The Stella Field is located in UKCS Block 30/6a, c. 230 km SE of Aberdeen. Stella Field is a four-way, dip-closed and salt-cored dome with a 600 ft gas-condensate column underlain by a 250 ft oil column within the 5–30 ft thick Paleocene Andrew Sandstone Member. Oil is also present in the underlying chalk reservoirs of the Danian Ekofisk and Maastrichtian Tor formations. Following the discovery of the field in 1979 there have been three phases of appraisal followed by the recent development, with first oil in February 2017.The field development has been challenging as the 38-year gap between discovery and first oil illustrates. Principal challenges have included structural undulations and radial faulting combined with a thin primary reservoir, variation in hydrocarbon, compartmentalization and depletion relating to producing fields. These issues have been reviewed following the latest drilling results and ideas on the petroleum geology updated.Block 30/6a, containing the Stella Field, was originally awarded to Shell/Esso in the first Licensing Round in 1964 as part of multi-block licence P011. The current Stella P.011 licence holders are Ithaca Energy (UK) Limited (operator) with 54.66%, Dyas UK Limited with 25.34% and Petrofac GSA Limited with 20%.
With a suppressed hydrocarbon sector over the past few years, operators, service providers and ancillary companies alike have been strongly challenged to collaborate, where feasible, on field development solutions which offer greater economies of scale and efficiency by reducing operational time and cost. This paper details the evolution of the Harrier field development plan (FDP) in the context of innovation within completion and stimulation treatment design which has successfully created value for this North Sea gas operator. Originally, the project plan comprised of two development wells, each accessing separate chalk gas reservoirs - Ekofisk and Tor which were approved by the UK Oil and Gas Authority in 2012 under the Stella and Harrier FDP, with an estimated development cost of USD 250 million. During the conceptual phase, the project economics were not attractive even in a high oil price environment. Services providers were then invited to provide alternative solutions to significantly enhance the investment appeal of this opportunity with the aim of reducing capital and operating expenditure while enhancing both field recovery and accelerated production. One such provider was successful with the proposition of a revolutionary contraction of the FDP with a unique design concept of a single well development terminating in a dual lateral with each leg targeting a separate reservoir in which fourteen acid stimulation stages per leg were planned to greatly enhance productivity. After several months of intensive collaboration, the optimized well design was completed and the project was sanctioned with field development cost reduced by a full 50%. The paper provides an overview of the stimulation design, based on the reservoir challenges encountered and the progression of the completion design explored, into its final fit for purpose realisation. Results in relation to achievement of well objectives, service delivery, change management during the execution phase and most significantly overall well performance are also provided. The objective of this paper is not only to demonstrate the value created to the field operator, but also to illustrate how planning and developing a unique solution was strongly influenced by a cost sensitive environment for efficiencies gained, with regards to risk management and mitigation, along with contingency planning. Furthermore, through a multi-segment integrated approach experience, numerous lessons learnt and best practices were harnessed for use when venturing on similar projects championing technical innovation under economic and resource constraints.
Recently two multilateral horizontal wells have been completed offshore using dedicated multistage hydraulic fracturing completions. The first well, located in the Central North Sea (referred to as ML-CNS), was stimulated using acid fracturing; while the second well, located in the Black Sea (referred to as ML-BKS), was stimulated using proppant fracturing. This paper presents the different drivers, challenges and lessons learned for each well while emphasizing the well construction and stimulation methodologies developed for the different reservoirs and field characteristics. The field development drivers for drilling and completing these offshore hydraulic fractured multilateral wells, a first of their kind globally, was different for each case. The objective of the first project, initially considered uneconomic, was to engineer a technical solution for completion and production of two separate reservoirs with only one subsea well. The second project was seeking to optimize infill drilling from the last available slot on the offshore platform to maximize reservoir contact and production in the same reservoir. ML-CNS was a TAML Level 2 completion with a 14-stage, 5 ½" multistage completion run in each lateral and set-up for sequential acid fracturing. Operationally, the first lateral was drilled and stimulated, followed by the drilling and stimulation of the second lateral, using the drilling whipstock to navigate through the multilateral junction. ML-BKS was a TAML Level 3 completion that had a 6-stage, 4 ½" multistage completion installed in each lateral, which were proppant fractured following a sequence designed to minimize the jack-up rig time required. Both legs were drilled and completed prior to starting the stimulation, access to either lateral was achieved with the existing workover unit on the platform by manipulating a custom designed BHA. The lessons learned from the first project executed in the North Sea were able to be transferred and applied to the second project in the Black Sea to allow for a more efficient and confident completion solution. Led by varying economical and regional constraints, the key factor for both wells centered on delivering operationally simple and reliable multilateral completion designs to economically meet the field development strategy in place. To the knowledge of the authors and following subsequent literature research, both wells are a worldwide first for an offshore multilateral well completed with multistage acid fracturing and multistage proppant fracturing, and together they represent a new trend in cost-effective offshore field development through well stimulation. The successful case studies for both wells with the combined analysis of the benefits, challenges, and lessons learned will provide a guide and instill confidence with operators who find this approach beneficial with a view to applying it in other assets.
A North Sea case study detailing the completion and stimulation design of the world's first offshore acid fractured multistage dual lateral will be presented. The key driver behind this subsea completion technology and stimulation program was to implement a cost effective completion solution that reduced field development costs. The completion technology selected provided an economically viable and low-risk solution in an economically challenging hydrocarbon environment. The completion design was developed to access two separate carbonate gas reservoirs from a single main bore. The stimulation program for the two horizontal laterals was modeled using reservoir characteristics and key considerations. The stimulation program maximized resource efficiency by utilizing the fluid capacities available within one sailing of the stimulation vessel per lateral, totaling 28 acid fracture treatments. This novel offshore acid fractured dual lateral was drilled, completed and stimulated within three months. The horizontal section of the motherbore was completed using a 14 stage openhole multistage completion solution in three days. To reduce time on location, the well was stimulated after reaching setting depth via a tie-back fracture string. The motherbore was stimulated with individual and distributed acid fracture treatment via sequential ball-activated sliding sleeves. Once operations were complete for the motherbore, a whipstock packer was set and the second horizontal wellbore (Leg 2) drilled. The E1 Leg 2 wellbore was completed in only two days using the same technology and setup as the motherbore. Once the bottomhole completion was set, Leg 2 was stimulated with 14 stages of acid fracture treatments, using the same sized ball-activated sliding sleeves as in the motherbore. By implementing a flexible low cost completion solution and maximizing the resources available during stimulation, the world's first offshore acid fracture multistage dual lateral was successfully completed, requiring only one subsea wellhead and tree. The completion and stimulation program of this dual lateral project provided a high value solution to North Sea operations by minimizing time, resource utilization and expanding experience for future ventures.
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