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The first electrical submersible pumps (ESPs) were installed nearly 100 years ago by simply running an ESP on tubing in a cased hole. Since then, ESP completion architectures have evolved to cater for a wide range of needs such as dual barriers for offshore operations, reservoir monitoring, flow assurance, backup gas lift, back-allocation for multilayered reservoirs, and dual ESPs for enhanced run life to name a few. These solutions have been made possible by new completion tools which continue to be developed. However, the biggest driver behind the proliferation of completion architecture arrangements has been the creativity of field engineers to meet production and operational needs. Key to justifying additional complexity in a completion is to demonstrate the value, and, to this end, an exhaustive list of functional production and operational requirements was developed and reviewed to serve as a check list for evaluation of artificial lift completion architectures. Establishing the requirements are often overlooked as architectures are often adopted based on what is known or legacy practices (i.e., "This is how we have always run our ESPs.") To illustrate how the functional requirements can be achieved, a wide range of completion architectures were compared and evaluated against the "functional check list" and the review contains references of where these completions have been successfully installed. One of the findings was that, all too often, the completion architecture does not provide a method for circulating the well without losses to the reservoir, which is an important consideration for maintaining flow assurance. Of course, the perfect ESP completion architecture does not exist. However, this review of requirements and completion architectures provides the practicing completion engineer with a methodology for developing the inevitable engineering compromise between cost, complexity, and value based on documented functionality.
The first electrical submersible pumps (ESPs) were installed nearly 100 years ago by simply running an ESP on tubing in a cased hole. Since then, ESP completion architectures have evolved to cater for a wide range of needs such as dual barriers for offshore operations, reservoir monitoring, flow assurance, backup gas lift, back-allocation for multilayered reservoirs, and dual ESPs for enhanced run life to name a few. These solutions have been made possible by new completion tools which continue to be developed. However, the biggest driver behind the proliferation of completion architecture arrangements has been the creativity of field engineers to meet production and operational needs. Key to justifying additional complexity in a completion is to demonstrate the value, and, to this end, an exhaustive list of functional production and operational requirements was developed and reviewed to serve as a check list for evaluation of artificial lift completion architectures. Establishing the requirements are often overlooked as architectures are often adopted based on what is known or legacy practices (i.e., "This is how we have always run our ESPs.") To illustrate how the functional requirements can be achieved, a wide range of completion architectures were compared and evaluated against the "functional check list" and the review contains references of where these completions have been successfully installed. One of the findings was that, all too often, the completion architecture does not provide a method for circulating the well without losses to the reservoir, which is an important consideration for maintaining flow assurance. Of course, the perfect ESP completion architecture does not exist. However, this review of requirements and completion architectures provides the practicing completion engineer with a methodology for developing the inevitable engineering compromise between cost, complexity, and value based on documented functionality.
In the Gulf of Mexico, the rapid pressure depletion and reservoir depth of the Lower Tertiary intervals lead to low oil recovery. A high-reliability, through-tubing subsea electrical submersible pump (ESP) system that takes an integrated approach to production optimization will enable producers to cost-effectively extract more hydrocarbons from the increasingly challenging reservoirs in today's subsea assets. The potential increase in production depends on the maximum drawdown pressure limitations of both well casing design and rock strength. ESPs in deepwater fields are also considered to be an enhancer rather than an enabler by extending the production plateau 5 to 8 years after initial well/field startup with natural flow and seabed boosting. Hence, a robust ESP system that can be installed and operated a few years after field startup without a workover for replacing the upper completions. A robust, reliable ESP would unlock additional value to deepwater operators by delaying CAPEX and eliminating ESP failures, such as degradation of components due to high-pressure/high-temperature (HP/HT) cycling, during the first few years of nonoperation. Designing ESPs for deepwater application is a multidisciplinary challenge and needs to be approached from a full system-reliability standpoint rather than improvements to the ESP hardware alone. Implementation of ESPs in deep water requires both upfront planning at a full-system level and high degree of flexibility for installation, deployment, and retrieval. Finally, because the impact of an unplanned ESP failure is significantly detrimental to project economics, efforts to improve robustness of the ESP hardware must be complemented with automation of ESP operation to reduce or eliminate operator-induced failures. Recent industry improvements in machine learning and predictive analytics need to be leveraged to implement condition-based monitoring of ESPs to better anticipate failures and plan for replacements and/or adjustments to extend the life of degraded units. A collaborative project was undertaken to develop the concept of an alternatively deployed through-tubing ESP (TTESP) system targeted for deepwater subsea operations. The goal was to reduce intervention costs, which, together with ESP run life, are the primary factors influencing the economics of subsea ESPs, including conventionally deployed through-tubing ESPs. The project scope encompassed the downhole hardware, from immediately below the subsea tree through the upper completion, as well as deployment and retrieval equipment and methodology. Economic analyses of subsea fields were conducted to identify the factors contributing to intervention costs so that alternatives could be developed. Multiple concepts were evaluated, and the proof-of-concept system was selected based on superior economic return compared with the baseline. During this proof-of-concept phase, significant testing of key technologies was conducted. The studies showed that conventional intervention vessels and methods will not reduce the intervention costs associated with TTESPs. Lighter vessels together with technologies and methods that minimize intervention time and frequency—and, consequently, reservoir damage and deferred production—are the answer. Eliminating the wait for an available offshore rig is also a key factor in improving overall production economics. The proposed alternatively deployed TTESP system and its associated deployment methodology could reduce the intervention time by half and eliminate reservoir damage. This unconventional deployment could be conducted with lighter service vessels, further reducing intervention costs.
Well intervention is an essential overall part of maintaining the integrity of wells. Moreover, intervention methods can differ based on each respective well completion. For well intervention purposes, a Y shaped tool (Y-Tool) is installed which usually accommodates an ESP's completion. The proposed paper suggests a process that utilizes an Automatic Y-tool completion which eases well intervention operations. Using a blanking plug is the norm when it comes to ESP completions equipped with Y-tool where it provides a good seal and prevent the fluid from flowing into the bypass profile. Moreover, setting or removing the blanking plug can be quite challenging if any obstruction has accumulated in the bypass profile. An automatic y-tool completion can be an effective solution where it provides a reliable ball/seat seal and eliminates the risk associated with any attempts involving the installment or removal of blanking plugs. The y-check tool features a moving ball that is triggered by the flow and pressure produced by the ESP, which in turn moves the ball seal into its respective seat and seals the desired section of the completion. After the successful installation of the automatic y-tool completion, the ESP performance was observed to ensure that there is no leak in the ball/seat sealing mechanism and that it can be utilized in the upcoming well intervention operations. This paper will illustrate the challenges associated with the blanking plug and benefits introduced in the automatic y-tool. This will be reflected on the ESP performance that will ensure the functionality of the automatic y-tool, and the highly effective intervention operation that can be conducted with a system such as the one mentioned in the paper. The paper discusses the detailed process in effectively utilizing the automatic y-tool in well intervention operations, which in turn provides a more efficient alternative for well interventions in completions with an ESP installed.
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