Search

This paper highlights the successful installation of a MultiLateral Technology (MLT) for the first time in an offshore field 40 km from Abu Dhabi. It will document the deployment of the deepest cemented MLT Level 5 globally, with improvements in well design and operations sequence compared to the conventional design and execution plan. The system is demonstrated as a reliable method to access laterals giving the utmost importance to all operational risks concerning drilling and completion. The design relies on the Latch Coupling (LC) pre-installed with the production casing as the foundation for the successful drilling and cementing of the upper drain liner and for different completion runs. The downhole completion components that are permanently installed provide the capability for future reservoir monitoring and intervention to the laterals via coil tubing, wireline or slickline through the Multilateral Tieback System (MLTBS) completion. The well was completed as the deepest cemented Level 5 System globally with zero NPT on MLT completion operations. The planning phase was extremely meticulous and all risks were properly identified at planning stage and mitigated during execution. The significant developments to multilateral construction are: Optimize well profile, mud system, clean out and milling BHAs to facilitate the deployment of MTLB system. Improve the operations sequence by replacing the Retrievable Bridge Plug (RBP) run with intermediate completion. The assessed amendment has reduced four (4) trips during installation which has been recognized as a global system improvement for MLT Technology. Utilizing a glass device for the well barrier instead of slickline plugs have efficiently reduced the time and simplified the operation's intervention. Selecting to spot Hi-Vis after isolating the lateral instead of the sand has effectively improved the metal recovery and clean wellbore post clean up approach. The challenge of clean out post washover was moderated with fabricating a stinger to pass inside the packer and achieve proper debris cleaning to the seal bore area. The well achieved its objective by providing two integral laterals with mechanical and hydraulic isolation and full accessibility of both drains for better reservoir surveillance through one single well slot. MLT installation strategy was effectively optimized to reduce time, cost and installation's risk against the original plan. The design enhancements were beneficial to achieve multiple global records.

For several decades, completion design has been performed by the Field Development (FD) Team of several offshore fields in Abu Dhabi and installed with minimal Completion Engineering Team contribution. The demand of lower completion requirement has being increased to maximize well portfolio and enhance well life. The completion design is becoming more challenging and import for key to success. Since a companywide re-organisation occurred a dedicated Completion Engineering Department has been formed to develop a plan to standardise & optimise completions in order to reduce phase duration and NPT. A plan was approved that involved the hiring of a complete engineering department with expertise in many different types of completion and workover operations from all over the globe. This engineering team was brought together from other oil companies and service providers, and tasked with reviewing all current and future completion designs, operations procedures and completion equipment. This was done in order to identify suitability and gaps that were the cause of well construction NPT and identify processes that could be used to reduce or eliminate possible future Well Integrity problems. When the new organisation was formed completion phase NPT reached over 20%, however three month after the NPT had dropped to 11.1%. Within six months of the engineering team starting to be formed, completion phase duration has reduced by 20% and NPT has reduced by almost 50%. These results have been achieved with a concerted effort to maximize understanding of the equipment available to be deployed and develop standardized completion designs that meet the functional requirements of the Field Development Department. As the department has grown and moves forward, a greater involvement in the development of documents such as but not limited to: scope of work and technical requirements for procurement; further deepens the engineering-centric approach that will continue reducing completion phase duration contributing to the operator strategic goals. This paper will show how the newly formed engineering team has managed a complex change from a previous organisation to a new one. Whilst the previous completion design and execution methodology was seen to be successful in other operating companies, the successful engineering-centric approach has been proven within other national operator offshore concessions to reduce phase duration and NPT.

Field presented here is located in the southern part of the Arabian Gulf approximately 135 km north-west of Abu Dhabi city. This giant heterogeneous carbonate field consists of multi-stacked reservoirs. The presented reservoir is highly fractured, it measures 9 km by 11.5 km. The reservoir has an original oil in place estimated at 2,240 MMstb of 35°API oil with saturation gas of 400 SCF/bbl. The reservoir pressure is +/− 2,700 psi and the sealine pressure in the field is +/− 1100 psi. The wells completed in T reservoir are unable to flow naturally against the high sealine pressure. Some wells are producing against by-pass line at 600 psi. Crestal gas injection was introduced to maintain the reservoir pressure. To produce the reservoir at its potential, it is required to use some artificial lift techniques. ESP was finalized to install for overcoming the high sea line pressure. As mentioned earlier the T reservoir is naturally fractured and has crestal gas injection, which lead towards 3,500 – 4,000 SCF/bbl and beyond the ESP limit. This requires some solution to handle the gas. A collaborative team of engineers was assigned to design and meet the challenge of such a premier application. The team conducted a detailed and comprehensive analysis of the T reservoir's fracture and fault characterization: the aim was to deliver an optimal well design meeting the requirement of ESP gas handling with minimum cost. A unique, fit-for-purpose dual completion (4-1/2" × 2-3/8") was finalized. The rigless ESP will be run through 4-1/2" tubing and 2-3/8" tubing will be utilized for gas handling and re-injecting gas in the sealine at surface. The dual completion will allow to handle high GOR through short string, which will lead towards the long ESP runlife. Before commencing the full development plan for T reservoir, this will be a pilot for better understanding the reservoir and its behavior. Rigless ESP was selected due to the advantages compared with conventional ESP: POOH and RIH of retrievable ESP parts through a conventional slickline unitPumps can be replaced during the well life without rig workover.Low OPEX cost.

The challenges of high heterogeneous multi-layer reservoirs were a driver for ADNOC to establish new well completion requirements. Based on this, the well completion strategy was revised in order to improve the completion design for a Dual Oil Producer (DOP) initially well planned without accessibility into the upper drain. The solution was successfully implemented by drilling the well having a Multilateral Dual String Level 5 Completion System to have full reservoir isolation and mechanical accessibility to TD in both drains.A major approach was implemented giving the utmost importance to all operational risks concerning drilling and completion. The design relies on the Latch Coupling (LC) pre-installed with the production casing as the foundation for the successful drilling and cementing the upper drain liner and for different completion runs. Thus, a level 5 multi-lateral completion coupled with Inflow Control Devices and Pre-perforated Liner in the upper and lower lateral respectively was successfully deployed.The main advantages of this technology compared to the initial proposal are:Brings effectively two single wells from one slot of the wellhead tower as it provides independent access & control for enhanced reservoir management (well stimulation, production logging and water shut-off). Substantial cost savings due to the utilization of one slot only. Conventional single designs need two slots to deliver equivalent completion requirements. The completion technology meets the Well Integrity Policy & Completion Guidelines stated by ADNOC to have full accessibility to all drains.This is the first Level 5 configuration installed in UAE integrated with a lower completion. The design enhances the benefits of the multilateral construction by providing full mechanical & pressure isolation at the junction throughout the life of the well. Furthermore, accessibility to both laterals from surface without the use of a re-entry deflector or any constraints was deemed to be paramount for a successful well construction.

The giant heterogeneous carbonate field presented here consists of multi-stacked reservoirs and is located in the Arabian Gulf approximately 135 km north-west of Abu Dhabi. The reservoir named "T" measures 9 km by 11.5 km, with large accumulation of 35 °API oil with initial gas oil ratio of about 400 scf/STB. The current reservoir pressure is around 2,700 psi; many of wells are unable to flow naturally against the high sealine pressure, due to low productivity and relatively low GOR. To produce these wells, "artificial lift" or lower sealine pressure are required. A collaborative team of Reservoir Engineers, Petroleum Engineers and Geoscientists was assigned to find a sustainable and cost-effective solution to produce reservoir "T" in order to evaluate its potential. The team conducted a detailed and comprehensive study of the field starting from reservoir "T" and then expanded to the other reservoirs. As a result, the proposal of an "Auto Gas Lift" (AGL) pilot was formulated to use gas from the reservoir "C" (underlying reservoir T) to artificially lift the oil produced from reservoir T. AGL is a cost-effective artificial lift system, directly replacing for conventional gas-lift equipment, gas compression facilities, gas transport pipelines and ancillary equipment. This technique has been identified as the most suitable for such mature offshore field, where existing platforms have limited spare load and space capacity and could not accommodate gas-lift compression facilities or ESP topside equipment. The first pilot completion has been designed. It consists of a perforated downhole high GOR zone from which gas is bled into the tubing at a rate controlled by a downhole gas lift valve. The gas produced from high GOR reservoir C will allow reservoir T to flow by reducing the hydrostatic head of the fluid column in the well. Artificial lift has not been implemented yet in the field. However, several artificial lift techniques, such as Electrical Submersible Pumps or conventional gas lift, are foreseen in long term development plans. "AGL" technique, if successful, could represent a cost-effective solution for further appraisal of this reservoir, without waiting for the implementation of large-scale artificial lift techniques.

An integrated and collaborative study was required in order to determine the most cost effective field development scenario while ensuring collision risk mitigation, to define and validate the well planning and slot allocation for the wells scheduled for the next ten years as part of the re-development due to a new sub-surface strategic scheme that was later extended to the full lifecycle of a green field offshore Abu Dhabi. The workflow included data, feedback and participation of four main stakeholders: Sub-surface Team, Petroleum Engineering Team, Drilling & Completion Team and Surface Facilities Engineering Team. The process started with the provision of the targets by the Petroleum Engineering Team, previously validated by the Sub-Surface Team to the Drilling & Completion Team. The second step included generation of preliminary trajectories including high-level anti-collision analysis against existing wells as well as other planned wells; this step also included validation of the Completion requirements based on the preliminary drilling schedule and equipment availability. The trajectories were then sent back to the Petroleum Engineering Team for well objectives validation and finally a multi-disciplinary session with the Surface Facilities Engineering Team, Petroleum Engineering Team and Drilling & Completion Team was executed to ensure readiness of surface installations based on the drilling schedule; as part of the outcome of this session multiple iterations occurred until alignment and agreement of all the stakeholders was achieved. The outcome of the workflow was the generation of full field development study including the preliminary trajectories, their respective slot allocation, high-level anti-collisions and estimated Drillex (Drilling Capex) validated and agreed by all stakeholders. This novel approach to the integrated multi-disciplinary collaborative field development well planning provides multiple benefits such as: 1. Fast delivery of scenarios for field development well planning, reducing the cycle time to less than half of the conventional time required. 2. Generation of multiple scenarios instead of a single scenario, allowing further optimization of cost and risk reduction without compromising expected production targets. 3. Early understanding of the completion equipment requirements to ensure availability based on the drilling schedule. 4. Quick response to unplanned changes based on the understanding of the full field scale planning allowing swapping of wells with minimum to impact on cost, risk and operations. 5. Full In-House process that represents a continuous and dynamic project allowing constant fine tuning based on new data and new models instead of a fixed time stamp, static, project with a single report outcome.

The Extended Reach Drilling (ERD) field re-development of a giant offshore field in United Arab Emirates (UAE) from four artificial islands predominantly requires the use of artificial lift (gas lift) to assist in unloading the wells post-completion operations and enhance reservoir production recovery rates. The vision was to achieve a well completion that allows for intervention-less unloading via gas lift using shearable Gas Lift Valves (GLV) and Remote Actuated Barrier Devices (RABD). The key principals in developing a solution to achieve this vision were to reduce rig time by avoiding critical path unloading, minimize post-rig activity to install live gas lift valves, and eliminate HSE exposures. Historically producer wells were completed with dummy gas lift valves and a frangible barrier device to facilitate the required completion pressure testing and provide barriers for rigging down from well. Coil Tubing (CT) was used to break the barrier device and kick off the wells with nitrogen. Once gas lift is available, the wells would be shut in, and a series of wireline interventions carried out to replace the dummy valves with live GLVs. This time consuming and costly process increases in cost when subsequent rig location covers the well that needs intervention; critical path rig time has been needed to unload wells with CT, in some cases requiring up to seven (7) rig days. This resulted in increased construction cost of each well and additional HSE exposure associated with the rig-less interventions required. A method was developed to deploy the upper completion with live, barrier qualified Tubing Pressure Shearable GLV’s (TSGLV) and a RABD, which enables all necessary well-construction integrity tests to be performed, and subsequently convert to a production configuration to allow unloading, gas lift and production of wells. Post-completion, well unloading and gas lift is immediately available without incurring critical path rig time or rig-less interventions. In this paper, the authors will demonstrate the technology that was developed, the qualification and testing program that was implemented, and final solution that enabled the Company to deliver wells successfully with remotely actuated unloading and production without the need for intervention.

Driving efficiency to ensure cost and risk reduction in well operations is paramount for any operating company; to achieve this, the main objective was to implement a continuous improvement process that measures performance to then improve it, acquiring lessons learned and finally implement new technologies to reduce non-productive time, invisible loss time and push the technical limit to the limit. The first step was to measure the current performance to determine average and best references to compare against. The drilling operations and engineering teams defined KPIs for each well type and respective sections and activities involving all levels of the organization including every individual, ensuring effective communication inclusive of Rig Crew and Service Providers. The initial KPIs were defined, discussed, validated and agreed by both operations and engineering management, all engineers were informed and challenged to measure their performance against KPIs. Once new records were achieved, a workflow to document best practices initiated, once identified, validated and documented, becoming the new standards. Similarly, once average performance was not achieved, a ‘Lessons Learned’ workflow was initiated. Aiming to get the team engaged a communication protocol of the Highlights and Lowlights was put in place, including recognition during operations meeting and emails. The primary results of the deployment of this initiative include the delivery of a 10% additional well count compared to the initial year's plan. An overall improvement of the overall Drilling and Completion Performance was also noted. An important improvement of the overall Rate of Penetration (ROP) was observed, as one of the key performance indicators. It was also notice a considerable reduction of the Flat time. New practices for losses mitigation in hazardous areas were stablished. The lower completion design was enhanced. The upper completion design and utilize Dual Hydraulic Packer in Oil producer well was optimized. Finally, the 1st Maximum Reservoir Contact Well was completed for two of the three Fields in the Team. The added value achieved by the implementation of these innovative practices includes the implementation of the KPI Gauges as a visual instrument to be used on daily operations meeting by the engineers and management, to quickly and effectively understand performance and improvement in multiple dimensions. Additionally, the implementation of a continuous improvement mind-set, focus in introducing changes gradually instead of radically to ensure a soft and solid adoption embraced by all team members. Finally, the improvement of the office-field communications, including a sense of ownership and achievement for each goal to achieve and record to break, to the point that every colleague involved in a specific operation, independently of their organization (Operator, Contractor or Service Company) is equally committed and engaged.

This Extended Reach Drilling (ERD) field re-development predominantly from four artificial islands of a giant offshore field in the United Arab Emirates (UAE) requires in most cases extremely long laterals in order to reach the defined reservoir targets, by the field development team. The giant offshore field can be effectively split in to two (2) geographical sections; East and West. The East portion of the field has been developed extensively and is considered to have good reservoir properties. The West portion of the field has much lower quality reservoir properties and requires an engineered lower completion liner in order to deliver the required well performance that will adequately produce and sweep the reservoir. The engineered liner along with the extremely long laterals means significant time is spent switching the well from reservoir drilling fluid (RDF) non-aqueous fluid (NAF) to an aqueous completion brine. In order to reduce the amount of rig time spent on the displacement portion of the completion phase, technologies have been developed to provide a method of switching the well from RDF NAF drilling fluid to an aqueous completion brine, without the associated rig time of the current displacement method. This technique eliminates the use of a dedicated inner displacement string and allows for the displacement to be performed with the liner running string, saving on average five (5) days per well. In this paper the authors will demonstrate the technology and system developed to perform this operation, as well as the qualification, testing, field installations and lessons learned that were required to take this solution from concept to successful performance improvement initiative.

This development predominantly from four artificial islands of a giant offshore field in the United Arab Emirates (UAE) requires isolation of the reservoir during deployment of advanced ERD upper completions. This methodology to isolate the reservoir, during upper completions, carries through to rigging down the Blow Out Preventer (BOP) and offline Xmas tree installation operations. These well construction barrier requirements are met with the use of a tubing deployed barrier device and packer within an intermediate completion that is deployed as a separate trip in the hole on drillpipe to isolate the reservoir. Prior to running the upper completion both packer and barrier device are suitably tested to confirm their barrier status. Current barrier devices utilized in the field development require wellbore intervention with either slickline or coiled tubing to remove the internal barrier in the devices. Both of these methods pose a financial impact and operational risk to the well. In addition, they can cause delays to the rig schedule as the intervention in some cases needs to be done on critical rig path, in situations where the next well on the schedule prevents offline access. Development plans to both minimize current and future wellbore interventions with slickline or coiled tubing, and maximize Inner Diameter (ID) to allow for remedial completion operations, resulted in a requirement for a barrier device with both remote actuation and large internal bore. The authors describe the process undertaken to develop, qualify and deploy a big bore, Remote Actuated Barrier Device (RABD) to meet the field development requirements.

The long term development from four artificial islands of this giant offshore field in the United Arab Emirates (UAE) is requiring longer and longer ERD wells. This can only be achieved by drilling higher angle, higher departure and increasing lateral lengths. Horizontal departure ratios have increased from 2:1 to 3:1 and will, before the development has finished approach 4:1. Maximum Reservoir Contact (MRC) lateral lengths at the beginning of the development were planned to average 10,000ft but are already being lengthened to 20,000ft, and beyond. This paper describes the many challenges that have arisen and have been successfully overcome to enable deployment of 6 5/8" horizontal lower completions of lengths up to 20,000ft into wells that are greater than 30,000ft MD. These challenges have been surmounted through the use of proprietary in-house software, leveraging partner resources and global experience, close collaboration between drilling, completion and field development teams, new technology equipment development and deployment methodologies. Several case histories will be presented and discussed at length in this paper. These will focus on specific aspects for each of the wells such as the; high strength liner connections, high load liner running tools, reservoir drilling fluid composition, swellpacker design, use of drillpipe or casing swivels, centraliser type and the effect of dog leg severity in the long reservoir lateral.