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Collaborating Authors
completion equipment
Abstract The operator of an Australian liquefied natural gas (LNG) plant needed to shut-in and suspend two injector wells containing extremely high CO2 (up to 99%) to perform maintenance and perform Xmas tree removal. Downhole double barriers were necessary in addition to barrier verification to ensure zero leakage across the well isolation barriers. Maintaining well barrier integrity and monitoring pressure and temperature below the tubing hanger plug were key. To achieve a proper barrier and verify the installed barriers, a service company delivered an engineered solution involving a unique combination of proprietary retrievable bridge plug (RBP) and a downhole telemetry system with wireless acoustic communication capability. Displayed real-time data enabled the operator to confirm the well was successfully isolated and barriers were safely set. This downhole telemetry system deploys surface-powered equipment for monitoring pressure below the RBP to evaluate barrier integrity quickly and accurately throughout the well suspension process. It achieves this using acoustic wireless transmission of downhole information to the surface for interpretation without the need for e-logs. This field-proven well communication system can monitor well integrity for extensive suspension durations (more than 500 hours for two wells), delivering valuable, reliable verification data while simultaneously setting the barrier and testing for leaks in a single run. The simple integrity verification accommodated safe X-mas tree removal in a critical HSE environment. Downhole wireless telemetry was continuously maintained throughout the entire well maintenance operation. Costs related to "dry" wellhead operations were reduced by eliminating the need for wireline mobilization and rig up to secure the well, while also reducing time to verify the barrier. Cost savings were significant per well. Using the service company's proprietary pressure verification system eliminated the need for compressing large volumes of gas to conduct a positive test. It also mitigated risks associated with personnel in the well bay area by performing real-time wireless diagnostics, as well as buildup before equalizing and retrieving the bridge plug. Demonstrating the validity of the lower barrier and deep-set plug, this downhole acoustic telemetry technology proved its superiority to traditional isolation monitoring methods; thus, the operator performed the same procedure during regular maintenance in its other wells. When two wellbore barriers are installed in close proximity, it can be difficult to ensure the integrity of the upper barrier. By measuring the pressure difference over the barriers, the integrity of the shallower barrier can be verified. Traditional practice is to use an anchoring or plug device to build a barrier above, which requires multiple slickline/e-log runs and pressure tests/controls for correct barrier placement. An alternative method is presented involving a unique combination of proprietary RBP and robust downhole acoustic telemetry system for real-time time monitoring, highlighting its success, cost savings, and continued use in additional wells.
Strengthening Digital Transformation of Rigless Well Intervention Through ROSE Platform, Driven by Well-Planned Strategy and Business Objective Alignment
Maher, Manar (ADNOC Onshore, Abu Dhabi, United Arab Emirates) | Syafruddin, Muhammad (ADNOC Onshore, Abu Dhabi, United Arab Emirates) | Reddicharla, Nagaraju (ADNOC Onshore, Abu Dhabi, United Arab Emirates) | Subaihi, Maad (ADNOC Onshore, Abu Dhabi, United Arab Emirates) | Albadi, Mohamed (ADNOC Onshore, Abu Dhabi, United Arab Emirates) | Desouky, Tarek (ADNOC Onshore, Abu Dhabi, United Arab Emirates) | Ahmad, Zeeshan (ADNOC Onshore, Abu Dhabi, United Arab Emirates)
Abstract Rigless well work intervention is at the forefront of field production cycle that integrates production optimization, reservoir monitoring plan (RMP), well maintenance, and well integrity. It is imperative that the oilfield provides efficient rig less planning, monitoring, and optimization, despite of dynamic challenges of field operation, that non only ease the business workflow but also attract opportunities, improve resources utilization, and optimize operational cost. To this end, the integrated online platform of rigless operation schedule entry (ROSE) provides a collaborative access for all stakeholder to streamline planning and scheduling of rigless activities and resources. Rigless well planning was traditionally conducted in manual basis using an excel spreadsheet. Without data integration, well input was sourced in scattered from different data bases that requires significant man hours to develop the plan. Furthermore, an extra effort is exerted to adjust or revise the plan and not easy for tracking and optimization. Progress or actual reports were communicated in email or shared folder to concerned stakeholders i.e., Development, Operation, and Well Integrity that is deemed not practical. ROSE is developed as digital solution where all rigless activities and resources are synchronized in one platform, provide all stakeholders an easy access and data extracting. ROSE also facilitates an automated well recommendation as a feed of rigless scheduling from RMP automation, PIES business plan, and well integrity workload. The integrated online platform of rigless operation schedule entry (ROSE) has been built to integrate rigless well plan, provides collaborative input and enhance rigless packages utilization. The platform provides user friendly features to initiate, revise, and optimize the well plan. ROSE proves an improvement of 20% in rigless package utilization by rigless operation clustering that translates to potential cost saving $1.2MM per year for an asset. In addition, it generates an automated report feeding to several business performance KPIs. The platform streamlines communication workflow which reduces emails and reminders and saves thousands of manhours spent in manual scheduling that otherwise can be allocated to other essential well operations. Development of ROSE is driven by the philosophy of do more with less with data integration and collaborative work at the core of its development. The platform is maintained simple with an easy interface for user to develop rigless well work plan. Yet, the system provides high visibility of overall rigless plan throughout the year and support realization of well operational business plan.
Objective A case study of an application in Iraq is presented with the aim to show the versatility of a limited entry cluster port completion system to overcome specific well challenges with "off-the-shelf" equipment designs. To overcome a unique set of challenges, a fit-for-purpose lower completion was designed to stimulate a reservoir with an acid matrix treatment, cleanup the acid, and allow for future water shut-off with an electric submersible pump (ESP) and Y-Block in place. Following the case study, a discussion is presented of the application of the system in UAE to augment the already successful Smart Liner (SL) completion system. There are many similarities between the completion presented and the SL. Advantages of using the system discussed in this paper are discussed. These advantages include: Better acid placement – especially at the toe of the well Lower pumping pressure Higher pumping rates Re-closable nozzles allow for future shut-off of undesirable zones, water zones for example.
Abstract A common problem in wells, both old and new, is the occurrence of mechanical plugs becoming stuck in the tubing hanger profile. Mechanical plugs are typically set in the tubing hanger profile to provide a pressure barrier to test the production tree or to prevent the flow of hydrocarbons from the tubing string to the atmosphere if the production tree is damaged or removed. There are many different types of mechanical plugs that can be used depending on the wellhead system configuration and planned well operations. Some of the common types of plugs used in the industry include, back pressure valves (BPV), non-return valves (NRV), two-way check valves (TWCV), and drop in plugs or DRN plugs. When these plugs become stuck in the tubing hanger the surface access into the production tubing is lost resulting in loss of production, complicated fishing operations, or loss of the entire wellbore if the obstruction cannot be removed. This paper highlights a recent case in which a drop-in style test plug became stuck in the tubing hanger profile of an onshore exploration well in the Middle East Region. The subject well had several failed retrieval attempts with slickline and coiled tubing, which led to the development of unique and innovative equipment and techniques to eventually recover the plug. These specialized retrieval tools and procedures provided an economical and efficient method to successfully remove the stuck plug from the well, ultimately eliminating the need to redrill a new well for the same reservoir targets. These tools and techniques were developed to remove stuck plugs and other obstructions without the use of a workover rig or snubbing unit, making this remediation process cost effective, reliable, and quick to deploy.
- North America > United States (1.00)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.15)
Unlocking Hydrocarbon Potential in Tight Gas Reservoir in Onshore Abu Dhabi Through Different Completion Technologies
Bernadi, B. (ADNOC Onshore, Abu Dhabi, United Arab Emirates) | Al Ameri, S. S. (ADNOC Onshore, Abu Dhabi, United Arab Emirates) | Al Awadhi, F. O. (ADNOC Onshore, Abu Dhabi, United Arab Emirates) | Al Shehhi, H. A. (ADNOC Onshore, Abu Dhabi, United Arab Emirates) | Al Hosani, M. A. (ADNOC Onshore, Abu Dhabi, United Arab Emirates) | Al Bairaq, A. M. (ADNOC Onshore, Abu Dhabi, United Arab Emirates)
Abstract This paper will discuss some case studies on how to unlock the tight gas reservoirs potential in onshore field of Abu Dhabi through different drilling/completion strategies. Various technologies are tested i.e., Underbalanced Coiled Tubing Drilling (UBCTD), Smart Liner (LEL), Hydraulic Fracking (HF) and Fishbones (FB). The well performances after technology application are then evaluated to see any benefit from completion technology deployments to increase the production. The selection of wells for technology implementation was carried out; 3 wells for Hydraulic Fracking, 1 well for LEL, 1 well for UBCTD and 1 well for FB. The technology implementation was preferentially applied on new wells because it gives better customization to design and implement completion technology tailored to the specific reservoir conditions and production requirements. In addition, retrofitting the existing wells with advanced completion can be more challenging and costly, making it more impractical although in certain case it can be justifiable. Observation reveals that the laterals placement on the right hydrocarbon sweetspots are the utmost important key element of the successful well production. The application of drilling technique/new advanced well completion technologies will increase the chance of production success. Thorough evaluation was performed to learn what extent the application of the techniques can improve the production. The finding reveals that the success story is as the result of combination of good lateral placement technique in the potential sweetspots and the type of the technology selected. So far pilot well with UBCTD technology has been found to have the most remarkable success among other pilot wells. Investigations were also performed to find-out what can be wrong with the failed wells with the technology deployment. The analytical study also reveals that the advanced well completion technology in a new single horizontal well can outperform the performance of a conventional multilateral well and even it can double the production of a single open-hole lateral well with non-technologies implementation at this time.
Abstract An onshore oil field in Abu Dhabi with high gas saturation has been implementing flow control devices since 2019 to control the undesired fluids production. Over the course of production ‘Reservoir 1’ is experiencing a gradual GOR increase as a results gas injection in underlying units. The key objective of this assessment was showed the optimal reservoir management Lower Completion (LC) strategy adopted during the last 4 years to mitigate the gas production and extend the well production life. Steady-state numerical solutions were set up to explore separate scenarios where Flow control devices (FCD) and Intelligent Completion (IC) were incrementally implemented. Overdesigned ICDs was avoided since they not just increase the cost of well completion, but also will impact the well Productivity Index negatively. The output is compared in terms of well cumulative oil and water/gas production thru the scenarios and their value quantified. Conveying in the use of integrated LC (i.e. ICV, ICD/AICD, DHPG, PPL), Seven (7) new wells were drilled and completed with FCD in 2019-2023. Following the AICD Well performance evaluation: 1. Regular Surface Well Testing and Multi Rate Test MRT, 2. Production Logging Tool (PLT) and 3. Reservoir Well Modelling were conducted. Furthermore, an integrated review regarding utilization of ICD technologies for GOR control and lesson learnt has been performed. The utilization of ICD technologies as a means for GOR control, is feasible and more efficient practice for well and reservoir management. All the wells with segmented completion with Autonomous Inflow control Device AICD shown enhanced production performance compared with barefoot completion. Recent PLT’s tests at various choke sizes in all the wells revealed no evidence or minimum free gas production down the horizontal wellbore adhering to reservoir management guidelines and ensuring production sustainability. In capturing GOR evolution trends, the use of multiphase flowmeters has proved crucial. The simulation model calibration with actual AICD well performance proved a significant oil recovery in long term. The delivered results supported the adoption of the technology on a larger scale; The provided solution effectiveness is continuously monitored to improve Lower completion design and increase production uptime.
- South America > Ecuador > Santo Domingo de los Tsáchilas > Oriente Basin > Block 53 > Singue Field (0.99)
- North America > United States > Texas > Permian Basin > Midland Basin > BrownField Field > Strawn Formation (0.98)
- North America > United States > Texas > Permian Basin > Midland Basin > BrownField Field > Canyon Formation (0.98)
- (2 more...)
Comparison of an All-Electric Intelligent Completion System Versus an Electro-Hydraulic System, Under Similar Conditions to Determine the Best Well Completion Technology for an Intelligent Mature Injection Field
Sánchez, W. (Ecopetrol) | Ahmedt, D. (Ecopetrol) | Camargo, D. (Ecopetrol) | Guarin, L. (Ecopetrol) | Solorzano, P. (Ecopetrol) | Polania, M. P. (Ecopetrol) | Molina, N. (Ecopetrol) | Garcia, M. (Ecopetrol) | Rojas, C. (Ecopetrol) | Jimenez, A. (Ecopetrol) | Castro, C. (Ecopetrol) | Meneses, G. (Ecopetrol) | Clavijo, O. (Ecopetrol) | Leal, J. (Ecopetrol) | Herrera, L. (Ecopetrol)
Abstract This paper will present a performance comparison of two intelligent completion technologies installed in six existing water injection wells. The first technology is an intelligent completion system with electric valves and the second is a hydraulic valve system with an electro-hydraulic control system. For comparison, a total of six wells were installed, three with all-electric and three with electro-hydraulic, in existing wells with similar reservoir and injection conditions. Both systems included permanent fiber optics to calculate the injected flow in each zone in real-time. The main objective of the technology test was to define the best technology to develop an intelligent mature onshore field. A total of six wells were selected: four in the Chichimene field and two in the Castilla field, both located in the Llanos Heavy Oil Basin in Colombia. In the first field, two wells used electrical technology and two wells used electro-hydraulic technology (one of the wells was installed inside 5-½" liner). In the other field, one electric and one electro-hydraulic well were installed. This distribution was made with the purpose of obtaining performance data for each technology in each field. The six wells were successfully installed in a period of six months without cost and time deviations or HSE incidents. In general, the electrical system was more flexible during calibrations and installation, requiring less preparation and installation time. On the other hand, the electro-hydraulic system was adequate for wells with small diameters (5-½"), since electrical technology has not been developed for this diameter. When precision of choke position and fast speed of actuation was required, the electric valve offered the best performance. The document will include details about technology selection, planning and installation process and the performance analysis obtained from each option during detailed planning, workshop and well-site preparation, downhole and surface equipment installation, and fiber optics calibration before injection start-up. The benefits and restrictions of each of the technologies will also be shown.
- South America > Colombia > Meta Department > Llanos Basin > Chichimene Field (0.89)
- South America > Colombia > Meta Department > Castilla Field (0.89)
Extended Reach Lower Completions: Enhanced Operational Performance and Efficiency
Cannon, Geoff David (ADNOC Offshore) | Caproni, Cristiano (ADNOC Offshore) | Kulkami, Neeraj Mukund (ADNOC Offshore) | Al Yammahi, Ohoud Abdullah (ADNOC Offshore) | Al Hajri, Saeed Salem (ADNOC Offshore) | Al Harbi, Ahmed Abubaker (ADNOC Offshore) | De Barros, Adelson Jose (ADNOC Offshore)
Abstract In 2021 the Drlling Team assigned to a significant Field Development Offshore Arabian Gulf, achieved a major milestone by installing the longest 6-5/8″ lower completion in an aqueous fluid (viscous brine). The aqueous fluid is solids free with lubricants added to greatly improve friction coefficient and the clean-out efficiency of the drilling mud. This method saves ∼5 days operational days by eliminating an inner string clean out post installation of the Lower Completion. This achievement is the culmination of a 5 year journey of delivering over 70 Production wells in this Field. Through this journey a "Technology Staircase" has evolved and matured - particularly related to reservoir drilling and installation of the lower completion. The first Maximum Reservoir Contact (MRC) pilot wells in the field were drilled and completed in 2020. Both these wells were completed conventionally with 6-5/8″ lower completion ∼13,000ft run in Non Aqueous Fluid (NAF). The challenge was to optimize these proof of concept (pilot) completions by taking the large step to run them in aqueous fluid as pioneered and proven with 4-1/2″ lower completions. All groups within the drilling team were challenged with the task of analyzing the collected historic data and apply it to our software models. Our target was to have an engineered confidence that we could reach our target depth with the lower completion complete with all redundant plans and contingency risks fully identified and in place. Drilling MRC wells has continually pushed the technical limits of drilling equipment and technology with ADNOC leading the industry in their development. Prior to the development of MRC drilling, the conventional lower drain size selected for the field development was 6″. However, to reach ever growing drilling targets, the Drilling Team was successfully challenged to overcome technical limits of equipment, fluids, and drilling practice. From the best practices gained from other ADNOC concessions, the hole size to enable the highest drilling performance is 8-1/2″ in our reservoirs. This size allows the utilization of 5-1/2″ drill pipe over the 4″ which has mechanical limitations and was a blocker to develop drain lengths beyond 9,000ft. Wellbore trajectory control during drilling is also a critical component for the delivery of the MRC well and subject to large focus during the drilling phase. Over previous 6″ drain drilling, the acceptable DLS, standard tripping practices and hole conditioning requirements had evolved into a robust guideline that was applied to the 8-1/2″ drilling. The additional benefits of improved wellbore trajectory control and drilling ROP which contribute to the successful deployment of the Lower Completion. These high performance targets also require a high performance drilling fluid system with NAF fluids being successfully utilized. The team's immediate challenge was to have confidence to run the 6-5/8″ lower completions in aqueous fluid that would deliver the same or similar friction coefficients to that of NAF. The capability of this greatly improves the subsequent efficiency of the well bore cleanout and mud displacement prior to running the lower completion. The immediate operational benefit is gained by eliminating approximately 5 days of rig time by not requiring an "inner string" clean-out after the lower completion installation. For the planning of the two MRC pilot wells, it was agreed that a cautious approach should be taken with the Lower Completions to be deployed in NAF fluid to establish a base line for the friction factors. During the installation, the Offshore Team would conduct detailed condition monitoring and analysis of the operations, recording parameters both manually and real time. The same was done during the inner string displacement recording tripping parameters pre and post NAF displacement. The data gained was then extensively reviewed in drag analyzing computer software to identify if any significant change in the friction parameters between the NAF and aqueous fluid. Our analysis confirmed that we had successfully achieved friction factors that would give us confidence to deploy the 6-5/8″ lower completion in aqueous fluid. In parallel we completed a detailed analysis with the Drilling, Completions and Fluids Teams where contingency plans were identified and put in place. In early 2021 the next MRC well was drilled where we had the opportunity to incorporate our learning. The lower completion was successfully installed in aqueous fluid with friction coefficients confirmed in alignment with those of NAF. Following this well and to date, the team has installed 20 further MRC Lower Completions in aqueous fluid, including the current record longest lower completion on Nasr at 17,616ft. Benefits realized: Safety: Eliminating unnecessary tripping and reducing HSE risk exposure to personnel. Operational efficiency: Removing unnecessary cleaning trip saving 5 days per well (cost) Production efficiency: Efficient NAF displacement, enhanced preparation for stimulation program. Equipment: Eliminated the requirement for complexity with dissolving plugs, remote close shoes. Drilling Performance – Improved ROP, trajectory control and BHA reliability 100X ADNOC Offshore: Continual improvement and operational excellence.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Middle East Government > UAE Government (0.65)
DeepStar Innovative Technology Development & Deployment Outlook
Shamshy, S. (Chevron) | Lee, C. (CPC Corporation) | Joseph, J. (Equinor) | Sun, W. (ExxonMobil) | Gayneaux, J. (Hess) | Sakurai, T. (INPEX) | Gomes, J. (Offshore Operators Committee) | Thompson, C. (Oxy) | Lima, C. (Petrobras) | Patni, S. (Shell) | Mateen, K. (TotalEnergies)
Executive Summary To meet the growing dual energy challenges of meeting growing demand for energy while reducing greenhouse gas emissions, it is crucial that the energy industry, including oil and gas companies, engineering firms, manufacturers, suppliers, regulators, energy-related academic institutes, and research organizations can collaboratively develop new technologies together to unlock offshore especially deepwater resources in safe and efficient manners. This DeepStar presentation will discuss the key challenges and technology development outlook that the industry can collaborate with. Leading collaborative examples of the DeepStar Program will be shared to understand how industry pioneers work together to reduce the cost and risks of developing novel technologies. By leveraging collective wisdom in areas absent of competitive advantages and unlocking collaborative capabilities between technology providers and commercial operated assets, DeepStar provides a unique platform whereby the joint industry needs of offshore deepwater energy producers can be addressed in a cost- and time-efficient manner. In order to address these needs, Deepstar has access to venture and research funding from various resources to unlock deepwater offshore energy potential that would otherwise be stranded due to technological limitations. What is "normal today" was "impossible 10 years ago"; what is "impossible today" will be normal 10 years from now. In offshore development, in 1878, the world's first modern oil tanker was built; in 1949, the first offshore mobile drilling platform was built; in 1977, the first FPSO was manufactured; in 1991, the first guideline-less subsea tree was available; in 2003, first semi-submersible facility in Gulf Of Mexico; in 2011, drilling water depth exceeded 3,000 meters; in 2015, the first subsea gas compression was put in operations; in 2018, the first autonomous offshore robot came in action, this groundbreaking development revolutionized the way operations are conducted in the offshore environment, opening up new possibilities and transforming the industry's approach to safety, efficiency, and cost-effectiveness. DeepStar is a global offshore technology development consortium founded in 1991. Its current members include 10 energy operators (Chevron, CPC, Equinor, ExxonMobil, Hess, INPEX, Oxy, Petrobras, Shell, and TotalEnergies) as members, and 30 plus tech service companies, research institutes as associate members that provide technical solutions to energy operators and industry. Utilizing its increasing image and significant leverage, DeepStar is to collaboratively deliver the most needed innovative technologies, including in engineering optimization, standardization, offshore drilling and interventions, reservoir monitoring, long-distance tie-back, advanced risers, all electrics, subsea separation, subsea boosting, autonomous subsea, autonomous FPSO, offshore wind, offshore carbon capture/decarbonization, for the energy industry. The key success of the DeepStar program is to let industry partners collaboratively work together to efficiently develop innovative technologies via significant leverage and cost savings to improve offshore operations. The program fosters collaboration among various stakeholders in the energy industry, including energy operators, tech service companies, and research institutes. This collaborative approach enables the pooling of resources, knowledge, and expertise, leading to the development of innovative technologies that address key challenges in offshore and deepwater operations. By bringing together industry pioneers, DeepStar harnesses collective wisdom and leverages funds to reduce costs and risks associated with technology development and increase the industry voice for solving common problems. DeepStar has several technical subcommittees which cover the key areas such as field development including drilling & completions, reservoir, facilities, autonomous operations, greenhouse gas emission and carbon abatement, flow assurance, subsea, etc. These subcommittees work together to identify the industry's key challenges and develop innovative technologies needed. DeepStar also promotes the adoption of innovative technologies through various initiatives, including conferences, workshops, and publications. Five technologies developed in DeepStar will be highlighted, which include 1) Hibot Robotic System, 2) Baker Hughes Veros Sensors Systems, 3) Baker Hughes REACH™ wireline-retrievable safety valve 4) Damorphe - Daido Steel - Baker Hughes Salinity Insensitive Metallic Barrier Assembly (SIMBA) with Smart Dissolvable Plugged Nozzle Assemblies (DPNAs), and 5) Damorphe-NaganoKeiki: High-Pressure High-Temperature (HPHT) - Flowable Sensor Ball. The selection of these five technologies in the DeepStar program was based on several criteria. Firstly, these technologies were chosen based on their relevance to the industry's current needs and challenges. They address critical areas such as engineering optimization, offshore drilling, reservoir monitoring, subsea operations, and autonomous systems. The selection also considers the maturity of the technologies, ensuring that they have reached a stage where they can be effectively deployed and commercially available and completed field deployed. Additionally, the technologies have demonstrated significant potential for cost reduction, risk mitigation, safety improvements, and environmental considerations, making them prime candidates for development and adoption within the industry.
- North America > United States (0.88)
- Asia > Middle East > UAE (0.28)
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Walker Ridge > Block 628 > Julia Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Walker Ridge > Block 627 > Julia Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Walker Ridge > Block 584 > Julia Field (0.99)
- (2 more...)
Fit for Purpose Low-Cost Solution for Upper Drain Accessibility in Dual Wells
Saqib, T. (ADNOC Offshore, Abu Dhabi, UAE) | Mirza, O. T. (ADNOC Offshore, Abu Dhabi, UAE) | Sabri, A. M. (ADNOC Offshore, Abu Dhabi, UAE) | Al-Hajri, S. S. (ADNOC Offshore, Abu Dhabi, UAE) | Mefleh, I. R. (ADNOC Upstream, Abu Dhabi, UAE) | Butler, B. (Halliburton, Dubai, UAE)
Abstract Located in the Arabian Gulf, approximately 135 km north-west of Abu Dhabi, this giant mature heterogeneous carbonate field is one of the largest fields in the world. The field is characterized by a number of multi-stacked heterogeneous reservoirs. With oil recoveries ranging from 3% to 45%, a large gas cap, and reservoir heterogeneities affecting production performance, the field faces challenges related to advanced maturity. The initial phase of development occurred under natural depletion from 1962 to 1973, and then the development strategy was changed to peripheral water injection, followed by Crestal gas injection in 1994. As a result of the movement of gas and water, the life of the wells has been affected. Because the saline pressure is approximately 1,100 psi, as soon as the well is hit by water, it cannot flow. As a key to meeting the production target for the upcoming projects, improvements in reservoir optimization through advanced well architecture are being considered to achieve the production target for this project, as well as ways to have dual wellbore accessibility, thus reducing the number of wells necessary. Having the ability to access lower completion levels and stimulate them is an essential part of the process. Utilizing technology to increase the accuracy of well placement will be a key factor in optimizing the well architecture. Additionally, optimization of well trajectories is also necessary to ensure that the reservoirs are being accessed efficiently and to maximize production. The use of advanced completion technologies can ensure that the wells are properly stimulated. Advanced multilateral completion technology is used to access laterals within the well. In order to minimize the number of wells and associated surface facilities, including platforms, the wells will target multiple reservoirs with two separate laterals. The first MultiLateral TieBack System (MLTBS) was successfully piloted in 2014 and was a great success [1]. It featured a cemented junction with an intermediate lateral liner, which was then completed to Level 5. Optimum cost and duration of the well was required in order to achieve these objectives without compromising on any of the objectives. This study was done in order to come up with a better and more cost effective solution for accessing the upper drain while ensuring segregated flow through independent strings and maintaining well integrity and safety as primary objectives. In order to fulfill the accessibility and control requirements, it was necessary to utilize a Dual Bore Deflector & Latch Coupling as part of the completion of the MLTBS. In this new design however, the intermediate cemented lateral liner was removed, and instead the production tubing would tie back into a lateral completion in the open hole. This new well design using the MLTBS equipment with an open hole lateral completion was selected for its advantages over the previous cemented junction design: Low CAPEX for Equipment: Saving of additional equipment for upper lateral like packer & assemblies. Low CAPEX for Operations: Rig-time saving in for cementation, clean out, milling of transition joint and running and setting the permanent packer in upper lateral. Some of the reservoirs weren't developed at first and were grouped as Undeveloped Reservoirs (UDR), and their development strategy is mainly based on line-drive development. In this type of completion, the ICDs will be used for water injector wells for line drive systems and producers, allowing control of the undesired fluid flowing through the ICDs by manipulating them in the lower completions.