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 brownfields, controlling well integrity is critical in maintaining production and ensuring safety of the personnel and infrastructures. Equally important is optimizing and allocating production in wells by closely following wellhead upstream pressures (and temperatures). In the current situation, field crews have to move from well to well. This method is time consuming, exposes personnel to driving hazards and potentially dangerous areas. In addition, human reading of manual pressure gauges can result in large discrepancy in the reported values. Together with the low frequency of manual readings, this method does not allow for pro-active well intervention and can result in higher downtime in case of well tripping. Deploying remote monitoring with classical telemetry in fields with limited telecommunication infrastructure is costly and complex. Low Range Wide Area Network (LoRaWAN), a public wireless network technology developed in 2009, changes the situation. It enables low power compact battery sensors with up to 10 km radio range. This performance is sufficient to connect, in one go, most onshore wells without power nor connectivity. This paper describes a pilot project to evaluate the adequacy of this technology in ADNOC Onshore fields. The objective is to assess performance of LoRaWAN deployed Sensors along four metrics: deployment time, deployment cost, Base station radio coverage and data availability. The pilot uses a plug-in ATEX- certified Wireless Pressure and Temperature (P&T) sensors developed by the vendor SRETT, commercial LoRaWAN Base stations, and proprietary software to provide remote access to the data via cloud data storage and web based application. For this pilot, four Base stations were deployed in two giant oil fields collecting data from four well heads each equipped with two sensors (P&T). This combination allowed testing wireless link quality over eight radio paths, some with terrain obstacles between Sensors and Base stations. The complete system was fully tested and validated at the shop prior to field deployment. Performances during the deployment was evaluated, and Sensor behaviors were monitored over a three-month period. In the current environment, maintaining a high HSE standard on aging infrastructure must be made at a controlled cost. LoRaWAN IoT remote monitoring technology is cost effective and efficient to deploy. Once deployed, it will enable preventative safe detection of wells with potential issues, improved accuracy and understanding of production events and lead to a reduction of potential adverse situations thanks to an optimized intervention strategy.

A large operator of a brown field offshore in the middle east has decided to provide full lower Completion accessibility and ensure prevention of open hole collapse as it can lead to various gains throughout the life of the well. Among those benefits, it provides a consolidated well bore for various production logging & stimulation tools to be deployed effectively, as well as full accessibility, conformance control and enable to provide production allocations for each zones. However there are multiple challenges in deploying lower completion liner in drains involving multiple reservoirs and geo steered wells: Well Bore Geometry, dog legs/ tortuosity etc. & differential sticking possibilities and of course the open hole friction. Due to the size of the open hole, restricted casing design and utilization of limited OD pipes further add to the complications of deploying the Lower completion liner in such brown Field wells. This paper intend to review the multi-step methodology approach implemented in recent years by the company to effectively deploy 4-1/2″ Liner in 6″ Horizontal Open Hole section. Among the techniques used to assist successful deployment of lower completions are: Improving hole cleaning, ensure smooth well bore with the use of directional drilling BHA, reduction of the Open Hole friction by utilizing Lubricated brines, fit for purpose Centralizers, use of drill pipe swivel devices to increase weight available to push the liner & reduce buckling tendency. With the length of open hole laterals reaching up to 10,000 ft for 6″ Lower drains, open hole drag, friction & cleanliness are major components that causes challenges in deploying the Liner till TD. The use of specially formulated brines with fixed percentage of lubricants proved to significant reduce friction compared to the drilling mud used for drilling the horizontal drain. The combination of low friction brine with proper centralization / standoff which resulted in reduced contact area with the formation has also shown good results in preventing differentials sticking while running the liner through multilayer reservoirs having significantly different reservoir pressures. Another major constrain to deploy the lower completion liner in this offshore field is the very nature of the wells being primarily workover. This involves generally Tie back liners run to shallow depths to restore the integrity of wells. This limits our ability in the selection of drill pipe that can be used as only smaller OD drill pipes and HWDP can be utilized in order to deploy the Liner to bottom. On many occasions this provides only limited weight to push the Liner down to TD and impact our ability to set the liner top packer. Drill pipe rotating swivel devices have been utilized to improve our weight availability & transferability to push the liner down and to set the liner top packers. In order to provide independent deactivation mechanism for the drill pipe swivel and to have complete success in our liner deployments, a dedicated ball activated sub was designed to deactivate the swivel acting as back up in case primary deactivation methods fails during liner setting. The combined use of all these techniques enabled the company to deploy 4.5″ Liners in 6″ Horizontal drains with high success in this offshore Brown Oil field of UAE. This resulted in better well construction and complete access to lower drains over the life of the wells.

Inflow Control Devices (ICDs) are typically deployed as parts of the lower well completion in horizontal wells to equalize the pressure drop along the drain length and to achieve a uniform flow through the formation. Therefore, ICDs can delay undesired water or gas breakthroughs and maximize the reservoir recovery, particularly when producing from heterogeneous reservoirs. However, by imposing additional pressure drops across segments, ICDs can reduce the production potential in the early stages of well life. This paper presents a novel design methodology, using dynamic reservoir modeling, to make ICDs responsive to the well flowing conditions and to eliminate the pressure drops across segments in early well life by using the shifting technique. The reservoir contains several sublayers and exhibits significant contrast in rock and fluid properties. The horizontal oil producer targets all sublayers simultaneously. A five-spot water injection pattern is planned to maintain the reservoir pressure. Usually, ICDs are designed based on well models that do not cover the entire expected well life. In our methodology, we rely on the dynamic reservoir model to predict changes of pressure and fluids along the drain and to find the optimal ICDs design that can respond to these changes. Sliding sleeves are combined with ICDs to allow choking back unwanted water production over time. Moreover, the design is tested with a systematic sensitivities approach for different well and reservoir conditions to ensure a robust design against reservoir uncertainties. The proposed completion design methodology was successfully implemented in a horizontal well crossing a layer-cake heterogeneous carbonates reservoir in offshore Abu Dhabi. The well deliverability analysis suggests that the well cannot produce more than 25% water cut without artificial lift. Sensitivities were conducted at varying water cuts for each ICD compartment in addition to specific sensitivities for the high permeability compartments. To reach the optimal completion design, reservoir simulations were used to evaluate the benefits of various combinations of ICDs and nozzles sizes and their overall impact on well performance. The optimal design consisted of five compartments in the horizontal section with 14 ICDs and proved to be more effective in delaying water breakthrough into the compartments with high permeability without affecting the initial production rates. The benefits of ICDs are well known in the industry to equalize the well flux based on permeability contrast by choking production selectively. The novel technique presented in this paper eliminates the choking effect on proction during the early well life while retaining the full benefits of ICDs for later stages; using the shifting technique, the offending layers can be choked back or closed completely to maximize oil production rates and reserves.

Completion and artificial lift most commonly designed by skilled and specialized engineers in there domain and misunderstand the need from each other's. This is even more accurate when it comes to the understanding of other domain such as production, reservoir, and workover. When it comes to Rig-less deployed ESP, the need to work hand in hand between the different core expertise is more accurate as the wrong design of the well could result in catastrophic implementation. Perfect completion design is most likely not achievable, and well design can always be improved, nonetheless, will proper planning and understanding of the limitations of this new ESP operations, the overall well efficiency can be greatly improved. Among the finding of this paper, the barrier philosophy and bullheading preparations should be carefully reviewed and implemented for any Rig-less deployed ESP. Ultimately, the objective of such technology is to bring increased value to the well.