Field Life Extension in Abu Dhabi Through Hybrid Development Concept
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Field A, a giant field consisting of many subreservoirs, is offshore Abu Dhabi and has produced for 50 years, mainly through peripheral water injection. A long-term development plan (LDP) for the field aims to extend the production plateau by 25 years through infill drilling and waterfloods. This paper describes an approach for optimizing the number and type of drilling centers required to enable the development plan to be flexible in design to accommodate infrastructure, facilities, drilling, and subsurface constraints.
Field A, a giant carbonate field, has been developed for 50 years. As the field reaches maturity, it moves to another phase of development. Design of the next development phase, the LDP, began in the early 2010s. The LDP assessment stage, which screened the surface and subsurface development concept, was recently completed, and the development planning team is preparing for the selection stage. The assessment-stage conclusion was for drilling from artificial islands (AIs), wellhead towers (WHTs), or a combination of both and leaves a degree of freedom. This paper describes the optimization approach of the drilling-center options.
The LDP is just the first phase of a large-scale long-span offshore reservoir redevelopment that aims for a further 50 years of production. The complexity of the field is significant because of limited seabed space, the age of the existing surface facilities and pipelines, and challenging drilling circumstances.
These complexities differentiate the development project from other offshore projects, and an appropriate selection of drilling centers is one of the more important keys to project success.
Field and Development History
The field of carbonate reservoirs is in shallow water. The field is 40×20 km, and different reservoirs have been developed by two different operators. The stack of reservoirs is divided into shallower reservoirs (U Reservoirs) and deeper reservoirs (L Reservoirs).
The L Reservoirs are geologically divided into two major reservoirs, L1 and L2, which have been developed similarly. The development began with natural production with original reservoir energy. Beginning in the 1970s, pressure maintenance through dump floodwater injection by connecting the target reservoirs with a shallow aquifer was conducted for 10 years. For further reservoir-pressure maintenance, powered peripheral water injection was started, and the development scheme has been continuous, with reinforced pressure maintenance through immiscible gas injection from the top structure.
Currently, the field development calls for increasing the density of peripheral water injectors and infill producers, with improvements in injectivity and productivity achieved through well horizontalization and control of fluid distribution with advanced completion technologies. Additional water-injection reinforcement is planned in the middip area for further pressure support.
Development-Plan Overview and Challenging Environment
Overview of LDP. Because of the different natures of the reservoirs and the different maturity levels with respect to the ongoing development, Reservoirs L1 and L2 are developed with different schemes. Reservoir L1 development continues the peripheral water injection, with a line of water injectors at the middip area dividing the field into two parts and enhancing pressure support. Gas injection from the crest will be reinforced with an increasing injection rate using existing wells and facilities. Reservoir L2 will be developed initially with a five-spot water-injection pattern, followed by an inverted-nine-spot pattern of water injection with full gas lift.
This development plan requires new infill drilling of 180 wells, both oil producers and water injectors. Pipelines, water-injection-capacity upgrade, gas lift equipment installation, and processing-facility construction are also needed. These 180 wells can be drilled from AIs or from steel structures such as WHTs. Deciding the optimal number and type of drilling centers is the focus of this paper.
Challenging Circumstance for Redevelopment. To implement the development plan successfully, the following challenges must be managed properly:
- Seabed space is already occupied by pipelines, and the available space for future development is limited.
- Aging facilities need to be replaced.
- The U Reservoirs have been and will be developed differently than the L Reservoirs because of their different natures.
Related to the first and second points, the seabed needed for surface-facility development is already quite occupied with many pipelines, steel structures, and AIs from previous development.
Empty slots remain, however, on the existing WHTs, and those 180 new wells could be drilled from there. Maximum use of existing WHTs is a preferable option purely from a short-term economic point of view. The option, however, is not encouraging because the existing WHTs are already aged (the majority of those towers were constructed in the 1980s) and their continued use for an additional 50 years without integrity issues seems unlikely.
Creating new drilling centers (WHTs or AIs) would be a more-realistic option. Nevertheless, the number and type of drilling centers must be decided carefully because seabed space is already quite limited.
With respect to the third point, different reservoir characteristics require different development concepts. The U Reservoirs consist of tight reservoirs and require smaller well spacing and more reservoir contact. This results in dense well drilling and longer well trajectories. The LDP wells must avoid intersecting existing wells and faults. Ideally, drilling centers should be distributed sufficiently to cover all the target points with as few departure wells as possible to minimize the risk of intersection.
Integrated Drilling-Center Optimization
The assessment phase concluded that the following three options are technically and economically robust:
- 27 WHTs (WHT option)
- Three AIs plus two WHTs (AI option)
- Combination of WHTs and AIs (hybrid option)
The locations of the drilling centers are chosen considering subsurface target locations so that the distance from the drilling center to the well is as small as possible. Fig. 1 above shows well and drilling-center locations for the first two cases. It is assumed that 100 slots are available on each AI and 12 slots are available on each WHT.
Before the drilling-feasibility study, preliminary screening reduced the number of candidates. At this stage, three options out of seven were eliminated because of seabed obstruction or conflicts with existing facilities.
The drilling-feasibility study provides opportunities to eliminate other drilling-center options. Technical drilling limitations constitute the first screening criteria, and a few options are expected to be dropped at this stage. The study also provides an estimate of drilling duration and cost for all of the wells. Drilling duration is used to evaluate the effect on production profile. The production profile and drilling cost are then included in an economics calculation.
The final stage of the work flow is the selection of the optimal drilling-center options. All outcomes from drilling feasibility, production profiles, and project economics are integrated, and a few drilling-center options continue to the selection stage.
Drilling-Feasibility Study. Drilling Difficulty. The first two drilling-center options were analyzed by creating trajectories and designing well structures for each well. The hybrid options were evaluated on the basis of lessons learned from the first two options.
As a representation of drilling difficulty, the directional difficulty index is used. This index is an empirical index based on industry experience and represents well complexity computed using the trajectories.
Drilling Duration. Drilling duration was also estimated for all the scenarios. Wells were placed in one of seven classes on the basis of departure, and drilling duration for each well was estimated using historical drilling experience.
Drilling-Center Effects on Production Profile. Reservoir simulation was performed to evaluate the effect on production of each drilling-center option. Independent reservoir models were used for Reservoirs L1 and L2.
Drilling is assumed to start 1 year before the first oil from the LDP. The drilling sequence is based on rig location (not to allow rigs to move from one drilling center to another without completing all wells) and is consistent with the estimated duration from the drilling-feasibility study.
Selection of Optimal Drilling-Center Options. The options with more drilling centers are more advantageous for drilling feasibility and oil production; however, other aspects such as ease of workover, logistics, expandability, and capital expenditure should be considered. For this, a dedicated team was established that consisted of reservoir engineers, drilling engineers, and planning engineers. The team had several discussions regarding the findings of the drilling-feasibility study and the reservoir-simulation work to summarize technical advantages and challenges.
The work flow discussed in this paper has been used to optimize the number and type of drilling centers. By integrating outcomes from the drilling-feasibility study, reservoir simulation, economics, and net-present-value evaluation, optimal drilling-center options can be selected.
The approach followed in this project study revealed the following lessons:
- Integration of different functions and disciplines early in the project phase is paramount in field-development planning before project sanction.
- A study of the feasibility of complex trajectories and their effect on field-development concepts and production profiles is an important step in the optimization loop.
- Flexibility should be built in for expandability of surface facilities to extend field life.
Field Life Extension in Abu Dhabi Through Hybrid Development Concept
01 October 2017
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