An operator planned to install ESPs to overcome high water cut and minimize the gas supply risk for a gas lift completion at a platform in the Gulf of Mexico. The platform is an oil collection point and its continuous operation is essential during any rig-assisted interventions. To maintain platform operation, three wells were selected for deployment of rigless electrical submersible pump (ESP) replacement systems to avoid the future use of a workover rig. The challenge was to allow a single-trip ESP deployment using the crane facilities with existing height limitations. A special surface connection system was designed to allow long ESP sections to connect under pressure at the wellhead. The technology is based on a propriotery system and method of connecting long strings at the surface using a surface lubricator and an adapted deployment stack. The system elements are located between the pump intake and protector seal sections of a standard ESP string that can easily and economically sourced in most locations. This new technology reduces the number of wireline/slickline runs needed, and the system features allow verification of mechanical connection integrity at the surface prior to deployment in the well. The successful deployment and commissioning of a rigless ESP replacement system in the SM 130 A-26 well in the Gulf of Mexico was completed in October 2019 without incident. Prior to the deployment of the rigless ESP replacement system, it was decided to perform hydraulic stimulation operations to improve the well productivity. This operation resulted in higher than expected well inflow with increased water cut. At the time of writing this paper, the ESP system had recently failed to start due to stuck pump (possibly scale related). Due to the ability to perform a rigless system upgrade for the unanticipated well inflow conditions, the operator is planning for the first rigless replacement of the existing ESP to achieve higher flow rate during the last quarter of 2021. The successful deployment of the alternative ESP deployment technology demonstrated the potential to improve the economics of the existing production facilities by reducing production deferment, minimizing health, safety, and environment (HSE) exposure; and improving the asset value. This paper discusses the engineered solution and application of the technology required to deploy long ESP strings, modifications required for the specific well conditions, and the lessons learned during the first successful deployment of rigless ESP technology in the Gulf of Mexico. Due to the performance and capability demonstrated in the first successful installation, Talos Energy has recently installed its second rigless ESP replacement system in a recompleted zone and is planning for installing its third system in the SM 130 field in 2022.
The Electrical Submersible Pump (ESP), a form of artificial lift technology, has proven to be a durable solution for delivering the required rates from Saudi Aramco fields. Therefore, this form of artificial lift was selected to increase production rate from one of the offshore fields, while optimizing offshore producing facilities. This offshore field has favourable conditions for ESP application, producing from carbonate reservoir with no anticipated fines production, low GOR, low temperature, low bubble point pressure and high API gravity. All new installations were carried out without interrupting the ongoing production target. The project has completed a four-years operating cycle while continuously maintaining the field production rate with an acceptable ESP failure and run life. So far, 41% of the originally installed ESP systems are operating more than 4 years and 20% are operating in the range of 3–4 years run life. The cumulative average run life of operating ESPs is 2.7 years and that of failed ESPs is 1.74 years. To maintain required production target, an effective ESP replacement program is a core element of field production strategy. Therefore, several measures such as replacement of underperforming ESP systems and upsizing of the pumps have been implemented. Furthermore, Dismantle Inspection and Failure Analysis (DIFA) of pulled ESP systems were conducted to evaluate the root cause of the failures and remedial actions were implemented to prevent such occurrences in future. Increasing Motor Lead Extension cable thickness, utilization of tandem seals and new wellhead penetrators are also expected to further enhance the ESP run life. New applications to minimize ESP failures due to human intervention and ensure proper equipment handling during installations are being pursed. In addition, tandem ESP completions and different types of wellhead penetrators are being pursued to reduce rig utilization, increase producing life and minimize failures. Introduction Saudi Aramco discovered the offshore field in 1963 and placed it in natural production from 1966 until 2004. The primary reservoir is hydraulically supported by natural water influx. The field produces Arabian Medium crude with an average oil gravity of 30° API and 2.7% sulfur by weight.
The emerging subsea processing system described in this work, comprises several deepwater wells equipped with electric submersible pumps (ESPs) and one or more seabed booster pumps. This system provides efficient reservoir hydrocarbon recovery by maximizing pressure drawdown at the sandface. The in-well ESPs increase the pressure drawdown to improve production throughout the life of the reservoir, while the subsea booster pump lifts the combined production from all wells to reach the processing facilities at sea surface. This system integrates several production technologies to optimize performance, lower operating costs, and support reliable and safe operation.The Lower Tertiary trend (LTT) in the Gulf of Mexico (GOM) poses a number of documented challenges for flowing reservoir fluid from the sandface to surface facility. The key challenges are operations due to low permeability, high pressures, high temperatures, and water and well depths. The primary objective of this work was to document the feasibility of the subsea processing system and quantify its production performance for a typical LTT field. The work included development of a full field system layout and simulations of production performance for a range of reservoir and system assumptions. In addition, operational issues such as system stability, power balancing, and basic control methods were considered, including the use of transient simulations, to ensure a reliable and efficient operation of the system. These form the basis of a unified pump control methodology. To verify the impact of in-well ESP reliability on field performance, a comprehensive availability model was developed using reliability data for individual system components; ESP reliability, ESP intervention time, and rig deployment time were varied to determine their impact on overall system availability. The results of the availability model were then combined with the steady-state production results to define production availability and calculate a range of internal rate of return (IRR) values for a typical LTT field development.Utilization of the system showed enhancement in oil recovery in the range of 20 to 50% over use of a seabed boosting pump alone and substantial improvement in total liquid and oil gain as compared to natural lift. The system resulted in very satisfactory IRR and achieved production availability targets by using alternatively deployed ESPs. Moderate improvement in in-well ESP reliability combined with shorter rig mobilization time for intervention shows significant improvement in production availability. In total, the combination of seabed boosting pumps and in-well ESPs should be considered as a viable method of enhancing recovery from challenging deepwater subsea fields such as those of the LTT in GOM.The unified pump control methodology is the key to safe and reliable operation of the system. The current work presents an approach on how to operate ESPs safely, by minimizing transient responses and shifting total operating load as much as possible to the seab...
Alternative deployed ESP Systems are strings that are deployed in the well on other than conventional tubulars. Coiled Tubing (CT) deployed Electric Submersible Pumps is one of the most common configurations and has been used successfully in Al Karkara field to reduce intervention cost. As part of a closed loop product improvement workflow, utilizing data from dismantle, inspection and failure analysis of equipment, design improvement were suggested and implemented to address root causes and maximize life in Al Karkara. As part of this work, the main challenges of the application as well as weaknesses identified on the different sections of the string are explained in detail. Moreover, the design and specification changes incorporated because of said observations are also covered, including improvements on the power cable, lower connector, multisensor, motor, bottom intake, and base protectors, among others. Through implementation of downhole equipment ESP upgrade and enhancing the operating philosophy, this improved the run life of Al Karkara field by more than 300%. With the industry shifting into a drastic reduction of total cost of ownership (TCO) approach and with the volatility of oil price, the rigless ESP deployment through coil tubing will help to eliminate the cost of a work over rig while reducing the deferred oil production. This paper showcases the ESP capabilities in this corrosive and high temperature environment.
Meeting the production demand in today's market without sacrificing performance of the artificial lift method is critical. Aggressive flowback procedures lead to solids production and unplanned electric submersible pump (ESP) shutdowns because of solids overload. A novel pump protection system has been designed, tested, and installed in the field. The system enhances the ESP life, improves restarts, and reduces downhole vibrations and unplanned shutdown by controlling the solids flowback and sending solids-buildup pressure signals. A comparative study on three ESP wells in the Delaware basin (US) demonstrated the efficacy of the system. The system comprises of an intake sand control screen and valve assembly. The novel stainless steel wool screen acts as a three dimensional (3D) filter capable of filtering out particles of 15 to 600 μm, and the valve assembly activated by differential pressure across the screen creates a secondary flow path to allow cyclic cleanup of the screen. Stainless steel wool screen with variable pore sizes is used as the sand control media for its high efficiency in preventing the flow of most of the solid particles. When the solids build up on the screen surface, the valve assembly opens upon reaching a preset differential pressure to enable flow past the screens and into the ESP and allows sands deposited on the screen surface to fall off. The pump protection assembly was tested at surface and installed in three wells along with downhole ESP gauges measuring pressure, temperature and vibrations after pulling out existing ESP completions. Qualification testing confirmed the opening of the valve assembly after solids buildup on the stainless steel wool screen. It also validated that the deposited sand fell-off from the screen surface after flow diverted through the valve assembly and pressure differential across screen dropped. In the field installations, the run life of the ESPs improved by an average of 35%, with comparable production volumes and slow drawdowns. In addition, the number of ESP shutdowns related to sand and solids was reduced by as much as 75%, improving longevity of electrical components. The success rate of ESP startups after planned and unplanned shutdowns also improved by 22%. The increase in inlet pressure captured via the downhole gauges when the valve assembly opened indicated the sand control prevention and mitigation system was bridged, and ESP replacement should be scheduled to minimize deferred production from a solids-induced ESP failure and to minimize surface solids management costs. The vibration signal data obtained from downhole sensors confirmed the reliability of the system. Overall, results demonstrate that the system designed is successful at increasing ESP run life without detriment to well production performance. The new, field-proven pump protection system along with its components and the completion design substantially increase life of ESP by reducing the number of shutdowns related to sand overload, reducing shutdowns, reducing overall vibrations, increasing the probability of successful start after shut-in, and increasing the performance reliability during fracturing of a neighboring well. Consequently, more wells that are looking to increase the ESP life can now benefit from this technology and increase output.
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