移动发电装置，并在与 Seneca Resources 在 Marcellus 页岩进行压裂作业期间将其租赁给 NexTier。运营商或压裂公司不必花钱自行建设基础设施并为潜在的电子压裂项目保留基础设施，而是可以花更少的钱从第三方提供商处租赁。 

“第三方提供商将对每个人都有价值。“我们拥有电力完成设备的地方就会出现这些公司，但他们可以向我们出租发电，或者他们可以将发电出租给运营商，这可以帮助运营商和服务提供商，”泰勒先生说。 

套管变形预测

操作人员在水力压裂中面临的最大挑战之一是套管变形。沙特阿美公司石油工程专家 Arshad Waheed 指出，套管变形可能发生在沿横向的任何一点，影响油井的产量和井眼可达性，在某些情况下，还会导致油井失控。 

2021 年，沙特阿美公司开展了一项研究，开发和测试操作工作流程，帮助操作员更好地预测套管变形情况。避免油井管道变形将节省高风险区域的压裂成本，帮助运营商保持油井的完整性和安全性，并确保生产不受影响。 

“当您观察套管变形时，它会影响油井产能，有时还会影响油井的完整性，具体取决于变形的类型。如果我们能够审视现有的工作流程，这可能有助于对这些事情产生积极的影响，”瓦希德先生说。2 月 7 日，他在德克萨斯州伍德兰举行的 2024 年 SPE 水力压裂技术会议上讨论了这项研究。 

沙特阿美公司通常在其压裂作业中部署两种类型的完井管柱：套管固井完井和裸眼多级（OH-MSF）完井。对于两种完井管柱类型，操作员执行相同的初步应力分析，以确定井况是否有利于变形套管。首先，确定水力压裂过程中预期的井底处理压力和轴向载荷是否会超过下部完井的额定值，然后对上部完井的压力进行类似的评估。 

瓦希德先生表示，由于多种原因，这种方法不足以评估变形风险。首先，它忽略了套管变形背后的其他记录原因，即井斜、井方位角、狗腿严重程度、管道集中、固井作业质量和提供的压裂处理类型。它还没有考虑到 OH-MSF 完井所面临的独特挑战，特别是水平井裸眼尺寸的不均匀性。 

施加在生产封隔器上的力随着井下压力和温度的变化而变化。这些变化使得连接到封隔器的油管收缩和膨胀。如果管道是固定的，或者达到移动极限，则任何额外的轴向载荷都可能使管道永久变形（如果载荷超过安全操作极限）。在 OH-MSF 完井中，由于孔径不均匀，多个中间封隔器串联运行，预计管道上的施加力和弯曲应力会发生显着变化。充分的应力分析必须考虑每个中间封隔器。

“在裸眼完井中，我们运行这些封隔器，这些封隔器之间的间距长度可能会发生变化。孔的大小始终变化。如果更改孔尺寸，每个部分的载荷都会发生变化。你要处理多个孔、多个封隔器、不同类型的流体，你的排量不同，很多事情都是不同的。那么，我们要为此做哪些设计呢？尚未完成包含此在内的分析类型，也没有报告变形的可能性，”他说。 

该研究测试了阿美公司开发的两种新的分析工作流程——一种用于水泥衬管，另一种用于 OH-MSF。对于固井衬管，使用商业管分析软件来运行井模型，其中包含诸如孔径、孔扩大严重程度、孔隙度、地层渗透率、孔偏差和方位角、超声波水泥粘结测井、狗腿严重程度和岩性等变量。然后，该软件会输出井中任何给定点的衬管变形风险评估，并提供突出显示该风险的颜色代码。 

对于 OH-MSF 完井，工作流程首先审查较低的完井等级、轴向载荷、计划的封隔器移动、封隔器间距、孔尺寸、微狗腿严重程度、完井每个阶段的预期时间、油藏压力和井底温度。如果这些参数中的任何一个低于管材的设计系数（衡量管材破裂前可以承受的特定参数最大数量的比率），则对该井进行标记，并对操作员和压裂公司进行标记将相应调整完成计划。 

阿美公司使用八口水平井（每种完井类型各四口）的历史数据测试了固井完井和 OH-MSF 的工作流程。对于使用固井工作流程建模的其中一口井，水泥粘结测井有助于正确评估水泥通道，瓦希德先生表示，与传统工作流程相比，这使操作员能够更好地了解水泥通道的存在或不存在。测井数据将使操作员能够在安全区域选择射孔，避免水泥通道交叉，从而最大限度地减少变形的可能性。 

一个这样的项目模型是一个 4 英寸 的单孔完井。生产孔尺寸为 5 7/8 英寸的水平井中配有多级压裂工具和封隔器的油管和衬管。上部完井由 4 ½ 英寸组成。管和 7 英寸。压缩永久变形套管锚。下部完井采用了 10 个裸眼机械封隔器，部署在 4 ½ x 7 英寸的井筒上。衬管吊架。 

使用商业软件作为实施工作流程的示例，在两个阶段（阶段 4 和阶段 5）进行井筒应力分析。增产期间的操作条件是根据压裂液泵送设计进行建模的，假设完井作业期间可能会出现拉伸、压缩、破裂和塌陷等最坏情况。工作流程生成的油管应力分析模型显示，在理想条件下，增产作业的第 4 阶段和第 5 阶段不会出现套管破裂或塌陷的可能性。

阿美公司采用这些工作流程来分析其压裂作业中套管变形的风险。瓦希德先生表示，该研究说明了工作流程在压裂作业完成之前识别套管变形问题的可能性的有效性。他还希望发表这项研究能够鼓励工程师进一步研究影响完井或管柱故障的各个变量和井下工具的影响。 

“这些新的工作流程是裸眼井和套管井的实用指南，我们正在确定可能导致管道变形的条件，更好地了解可以帮助我们避免这些情况的因素，”他说。 

提高可配置性以满足不同需求

今年 2 月，GEODynamics 宣布推出 EPIC Precision 和 EPIC Flex 一次性顶部装载喷枪系统，旨在简化电缆作业。 

这些喷枪经过定制，可满足操作员的需求。GEODynamics 表示，EPIC 枪的开关是首款能够配置为快速射击模式的数字开关，有助于操作员减少非生产时间。Precision 技术提供可重复使用的潜艇，配有可配置和可编程的开关和拍摄面板，这有利于需要现成系统的操作员。 

Flex 技术适合那些想要将枪支系统的各种组件与他们手头可能已有的其他组件一起使用的操作员 - 开关和装药的设计与开源软件架构兼容，这意味着它们可以使用任何第三方程序进行编程。

“我们看到的是，公司希望将其有线线路定制为他们想要的任何东西，”韦德先生说。“如果你想把A公司的遥测数据放进去，并且想用我们的费用，你就可以做到。如果他们希望在他们的系统中收取其他人的费用，而您希望我们进行遥测，我们希望在那里拥有这种可互换的功能。如果我们支持有线传输，我们就不能只拥有一套火炮系统。我们必须能够给他们选择。”

2023 年中期，这些枪在德克萨斯州米尔萨普的 GEODynamics 技术评估中心进行了实验室测试，每个系统进行了 100 次实弹射击。2023 年 12 月下旬至 2024 年 1 月上旬，与马塞勒斯页岩一位未透露姓名的操作员合作进行的现场试验产生了类似的结果——Precision 和 Flex 枪均成功进行了 200 次实弹射击。然而，韦德先生表示，该公司在将枪支运送到现场测试地点时遇到了问题。 

“我们发现每辆卡车上需要配备的设备比试验时配备的设备还要多，”他说。“我们只能在一辆卡车上装 50 支枪，而且将它们运送到德克萨斯州以外的地区并不总是很经济。我们必须创建一个板条箱系统，使我们能够在一辆卡车上放置多达 100 支枪，与我们现有的 50 支枪相比，这可以节省一半的占地面积。”

EPIC 火炮已被巴肯的运营商使用，该公司计划于 2024 年上半年开始与二叠纪盆地的运营商合作。为蒙特尼的运营商提供该系统的谈判也在进行中今年页岩。直流  

By Stephen Whitfield, Senior Editor

As with other sectors in the oilfield, hydraulic fracturing is all about pushing performance, and companies building new frac fleets and associated equipment must design them with performance in mind. Increased horsepower continues to be a top touted feature by frac service providers – where 2,500- to 3,000-hp trailers were once commonplace, newer systems, such as NexTier Completion Solution’s Emerald electric frac (e-frac) system, can feature up to 6,000 hp on a single trailer. But horsepower is not the only way to help improve performance in frac operations.  

“You can only put so much horsepower down a 5 ½-in. casing; you can only get so much pressure. You can’t turn it up to 11 all the time, nor should you,” said Doug Taylor, VP of Digital Operations at NexTier. “Where the differentiators come in is in the reliability of the equipment we’re providing and in helping the operator to make real-time strategic decisions.”

Helping operators gain an edge in decision making means developing tools that can help them improve at the margins, whether it’s through savings in fuel costs, a reduction in emissions or mitigating the dysfunctions that can increase nonproductive time or lead to serious consequences downhole. For the service providers, this could mean improving on systems that are already in the market or creating new workflows to help them spot potential issues. 

Whatever steps they are taking, the name of the game is to unlock new efficiencies in order to help operators maximize their frac performance. 

“Basically, how are we going to get a tool out there that can help make these frac companies and these operators successful?” said Zach Wade, Senior Operations Manager at GeoDynamics, a technology developer that specializes in completions and abandonment tools. “These guys have a lot of labor going out to these frac sites, a lot of operations, a lot of trucks, a lot of trailers. They’ve got enough costs and logistics to manage. If we can go out there and give them the right tools, they’re making good margins and we’re making good margins.”  

Challenges in e-frac adoption

With an increasing focus being placed on the industry’s carbon footprint, e-frac fleets have become a potentially valuable tool. These systems use electrically powered pressure pumps running on modular natural gas generators, instead of the diesel-driven pumps of a conventional frac system. The generators make electricity using CNG, LNG or field gas produced onsite that may otherwise be flared. This can lead to fuel savings and a carbon emissions reduction.

“With dual fuel, you’re always going to have some diesel associated with your operation depending on how you’re fracking the well, depending on how much equipment you have out there, and depending on what the customers require of some of the equipment,” said Ben Dickinson, VP of Strategy and Digital Development at NexTier. “The engine will use whatever natural gas versus diesel combination to operate in the most optimum way. So, there’s always going to be a range of diesel that’s going to be required. On the other hand, electric is fueled by 100% natural gas power-gen.”

While the carbon reduction potential is larger with e-frac fleets, the logistics and cost of building them make their adoption a trickier pill for operators to swallow. For instance, NexTier launched Emerald, its first e-frac offering in 2022, prior to its merger with Patterson-UTI in Q4 2023. However, as of February 2024, only one of NexTier’s active frac fleets is an Emerald fleet. The company expects to be operating around 140,000 electric horsepower by mid-2024. The majority of its fleets running are Tier IV dual-fuel fleets, which use a combination of diesel and natural gas-fueled engines to operate.

“If an operator wants to order a newbuild electric fleet today, it can be 12 to 18 months before it’s delivered because we have to build a package for it. Then on the electric side, it’s not as much a challenge on the equipment as it is a challenge on delivering the power generation. That’s an additional cost compared with a Tier IV spread that has built-in power generation,” Mr Taylor said. 

Another hurdle to wider adoption of e-frac fleets is the still unsettled question of who’s paying for the infrastructure that powers an electric fleet – operators or service companies? Service companies like NexTier want the operator to provide the capital for electricity because it is a significant upfront cost. However, the operator wants the frac provider to provide for the power generation because, historically, frac providers also pay for the engines used in diesel and dual-fuel fleets. 

For now, third parties may hold the key to alleviating this issue, by providing the infrastructure to power the generators running the e-frac system. Voltagrid, for example, is a turnkey power company that supplies mobile power grids for industrial projects; it is providing mobile power generation units for the Emerald Frac Fleet and leasing it to NexTier over the course of a frac job with Seneca Resources in the Marcellus Shale. Instead of an operator or a frac company spending the money on building the infrastructure themselves and keeping it on hold for potential e-frac projects, they can spend less money to lease from a third-party provider. 

“The third-party providers are going to be valuable for everyone. You have these companies popping up where we have the electrical completions equipment, but they can lease us the power generation, or they can lease the power generation to the operator, and that could help both the operator and the service provider,” Mr Taylor said.  

Casing deformation prediction

One of the biggest challenges operators face in hydraulic fracturing is casing deformation. Arshad Waheed, Petroleum Engineering Specialist at Saudi Aramco, noted that casing deformation can happen at any point along the lateral, affecting the well’s production and wellbore accessibility and, in some instances, result in a loss of well control.  

In 2021, Saudi Aramco undertook a study to develop and test operational workflows that could help the operator better anticipate instances of casing deformation. Avoiding pipe deformation on a well will save fracturing costs across high-risk areas, help the operator maintain well integrity and safety, and ensure production is not jeopardized. 

“When you’re looking at casing deformation, it impacts the well productivity and sometimes the well’s integrity, depending on the type of deformation. If we can look at the workflows we have, that would probably help affect these things positively,” Mr Waheed said. He discussed the study at the 2024 SPE Hydraulic Fracturing Technology Conference in The Woodlands, Texas, on 7 February. 

Aramco typically deploys two types of completion strings on its frac jobs: cased-hole cemented completions and open-hole multistage (OH-MSF) completions. For both completion string types, the operator performs the same preliminary stress analysis to determine if the well conditions are favorable for deformed casing. First, it determines whether the bottomhole treating pressures and axial loads expected during hydraulic fracturing will exceed the ratings of the lower completion, followed by a similar evaluation of the pressures in the upper completion. 

Mr Waheed said that this methodology was an inadequate means of assessing deformation risk for a number of reasons. First, it ignores other documented causes behind casing deformation – namely, well deviation, well azimuth, dogleg severity, pipe centralization, cement job quality and the type of frac treatment provided. It also does not account for the unique challenges faced with OH-MSF completions, particularly the non-uniformity of the open-hole size in a horizontal well. 

The forces applied on a production packer changes as the pressures and temperatures change downhole. These changes make the tubing connected to the packer contract and expand. If the tubing is fixed, or if it reaches the movement limit, any additional axial load could permanently deform the tubing if the load exceeds the safe operational limit. In an OH-MSF completion, since the hole size is not uniform, multiple intermediate packers are run in tandem, and significant variations in applied forces and bending stresses are expected on the pipe. An adequate stress analysis must account for each of the intermediate packers.

“In open-hole completions, we’re running these packers, and the lengths of spacing between those packers may change. The hole size varies all the way through. If you change the hole size, the loads are changing in every section. And you’re dealing with multiple holes, multiple packers, different types of fluids, your displacement is different, a lot of things are different. So, what are we trying to do to design for that? The type of analysis that incorporates this is not done, and the potential for deformation is not reported,” he said.  

The study tested two new analysis workflows Aramco developed – one for cemented liners and one for OH-MSF. For the cemented liners, a commercial tubular analysis software was used to a run a model of the well incorporating variables like hole diameters, hole enlargement severity, porosity, formation permeability, hole deviation and azimuth, an ultrasonic cement bond log, dogleg severity and lithology. The software then outputs a liner deformation risk assessment at any given point in the well, providing a color code highlighting this risk. 

For OH-MSF completions, the workflow begins with reviews of the lower completion ratings, axial load, planned packer movement, packer spacing, hole size, micro-dogleg severity, anticipated time for each stage of the completion, reservoir pressure and bottomhole temperature. If any one of these parameters falls below the tubular’s design factor – a ratio that measures the maximum quantity of a specific parameter that the tubular can take before breaking – then the well is flagged and the operator and frac company will adjust the completion program accordingly. 

Aramco tested the workflows for cemented completions and OH-MSF using historical data from eight horizontal wells, four for each type of completion. For one of those wells modeled with the cemented workflow, the cement bond log helped properly assess cement channeling, which Mr Waheed said gave the operator a better idea of the presence or absence of cement channels than with its traditional workflow. The data from the log would allow the operator to choose perforations in safe areas that avoided intersecting cement channels, minimizing the potential for deformation. 

One such project modeled was a monobore completion with a 4 ½-in. tubing and liner with multiple stage fracturing tools and packers in a horizontal well with a production hole size of 5 7/8 in. The upper completion was comprised of 4 ½-in. tubing and a 7-in. compression set casing anchor. The lower completion utilized 10 open-hole mechanical packers deployed on a 4 ½ x 7-in. liner hanger. 

The wellbore tubular stress analysis was performed on two stages (stage 4 and 5) using a commercial software as an example of implementing the workflow. Operational conditions during stimulation were modeled based on the frac fluids pumping design assuming the worst-case scenarios for tension, compression, burst and collapse that the completion was likely to see during the stimulation job. The tubing stress analysis model generated from the workflow showed no potential for burst or collapsed casing during stages 4 and 5 of the stimulation operations under ideal conditions.

Aramco has adopted these workflows to analyze the risk for casing deformation on its frac jobs. Mr Waheed said the study illustrated the effectiveness of the workflows in identifying the potential for casing deformation issues before a frac job is completed. He also hopes that publishing the study will encourage engineers to further study the effects of individual variables and downhole tools that affect completion or tubular failure for their wells. 

“These new workflows are practical guides for open-hole and cased holes, and we’re identifying the conditions that can lead to pipe deformation, better understanding the things that can help us avoid these cases,” he said. 

Increasing configurability for different needs

In February, GEODynamics announced the launch of its EPIC Precision and EPIC Flex disposable top-loading gun systems, which are designed to streamline wireline operations. 

The guns are customized to fit an operator’s needs. GEODynamics said the switches for the EPIC guns are the first digital switches capable of being configurable to rapid-firing mode, helping operators reduce nonproductive time. The Precision technology offers reusable subs with a configurable and programmable switch and shooting panel, which benefits operators that want a ready-made system. 

The Flex technology is suited for operators who want to use various components of the gun system with other components they may already have on hand – the switches and charges are designed to be compatible with open-source software architecture, meaning that they can be programmed with any third-party program.

“What we’re seeing is that companies want to customize their wireline to be whatever they want,” Mr Wade said. “If you want to put Company A’s telemetry in and you want to you use our charges, you can do it. If they want somebody else’s charges in their system and you want us to do telemetry, we want to have that interchangeable capability there. If we’re supporting wireline, we can’t just have one gun system. We have to be able to give them options.”

Laboratory testing on the guns was conducted at GEODynamics’ Technology Evaluation Center in Millsap, Texas, in mid-2023, with 100 live shots run on each system. Field trials, done in collaboration with an unnamed operator in the Marcellus Shale in late December 2023 to early January 2024, produced similar results – the Precision and Flex guns each ran 200 live shots successfully. However, Mr Wade said the company faced an issue with trucking the guns out to the field test site. 

“We found that we needed to have more equipment on each truck than what we had for the trial,” he said. “We could only put 50 guns on a truck, and the economics of shipping them to regions outside of Texas don’t always work ideally. We had to create a crating system that allows us to put up to 100 guns in one truck, which saves us half the footprint versus the 50 we had.”

The EPIC guns are already being used by operators in the Bakken, and the company is set to begin work with an operator in the Permian Basin in the first half of 2024. Talks are also under way to provide the system for an operator in the Montney Shale this year.  DC