随着越来越多的油井依赖 ESP，延长电潜泵 (ESP) 系统的使用寿命变得意义重大。人工举升泵的运行寿命和性能对产出流体中的固体颗粒很敏感。随着固体颗粒的增加，ESP 的运行寿命和性能显着下降。此外，固体会增加更换 ESP 所需的油井停机时间和修井频率。 

图 1 井下涡流除砂器示意图。

经常流过人工举升泵的固体颗粒包括地层砂、水力压裂支撑剂、水泥和被侵蚀或腐蚀的金属颗粒。旨在分离固体的井下技术包括从低效旋风分离到高效 3D 不锈钢羊毛筛网。井下涡流除砂器已在传统井中使用了数十年，它们主要在生产过程中保护泵免受大颗粒的影响。然而，非常规井存在间歇性段塞流，导致现有的井下涡流分离器技术只能间歇性地工作。 

应用挑战 

已经提出了几种不同的组合防砂筛和井下涡流除砂器的变体来保护 ESP。然而，由于每口井产生的固体尺寸分布和体积的不确定性，所有这些都在泵保护和生产性能方面留下了差距。这种不确定性增加了防砂组件的长度，从而减少了 ESP 的设置深度，限制了 ESP 的储层压降潜力，并对油井经济性产生负面影响。非常规井优选更深的埋设深度。然而，在具有高狗腿严重性的套管部分内使用除砂器和公头插塞泥浆锚来悬挂长而刚性的防砂组件，限制了 ESP 平均故障间隔时间的改善。内管的腐蚀是该设计未充分评估的另一个方面。 

2005 年一篇论文的作者介绍了基于旋流管的井下砂分离器（图 1）的实验结果，该结果取决于旋流作用和重力，以显示分离效率对油粘度、流量和颗粒尺寸的依赖性。他们表明，分离器的效率很大程度上取决于颗粒的终端速度。分离效率随着流量的下降、固体颗粒尺寸的减小和油粘度的增加而恶化，图2。对于典型的旋流管井下分离器，当颗粒直径降至~100μm时，分离效率降低至~10 %。此外，随着流量的增加，涡流引起的分离器会受到侵蚀磨损，从而影响结构部件的使用寿命。 

图 2. 分离效率与粒径和液体粘度的函数关系。体积流量为 120 m3/d (Martins 2005)。

下一个合理的替代方案是使用具有定义槽宽度的二维防砂筛网。当选择筛网来过滤传统或非常规井生产中的固体时，颗粒尺寸和分布是重要的考虑因素，但它们可能是未知的。固体可能来自水库，但从脚跟到脚趾可能有所不同；或者，筛管可能需要过滤水力压裂产生的沙子。无论哪种情况，固体收集、分析和测试的成本都可能令人望而却步。 

如果二维油管筛管配置不当，结果可能不利于油井的经济效益。砂筛孔太小可能会导致过早堵塞、停止生产并需要进行补救修井。如果它们太大，固体就会自由地进入生产流，这会腐蚀管道、破坏人工举升泵、冲洗表面节流器并填满表面分离器，从而需要喷砂和处置。这种情况需要一种简单、经济高效的解决方案，可以延长泵的使用寿命并涵盖广泛的砂粒尺寸分布。 

为了满足这一需求，我们对阀门组件与不锈钢羊毛筛网的使用进行了研究，该筛网对产生的固体分布不敏感。研究表明，不锈钢棉筛网具有可变的孔径和 3D 结构，可以有效控制各种尺寸的固体，而无需了解所产生的固体颗粒尺寸分布。3D不锈钢棉筛网可有效控制小砂粒和大砂粒，无需多余的二次过滤。 

安装在筛网底部的阀门组件允许生产继续进行，直到 ESP 被拉出。它可以防止在屏幕桥接后立即检索 ESP。由此产生的进水防砂筛管和阀门组件可通过清洁流体流，在生产过程中保护 ESP、有杆举升泵和气举完井免受固体污染，并提供经济有效的解决方案来延长泵的使用寿命，而无需针对不同的情况进行定制。储层特征。 

图 3. 生产过程中过滤的固体逐渐形成阻止流体流动的桥梁。

第一代泵保护设计。在加拿大西部的蒸汽辅助重力排水井中部署了使用不锈钢羊毛筛网的泵保护组件，以保护 ESP 在生产过程中免受固体污染。当采出液进入生产管柱时，筛网会过滤掉采出液中产生的有害固体。在生产管柱内，流体流向 ESP 入口，并在此处被泵送到地面。封隔器可以在筛管和ESP之间运行，以在生产区和上部井筒之间提供层位隔离。 

随着生产的持续进行，筛管和套管之间的环形空间往往会被沙子桥接，从而增加流动阻力。最终，环形空间可能完全桥接，停止流动，并且井筒和生产管柱之间形成压差，如图 3所示。此时，流体无法再流向 ESP，必须拉动完井管柱。根据与固体产生相关的多个变量，通过筛网上的固体桥停止流动所需的持续时间可能小于允许 ESP 将含有固体的流体泵送到地面的平均故障间隔时间，因此开发了第二代组件。 

图 4. 典型的非常规井 ESP 完井，防砂组件悬挂在 ESP 压力计下方。

第二代泵保护组件。PumpGuard* 进水防砂筛管和阀门组件系统悬挂在图 4 中 REDA* 泵下方，这是一个非常规 ESP 完井示例。一旦油井生产，筛网会过滤掉生产中的固体，但会开始慢慢地与沙子桥接，并形成压差。当该压差达到阀门设定的开启压力时，阀门打开，允许流体直接流入管柱并流向 ESP。这种流动导致筛网上的压差均衡，从而松开砂袋对筛网外侧的抓力。沙子可以自由地从环形空间中脱落，这减少了通过筛网的流动阻力并允许流动恢复。随着压差下降，阀门返回到关闭位置，并恢复正常流动情况。重复此循环，直到需要将 ESP 从孔中拉出进行维修为止。本文重点介绍的案例研究证明，与单独运行筛管完井相比，该系统能够显着延长泵的使用寿命。 

对于最近的安装，引入了一种成本驱动的解决方案，用于不锈钢毛网和 ESP 之间的区域隔离。筛网部分上方安装了朝下的杯式封隔器。在杯式封隔器上方，额外的基管穿孔为产出的流体从筛管内部迁移到封隔器上方的环形空间提供了流动路径，流体可以在此处进入 ESP 入口。 

与基于间隙的 2D 筛网类型相比，为此解决方案选择的不锈钢羊毛筛网过滤器具有多种优势。二维过滤器主要依靠颗粒桥接过滤器中的间隙或槽来构建砂包并实现防砂。然而，由于只能为筛网选择单个间隙值，因此筛网对所生产流体的颗粒尺寸分布变得高度敏感。 

相反，不锈钢羊毛筛网过滤器的厚网床为产出的井筒流体提供了高孔隙率（92%）和大的开放流动面积（40%）。该过滤器的构造方法是将不锈钢羊毛网压缩并直接包裹在穿孔基管周围，然后将其封装在穿孔保护罩内，该保护罩的两端焊接到基管上。网床内孔的分布、不均匀的角度方向（从 15 µm 到 600 µm 不等）允许无害的细粒在较大的有害颗粒被捕获在网内之后沿着 3D 流动路径流向中心管。该筛网的附片上的沙保留测试证明，过滤器保持高渗透性，因为液体是通过筛网产生的。实际上，这种单一“过滤器”可以处理所遇到的产出流体的所有颗粒尺寸分布。这种不锈钢羊毛筛管是由一家超级大型运营商于 20 世纪 80 年代开发的，专门用于蒸汽刺激油藏中的独立筛管完井，并拥有广泛的成功安装记录。 

图5 C井新型防砂系统ESP运行性能

该阀门组件由弹簧加载阀门组成，允许单向流动从生产区进入管柱。通过在安装前调整螺旋弹簧预紧力，可以定制阀门以获得应用所需的开启压力。通常，单个阀门运行在不锈钢羊毛筛网下方，以提供储液器和 ESP 之间的辅助流动路径。在某些情况下，多个阀门和不锈钢羊毛筛网串联运行，其中中间的阀门设置为比最下面的阀门更低的开启压力。 

随着时间的推移，地层颗粒填充泵保护器组件滤网的外表面和生产套管壁之间的环形区域。当空腔充满沙子并且颗粒固结时，沙包上的压降增加。当该压降达到预设值时，锥阀打开并允许流量直接通过泵入口。在此阶段，通过管道的流动能够沿着筛网过滤器的外部拆开先前固结的沙粒。由于压差减小，流量将恢复通过滤网，并且进气阀将关闭。因此，泵只能在短时间内直接从阀门看到流量。这会延长泵的使用寿命，因为大部分流量是通过砂筛过滤的流体。 

现场试验 

泵保护系统与杯封隔器一起在美国特拉华盆地的三个不同井中运行。主要目标是减少由于与砂相关的过载而导致的 ESP 启动和停止次数，并提高 ESP 的可用性以改善生产。泵保护系统悬挂在 ESP 管柱的下端。油井的结果显示，采用泵保护技术，泵性能稳定，振动和电流强度降低。安装新系统后，与沙子和固体相关的停机次数减少了 75%，泵的使用寿命延长了 22% 以上。 

A 井。德克萨斯州马丁县的一口新钻压裂井安装了 ESP 系统。该井的垂直部分约为 9,000 英尺，水平部分延伸至 12,000 英尺（测量深度 (MD)）。对于最初的两个完井，安装了带有六个尾管接头的井下涡流引砂分离器系统，作为 ESP 完井的组成部分。对于使用相同类型的砂分离器的两次连续安装，观察到 ESP 操作参数（电流强度和振动）的不稳定行为。对拉出的 ESP 设备的拆解分析表明，涡流气体分离器组件被异物堵塞，该异物被确定为沙子，因为它是非磁性的，并且不会与酸发生化学反应。 

在第三个 ESP 安装中，不锈​​钢羊毛筛网取代了砂分离器，作为 ESP 防砂的一种手段。安装新的泵保护系统后，ESP 显示出更稳定的行为，将电机电流波动范围从安装 #2 中的 ~19 A 减少到安装 #3 中的 ~6.3 A。振动更加稳定，趋势减少了 75%。压降也很稳定，与之前的安装相比几乎没有波动，并且额外获得了 100 psi 的压降。ESP 过载停机次数减少了 100%，并且 ESP 在低振动下运行。 

B 井。在新墨西哥州尤尼斯附近的一口井中，另一口非常规井安装了 ESP，但没有泵保护。首次启动后出现下降，ESP 开始表现出不稳定的行为。安培数和压力的波动与振动峰值相关。在这些条件持续 137 天后，ESP 发生故障，并安装了替代品。第二次安装包括具有相同 ESP 配置的新泵保护系统。油井恢复生产后，电潜泵运行正常，电流稳定，振动较小。截至本文发布时，ESP 第二次运行已实现超过 300 个运行天，与之前的安装相比有了显着改善。 

C 井。该系统的第三次现场安装是由一家石油和天然气巨头在德克萨斯州 Mentone 进行的，该公司因出砂而经历了中断和 ESP 故障，并希望提高泵的正常运行时间。操作员通常在每口 ESP 井中运行带有尾管的井下砂分离器。然而，一旦尾管充满沙子，分离器就会让沙子流到泵部分，腐蚀泵级、轴承和轴，导致升力损失。使用泵保护器运行新系统后，ESP 的运行寿命延长了 22%，水位下降更稳定，ESP 相关的正常运行时间更长。 

运行时与沙子和固体相关的停机次数减少了 75%，从第一次安装时的 8 次过载事件减少到第二次安装时的 2 次，并且过载停机后成功重新启动的次数提高了 30%，从第二次安装中的 12 个事件总计为 8 个，减少了设备上的电应力并提高了 ESP 的运行寿命。 

交付价值 

图 5显示，当不锈钢毛滤网堵塞且阀门组件打开时，进气压力特征（蓝色）突然上升。这种压力特征可以预测与沙子相关的 ESP 故障，从而进一步提高生产效率，因此可以规划使用修井机的更换操作。  

*斯伦贝谢标志 

_参考 

_{1 Martins, JA, ES Rosa, S. Robson，“作为井下除砂器装置的旋流管的实验分析”，SPE 论文 94673-MS，在巴西里约热内卢举行的 SPE 拉丁美洲和加勒比石油工程会议上发表， 2005 年 6 月 20 日至 23 日。https://doi.org/10.2118/94673-MS。} 

_致谢 

_{本文包含 SPE 论文 207926-MS 的内容，该论文于 2021 年 11 月 15 日至 18 日在阿联酋阿布扎比举行的阿布扎比​​国际石油展览及会议上发表。} 

关于作者

阿比南丹·特里帕蒂

斯伦贝谢

Abhinandan Tripathi 是斯伦贝谢美国陆地完井运营经理。在他跨越中东和美国土地的职业生涯中，他从流域层面推动创新。他的兴趣包括新产品开发以及解决完工和生产技术和运营挑战。

戈查乔丘亚

斯伦贝谢

Gocha Chochua 是斯伦贝谢的技术顾问。他在石油和天然气、涡轮机械和航空航天行业拥有 20 多年的建模和仿真经验。他的研究兴趣包括计算流体动力学、侵蚀建模和缓解、模拟驱动的设计优化、多相流和热管理。Chochua 博士发表了 50 多篇期刊文章、会议论文、专利和行业标准。

阿姆伦德拉·库马尔

斯伦贝谢

Amrendra Kumar 是斯伦贝谢防砂和流入控制装置产品线的产品冠军。在公司工作的 15 年中，他的研发工作主要集中在防砂、水力压裂和流入控制方面。他目前正在开发自主流入控制装置和抗侵蚀砂筛。他的长期目标是开发技术来帮助该行业向低碳密集型能源转型。Kumar 先生在同行评审期刊和国际会议上发表了 20 篇科学论文和摘要。他拥有六项已在行业中使用的流入控制和防砂技术的已公布专利和临时专利。他拥有德克萨斯 A&M 大学学院站的石油工程硕士学位和丹巴德 IIT (ISM) 的石油工程学士学位。

凯瑟琳·埃斯科瓦尔

斯伦贝谢

Katherine Escobar 是斯伦贝谢北美业务的人工举升领域冠军，拥有超过 11 年的生产工程和生产技术专家经验。她的职业生涯涵盖生产运营、技术开发、营销和领域领导。Escobar 女士在哥伦比亚开始了她的职业生涯，担任生产技术专家现场工程师，然后扩展到人工举升和完井领域的技术和领域领导地位。

Extending the life of electric submersible pump (ESP) systems has gained significance, as more wells rely on ESPs. The run life and performance of artificial lift pumps are sensitive to solids particles in the produced fluid. ESP run life and performance drop significantly, as solid particles increase. Additionally, solids increase well downtime and workover frequency required to replace the ESP. 

Fig. 1. Schematic of a downhole vortex-induced sand separator.

Solids particles that frequently flow through artificial lift pumps include formation sands, hydraulic fracturing proppants, cements and eroded or corroded metal particles. Downhole technologies, designed to separate the solids, range from low-efficiency cyclonic separation to highly efficient, 3D, stainless-steel wool screens. Downhole vortex-induced desanders have been in use for decades in conventional wells, where they principally protect pumps from large particles during production. However, unconventional wells suffer from intermittent slug flow, which causes the existing downhole vortex-induced separator technology to work only intermittently. 

APPLICATION CHALLENGE 

Several different variants of combination sand control screen and downhole-vortex-induced desanders have been proposed to protect ESPs. However, all left gaps in pump protection and production performance, due to uncertainty in produced solids size distribution and volume from each well. The uncertainty increased sand control assembly lengths, which reduced ESP setting depths, limiting reservoir drawdown potential of the ESP and negatively impacting well economics. Deeper setting depths in unconventional wells is preferred. However, suspending long, rigid sand control assemblies, using desanders and bull-plugged mud anchors inside casing sections with high dogleg severity, was limiting improvement of the mean time between failure for the ESPs. Erosion of the inner tube was another aspect not fully evaluated with this design. 

The authors of a 2005 paper presented the experimental results from a downhole sand separator based on swirl tubes (Fig. 1), which depend on cyclonic action and gravity, to show the separation efficiency dependence on the oil viscosity, flowrate and particle size. They showed that efficiency of the separator is largely dependent on the terminal velocity of the particle. Separation efficiency deteriorates with a drop in flowrate, decrease in solid particle size and increase in oil viscosity, Fig. 2. For a typical swirling tube downhole separator, as the particle diameter falls to ~100 µm, the separation efficiency decreases to ~10%. Additionally, with the higher flowrates, vortex-induced separators are subject to erosive wear, which affects the operational life of the structural components. 

Fig. 2. Separation efficiency as a function of particle diameter and liquid viscosity. The volumetric flow rate is 120 m3/d (Martins 2005).

The next logical alternative would be to use 2D sand control screens with a defined slot width. When selecting a screen to filter solids in production from a conventional or unconventional well, grain size and distribution are important considerations, but they may be unknown. The solids may originate from the reservoir, but they can vary from heel to toe; alternatively, the screens may need to filter sand from hydraulic fracturing. In either case, the cost of solids collection, analysis, and testing may be prohibitive. 

If 2D tubing screens are not configured appropriately, the results can be detrimental to the economics of the well. Sand screen pores that are too small may result in premature plugging, halting production and requiring a remedial workover. If they are too big, they allow solids to freely enter the production flow, which can erode tubing, destroy artificial lift pumps, wash out surface chokes, and fill up surface separators, requiring sand jetting and disposal. This situation leaves a need for a simple, cost-effective solution that can increase pump life and encompass a wide distribution of sand sizes. 

To address this need, a study was done on the use of a valve assembly in conjunction with a stainless-steel wool screen, insensitive to the produced solids distribution. The study revealed that with variable pore sizes and 3D structure, stainless steel wool screens effectively control solids of all sizes without the knowledge of produced solids particle size distribution. With effective sand control of small and large sand sizes, the 3D stainless steel wool screen does not require redundant secondary filtration. 

The valve assembly installed at the bottom of the screens allows production to continue until the ESP is pulled. It prevents an immediate retrieval of the ESP after screens are bridged. The resulting intake sand control screen and valve assembly protects ESPs, rod lift pumps, and gas-lift completions from solids during production by cleaning fluid flow and provides a cost-effective solution to extend the life of the pump without the need for customization for different reservoir characteristics. 

Fig. 3. Solids filtered during production gradually form a bridge halting fluid flow.

First-generation pump protection design. A pump protection assembly using a stainless-steel wool screen was deployed in Western Canada’s steam-assisted gravity drainage wells to protect ESPs from solids during production. The screen filters harmful produced solids from the production fluid as it enters the production string. Inside the production string, the fluids flow toward the ESP intake, where they are pumped to surface. A packer may be run between the screen and ESP to provide zonal isolation between the production zone and the upper wellbore. 

As production continues over time, the annulus between screen and casing tends to bridge with sand, which increases flow resistance. Eventually, the annular space can become completely bridged, halting flow, and a differential pressure forms between the wellbore and the production string, Fig. 3. At this point, fluids can no longer flow to the ESP, and the completion string must be pulled. Depending on multiple variables related to solids production, the duration of time it takes to halt flow via a solids bridge over the screens may be less than the mean time between failure of allowing the ESP to pump the solids-laden fluid to surface, and so a second-generation assembly was developed. 

Fig. 4. Typical unconventional well ESP completion with sand control assembly suspended beneath the ESP gauge.

Second-generation pump protection assembly. The PumpGuard* intake sand control screen and valve assembly system is suspended beneath a REDA* pump in Fig. 4, in an example of an unconventional ESP well completion. Once the well produces, the screen filters the solids from production but will begin to slowly bridge with sand, and a differential pressure forms. When this differential pressure reaches the set cracking pressure of the valve, the valve opens, which allows fluid to flow directly into the string toward the ESP. This flow causes the differential pressure across the screen to equalize, thereby loosening the grip of the sand pack on the outside of the screen. Sand becomes free to slough out of the annular space, which reduces the flow resistance through the screen and allows flow to resume. As the differential pressure drops, the valve returns to its closed position, and the normal flow scenario is resumed. This cycle repeats until it becomes necessary to pull the ESP out of hole for servicing. The case studies highlighted in this article have proven this system capable of significantly increasing pump life, compared to running the screen completion alone. 

For recent installations, a cost-driven solution for zonal isolation between the stainless-steel wool screen and ESP was introduced. A downward-facing cup-style packer was installed above the screen section. Above the cup packer, additional basepipe perforations provide a flow path for produced fluid to migrate from inside the screen to the annular space above the packer, where the fluid can enter the ESP intake. 

The stainless-steel wool screen filters selected for this solution provide several benefits over a gap-based, 2D screen type. The 2D filters rely mainly on particles bridging across the gaps, or slots, in the filter to build a sand pack and enable sand control. However, as only a single value for the gap can be chosen for a screen, the screens become highly sensitive to the particle size distribution of the produced fluids. 

Conversely, the thick mesh bed of the stainless-steel wool screen filter provides a high porosity (92%) and large open flow area (40%) for produced wellbore fluids. The filter is constructed by compressing and directly wrapping a stainless-steel wool mesh around a perforated basepipe and then encapsulating it within a protective perforated shroud that is welded to the basepipe at each end. Distributed, nonuniform angular orientation of the pores within the mesh bed (which vary from 15 µm to 600 µm) allow harmless fines to flow along 3D flow paths toward the basepipe after the larger and harmful particles have been trapped within the mesh. Sand retention testing on this screen’s coupons has proven the filter maintains a high permeability, as fluids are produced through the mesh. Effectively, this single “gauge” of filter can handle all particle size distribution of produced fluids encountered. This stainless-steel wool screen was developed in the 1980s by a supermajor operator specifically for standalone screen completions in steam-stimulated reservoirs and has an extensive track record of successful installations. 

Fig. 5. ESP operating performance with new sand protection system for Well C.

The valve assembly is composed of a spring-loaded valve that permits one-way flow from the production zone into the tubing string. By adjusting the coil spring preload force prior to installation, the valve can be tailored to achieve the desired cracking pressure for the application. Typically, a single valve is run below the stainless-steel wool screen to provide the secondary flow path between reservoir and ESP. In some cases, multiple valves and stainless-steel wool screens are run in series, in which the middle valve(s) are set to lower cracking pressures than the lowermost valve. 

Over time, formation particles fill the annular area between the outer surface of the pump protector assembly screen and the production casing wall. As the cavity fills with sand and the particles consolidate, the pressure drop across the sand pack increases. When this pressure drop reaches the preset value, the cone valve opens and allows flow directly through the pump intake. At this stage, the flow through the tubing enables unpacking the previously consolidated sand particles along the exterior of the screen filter. Flow will resume through the screen, and the intake valve will close, due to reduction in differential pressure. Therefore, the pump sees flow directly from the valve for only a short while. This causes an increase in pump life, as most of the flow is filtered fluid through sand screen. 

FIELD TRIALS 

The pump protection system, in conjunction with a cup packer, was run in three different wells in the U.S. Delaware basin. The primary objectives were to reduce the number of ESP starts and stops, due to sand-related overload and to enhance ESP availability for production improvement. The pump protection system was hung from the lower end of the ESP string. The results from the wells showed stable pump behavior, with reduced vibrations and amperage, with pump protection technology. After installation of the new system, the number of shutdowns related to sand and solids was reduced by as much as 75%, with over 22% extension of pump life. 

Well A. An ESP system was installed in a newly drilled and fractured well in Martin County, Texas. The vertical section of the well is about 9,000 ft, and the horizontal section extends to 12,000 ft, measured depth (MD). For the initial two completions, a downhole vortex-induced sand separator system with six joints of tailpipe was installed as an integral part of the ESP completion. Erratic behavior of the ESP operating parameters (amperage and vibration) was observed for both consecutive installations with the same type of sand separator. The teardown analysis of the pulled ESP equipment showed that the vortex gas separator assembly was plugged with foreign material, which was identified as sand, since it was nonmagnetic and did not chemically react to acid. 

On the third ESP installation, a stainless-steel wool screen replaced the sand separator as a means of ESP sand control. After installing the new pump protection system, the ESP displayed more stable behavior, reducing the range of fluctuations in motor amperage from ~19 A in install #2 to ~6.3 A in install #3. Vibrations were more stable, with 75% reduction in the trend. Drawdown was also stable, displaying little fluctuation compared to the previous installation and gaining an additional 100 psi of drawdown. ESP overload shutdowns were reduced 100%, with the ESP operating at low vibration. 

Well B. In a well near Eunice, New Mexico, another unconventional well had an ESP installed with no pump protection. After the drawdown from the initial startup, the ESP began displaying erratic behavior. The swings in amperage and pressure correlated with a spike in vibration. After sustaining these conditions for 137 days, the ESP failed, and a replacement was installed. The second installation included the new pump protection system with same ESP configuration. After the well was returned to production, the ESP behaved normally with stable amperage and lower vibration. At the time of publication, the ESP second run had achieved over 300 run days, a significant improvement compared to the previous installation. 

Well C. The third field installation of the system was in Mentone, Texas, by an oil and gas major that had been experiencing disruptions and ESP failures, due to sand production and wanted to improve pump uptime. The operator typically ran a downhole sand separator with the tailpipe in every ESP well. However, once the tailpipe gets filled with sand, the separator allows the sand to flow through to the pump section, eroding the pump stages, bearings, and shaft, and resulting in loss of lift. After running the new system with the pump protector, ESP run life was extended by 22%, with more stable drawdown and better ESP-related uptime. 

The number of shutdowns related to sand and solids while running was reduced by 75%, from eight overload events in the first install to two events in the second install, and the number of successful restarts after an overload shutdown was improved by 30%, from 12 events to a total of eight in the second install, reducing electrical stress on the equipment and improving run life of the ESP. 

VALUE DELIVERED 

Figure 5 shows the intake pressure signature (blue) rises suddenly when the stainless-steel wool screen is plugged, and the valve assembly opens. This pressure signature enables further improvements in production efficiency by predicting the impeding sand-related ESP failure, so replacement operations using workover rigs can be planned.  

*Mark of Schlumberger 

_REFERENCE 

_{1                      Martins, J. A., E.S. Rosa, S. Robson, “Experimental analysis of swirl tubes as downhole desander device,” SPE paper 94673-MS, presented at the SPE Latin American and Caribbean Petroleum Engineering Conference, Rio de Janeiro, Brazil, June 20–23, 2005. https://doi.org/10.2118/94673-MS.} 

_{ACKNOWLEDGEMENT} 

_{This article contains elements from SPE paper 207926-MS, presented at the Abu Dhabi International Petroleum Exhibition & Conference, held in Abu Dhabi, UAE, Nov. 15–18, 2021.} 

About the Authors

Abhinandan Tripathi

Schlumberger

Abhinandan Tripathi is a completions operations manager for Schlumberger in U.S. land. In his career spanning the Middle East and U.S. land, he has driven innovation from the basin level. His interests include new product development and solving completions and production technical and operational challenges.

Gocha Chochua

Schlumberger

Gocha Chochua is a technical advisor at Schlumberger. He has more than 20 years of modeling and simulation experience in the oil and gas, turbomachinery, and aerospace industries. His research interests include computational fluid dynamics, erosion modeling and mitigation, simulation-driven design optimization, multiphase flows and thermal management. Dr. Chochua has published more than 50 journal articles, conference papers, patents and industry standards.

Amrendra Kumar

Schlumberger

Amrendra Kumar is a product champion in the sand control and inflow control devices product line at Schlumberger. During his 15 years at the company, his research and development work has focused on the sand control, hydraulic fracturing, and inflow control. He is currently developing autonomous inflow control devices and erosion-resistant sand screens. His long-term goal is to develop technologies to help the industry transition to lower-carbon-intensive energy. Mr. Kumar has published 20 scientific papers and abstracts in peer-reviewed journals and international conferences. He has six published and provisional patents on inflow control and sand control technologies that have been utilized in the industry. He holds a MS degree in petroleum engineering from Texas A&M University, College Station and a BS degree in petroleum engineering from IIT (ISM), Dhanbad.

Katherine Escobar

Schlumberger

Katherine Escobar is the artificial lift domain champion for Schlumberger’s North American operations, with more than 11 years of production engineering and production technologist experience. Her career has spanned production operations, technology development, marketing, and domain leadership. Ms. Escobar started her career in Colombia as a production technologist field engineer before expanding into technology and domain leadership within artificial lift and completions.