Throughout the past decades, the Electrical Submersible Pumps (ESPs) have been deployed across different oil fields in an Arena of Artificial Fields. It was a proven fact that the typical run life of an ESP can exceed multiple years. However, that fact could be reversed especially in designated fields with high Hydrogen Sulfide (H2S) partial pressure; where specialized ESP design is required. The presence of the Hydrogen Sulfide (H2S) can result in various and vast forms of corrosion products attacking the ESP components which eventually resulted in an ESP shorter run life compared to average. Hydrogen Sulfide (H2S) can also react with formation water (H2O) and form Sulfuric Acid (H2SO4) or free Sulfur; which is another source of corrosion product affecting the installed ESP system. As part of continuous improvement in equipment's reliability, several Dismantle inspection and failure analysis (DIFA) were done for ESP premature failures to identify the root causes along with the recommendations and forward plan to enhance ESP run life. The results of these DIFAs indicated a common root cause of ESP failures are related to Hydrogen Sulfide (H2S) presence and well fluids entering the ESP internal components. In particular, the packer penetrator, Motor-Lead-Extension (MLE), and the pothead interface were found to be the main reasons. Consequently, an effort was rolled out to control the Hydrogen Sulfide (H2S) presences at these three locations in order to maintain the ESP reliability and prolong its run life. This presented paper will demonstrate the methodologies and fit-to-purpose ESP design that contributed in extending the ESP run life in a high Hydrogen Sulfide (H2S) pressure fields. Also, a captivated practice along with related technologies have been adapted for the sour environment which resulted in sustaining the ESP run life.

A three-dimensional numerical model was developed to simulate the stability of wellbore and perforation tunnels completed in weak sandstone formations. Post-yield mechanical behavior of granular materials is incorporated in the model to study the mechanical instabilities associated with such completions. Fluid flow calculations are also incorporated in which they are computationally coupled with the mechanical calculations to generate pore pressure and stress distribution in the sand matrix. In addition, the model presented here extends the use of the sand erosion criterion developed by Kim (2010) in order to compute the mass of the produced sand. It has been shown through field experience that sanding is influenced by several factors such as completion geometry, wellbore inclination, perforation orientation, and in-situ stress anisotropy. The developed model is capable of simulating the impact of these factors and assessing their sanding risk through advanced modeling and meshing techniques. The model can be utilized accordingly to design a wellbore completion that maximizes the mechanical stability and reduces the sand production rate. Different production and operational conditions can also be simulated to determine the onset of sand production and the critical drawdown pressure. Results obtained from the model shows that vertical wellbores produce less sand in regions where the overburden stress is the maximum in-situ stress. In horizontal wellbores, vertically oriented perforations are more stable than horizontally oriented perforations and can withstand higher drawdown before sand is produced. A wellbore model with multiple perforations was also constructed to investigate the effect of mechanical and hydraulic interference from adjacent perforations on the evolution of plastic strain. It was shown that perforation spacing has an influence on both the magnitude the spatial spread of the plastified zone. By combining the effects of phasing angle, perforation density, and wellbore diameter, the model is capable of determining the completion configuration with the least sanding risk.

The deployment of downhole packers in Electrical Submersible Pump (ESP) completions brings many added benefits to the wellbore integrity, yet it adds a certain degree of complexity to the completion design, installation, and operation. Thermal expansion of the trapped completion fluid in the tubingcasing-annulus (TCA), located between the ESP upper completion packer and the tubing hanger, poses several risks to the wellbore integrity, including tubing collapse, wellhead rupture, packer failure, casing failure, ESP cable failure, and packer electric penetrator failure. The increase in TCA pressure is accelerated in ESP wells because of their capability to instantaneously produce high volumes of hot reservoir fluids to the surface. Improper bleeding of TCA pressure results in explosive decompression (ED) of the different ESP cable components leading to a sudden premature failure of the electrical system. While appropriate bleed-off procedures have shown to minimize ED effects the selection of suitable ESP cable materials have eliminated these types of TCA cable failures. Gathering data from multiple sources such as Dismantle Inspection and Failure Analysis (DIFA), ESP downhole sensors, laboratory tests, and completion pull reports was a critical step for accurate identification of the root cause behind the encountered TCA problems. The followed analysis methodology showed that selection of packer elastomers that are suitable for the reservoir conditions was proven to be of extreme importance to the wellbore integrity and the ESP runlife. In the presented case study, changing to high-grade elastomer packers was necessary in order to tolerate the high hydrogen sulfide (H 2 S) partial pressure experienced in the studied field. Moreover, data gathered from DIFA proved that proper well cleanouts prior to ESP installation is also crucial in preventing explosive decompression of packer penetrator. In fact, effective TCA management is an important strategy that needs to be implemented in both the design and operation of the well completion.

Summary Managing large-scale electrical submersible pump (ESP) operations and assessing their performance can be a challenging task. Diverse operational environments, widely spread geographical areas, large ESP populations, and different service providers are some of the complications facing operators. Nonetheless, it is vital to the success of any artificial lift project to establish a performance evaluation structure that can effectively capture deficiencies and highlight improvements. While many operators focus on run life statistics as the central key performance indicator (KPI) for ESPs, these types of statistics may not be sufficient in providing meaningful information to decision makers. Other important ESP performance parameters include ESP shutdowns (both planned and unplanned), restart time of tripped ESPs, commissioning time, failure rate, and the number of premature ESP failures. Thus, a comprehensive study was jointly initiated between an oil operator and ESP vendors to establish KPIs that drive improvements in all aspects. The selected KPIs were developed in a structure that ultimately focuses on maximizing production availability and revenue generation. By constructing the ESP KPI framework, subpar performance areas were clearly visible by both the operator and the service provider. Decision makers were able to identify and act on fields that lag in performance while exerting efforts to improve underperforming service providers. Furthermore, regular meetings were conducted to review the established KPIs and recommend some action items, which might focus on either technical or operational solutions. Finally, KPI targets were set on the basis of the review of historical trends and were assigned to be challenging yet relevant and attainable. The followed practice can prove to be successful in forming a common ground where service providers can quantify losses by the operator as a result of ESP performance deficiencies. Comprehensive data collection and keeping of ESP trips, failures, and replacements are critical to the success of this work. Regular review of field reports and well performance are imperative to accurately compute the various KPI formulas. In fact, many of the KPI calculations can be automated to capitalize on the available communication networks installed in the field to improve ESP monitoring and accurately assess their performance.

Previously, many Oil and Gas Production Companies elected not to develop hydrogen sulfide (H2S) producing fields, particularly offshore, in exchange for sweeter crude projects. A narrow number of H2S field developments resulted in a limited number of publications with empirical data on Electrical Submersible Pump (ESP) reliability producing in high H2S partial pressure offshore fields. This paper summarizes ESP reliability lessons learned and solutions implemented from more than 500 ESPs producing across three carbonate field wells characterized by high H2S/CO2 partial pressures, reservoir pressure and production rates; low bubble point pressure and low to mid-level water cut. This paper utilizes ESP field observations and pull failure findings from over 200 Dismantle Inspection and Failure Analysis (DIFA) to confirm H2S behavior and root causes of electrical and mechanical failures within multiple ESP components. Moreover, H2S affects where ESPs were initially idle and exposed to H2S for one to two years either in static conditions or in naturally high rate flowing wells prior to commissioning are discussed. DIFA observations over a wide range of ESP runlife was instrumental in establishing the need for technologies to slow H2S movement across ESP components inclusive of a tandem seal section. Several motor seal sections have failed mechanically from H2S attack thereby requiring upgrade to high alloy metals, ceramic radial bearings and upgraded mechanical seals. Laboratory testing of failed conductor insulations retrieved during DIFA further exposed H2S methodology in creating electrical shorts. Systematic approaches were adopted to identify any unnecessary contributors such as power quality, operational practices or human error that may have facilitated H2S attack. Following the investigation and identification of unnecessary contributors; H2S scavengers were introduced into the seal section to slow H2S migration into the motor, lead sheathed motor lead extension (MLE) was upgraded with new H2S resistant insulation materials and design along with other new technologies that were trial tested to further improve ESP reliability and run life in H2S producing wells. ESP component failure tracking and runlife statistics spanning an eleven year period are shared with the reader to validate the success of H2S resistant ESP component upgrades. Finally, methodology in calculating and measuring impact of varying degrees of H2S partial pressure and temperature from three high and two low H2S partial pressure ESP fields are provided.