The Clair field could be described as an ‘unconventional’ conventional reservoir. The rock matrix permeability places reservoir into the conventional category, for which conventional fracturing design in terms of high proppant concentration and fracture conductivity are required for production uplift. However, the presence of natural fractures brings the Clair field a similarity to unconventional reservoirs where impact and contribution of natural fractures must be taken into the equation. This paper describes the integrated fracturing and production optimization study that was conducted to optimize multistage hydraulic fracturing design in the presence of natural fractures of various density in the Clair field. The production uplift of hydraulic fracturing in conventional reservoirs is well understood. However, the presence of natural fractures adds an unconventional twist of complexity and uncertainty to fracturing design and even more so to production uplift estimates. To reduce the uncertainty of hydraulic fracturing uplift in the presence of natural fractures, specialized software was used to explicitly model cases with a range of density discrete fracture networks (DFNs) and the interaction with hydraulic fractures. Then the resulting fracture geometries were input into production modelling software to estimate uplift and calibrated back to producers in the segment. This process was repeated for several reservoir scenarios and fracturing designs to establish the production uplift range and ultimately inform optimal hydraulic fracturing design recommendations. One of the most valuable, yet not most intuitive observations was that the natural fractures and the hydraulic fractures can have a synergistic effect on production. All DFN cases modelled showed benefit from using hydraulic fracturing including high density DFNs. Even when natural fractures are already present, hydraulic fractures will help in connecting the natural fractures to the well and increase production. Higher numbers of hydraulic fractures were associated with the best uplift predictions. The described work has been instrumental in changing how hydraulic fracturing is being considered for naturally fractured reservoirs in general and for the Clair field in particular. Hydraulic fracturing had originally just been seen as a mitigation to a poorly fractured (low/no DFN) outcome. With the results of this study however it is evident that hydraulic fracturing is also an enabler for increased production in a wide range of DFN cases. Several practical recommendations have resulted from this study such as multistage fracture spacing, number of fractures, optimized proppant placement between stages and fracture geometry. The impact of fracture vs wellbore orientation and overflush were also modelled. This is the first time such a workflow has been applied for a conventional yet naturally fractured reservoir. The proposed modelling workflow allows for optimization and robust fracturing design in environment of reservoir and geological uncertainties.

The integration of data and discipline specific knowledge is a common challenge when attempting to optimize or accelerate an asset's recovery through hydraulic fracture stimulations. Any potential omission of data or understanding will increase uncertainty and a project's chance of failure. Therefore, when looking to optimize the production of a given asset, it is key to take a holistic approach that breaks down any technical and organisational barriers. This project couples the output of the different subsurface and stimulation disciplines to reduce the uncertainty associated with the production forecast of planned stimulation designs. The following paper presents the integrated approach for the Graben sector of UK's North Sea Clair oil field, largest oil field currently in Europe. Geophysicists, petrophysicists, and geologists generate a static model which is calibrated and validated by reservoir engineers through dynamic reservoir simulation. This model is used to identify the optimum exploitation scenario for a hydrocarbon reservoir and is assessed by the geomechanics engineer to deduce the subsurface stresses and strains to create a 3D mechanical earth model. The multidisciplinary validated representation is handed over to the stimulation engineer to implement various treatments, either performed or to be performed. Once these treatments are designed, the reservoir engineer produces a production forecast which is then fed back to all team members involved in the process, enabling an optimization loop. Considering that this is a multi-well (producers and injector) study, any inference is reflected by the analysis and the optimum hydraulic fracture design is chosen for implementation by an offshore stimulation vessel. Traditionally, for forecasting purposes, hydraulic fractures can be implemented using conventional reservoir simulation; however, these are very much approximated models of what the stimulation engineers are designing and implementing. Often, the reservoir, production, stimulation engineers can come up with individual forecasts that are obtained independently and omit basic information. A typical example is the way stresses might change due to stimulation and production and the possibility to account for them in an integrated way. The proposed workflow eliminates these shortcomings, and the asset team delivers a single forecast of the exact fracture design considering a fully consistent model of the subsurface, which is to be implemented by the stimulation vessel for the different wells.

Glass reinforced epoxy (GRE) lining is a polymer composite material, the main components of which are a thermosetting resin and a fiberglass reinforcement. The combined properties of its components result in a material with excellent chemical, thermal and mechanical performance. GRE lining is typically used as a coating on production tubulars in oil wells to protect metallurgy of tubulars from corrosive environments, thereby extending the life of tubulars and realizing cost savings. GRE lining is chemically compatible with many acids used in well stimulation to restore productivity. Typical acids such as hydrochloric, formic, acetic etc. involve carbonate removal followed using hydrofluoric (HF) based acids for removal of small formation particles. However, the use of HF is typically not recommended in GRE lined tubulars due to potential interactions with HF. Yet, in most sandstone reservoirs, HF fluids contribute greatly to restoring well productivity due to formation damage removal related to fines and clays. While GRE lining is a well-known technology, its chemical compatibility with acids is challenging to predict due to its heterogenous nature and requires specific testing to understand potential for mechanical degradation. Prior studies at BP focused on evaluation of GRE performance with 9% HCl: 1% HF under ambient boundary conditions of 77°F for 24 hours. These tests caused unacceptable levels of mechanical degradation to GRE and plans to execute stimulation treatments in GRE lined wells were abandoned. However, an increasing number of GRE lined underperforming water injector well stock necessitated a less aggressive acid design involving 0.5% HF. Therefore, 0.5% HF was assessed for GRE lining compatibility, mechanical and physical property changes under specific well boundary conditions at elevated temperatures of 120°F and 140°F and extended times of up to 72 hours. Core flow tests were also carried out to evaluate the effect of GRE exposed acid to any potential for formation damage. This study demonstrated that exposure of GRE lining to 0.5% HF resulted in acceptable retention of mechanical properties and did not show any formation damage impacts. These results were also reflected in field performance where a significant injectivity index improvement of >4 was achieved, thereby opening the door to a significant increase in number of GRE lined wells to be treated across multiple regions.

This paper describes the evolution of subsea stimulation treatments within one field including a novel dual vessel approach that was developed and successfully implemented on multiple wells. The methodology that enabled stimulations of high volume, complexity and precision is described, including observed results and opportunities for continuous improvement. In a harsh low oil price environment such cost-efficient stimulations can unlock additional potential for many subsea developments. Three West of Shetlands (WoS) injectors stimulation campaigns successfully delivered 11 subsea well treatments with a novel dual vessel batch approach in 2020 delivering operations of outstanding efficiency and reservoir results while driving costs down. A construction vessel provided remotely operated vehicle (ROV) support including deploying the well control package, whereas the stimulation vessel ran its own downline to facilitate optimized use of its dedicated pumping system and large chemical handling capacity. To enable deep water stimulation, the quick connect downline was engineered and project specific equipment installed onto the stimulation vessel allowing deployment to 450m water depth. Notable cost reductions in excess of 34% were achieved utilizing the efficiency offered by manifold entry for batch treatments to minimise the number of subsea re-connection operations while the stimulation vessel allowed much larger bulk loadouts and optimised the number of vessel loadings for continuous operations. This novel dual vessel approach for batch subsea stimulations allowed multiple well access through ‘daisy chains’ within isolated pipeline segments, while keeping injection operations live to other wells from the Glen Lyon Floating Production Storage and Offloading Vessel (FPSO) in the Schiehallion field. Improved HSE performance was achieved through reduced chemical handling and transportation. Real time data solutions for onshore monitoring were developed which aided the management of COVID-19 risks. The post-stimulation injection rate from the stimulation has signifcantly improved in all wells, resulting in large additional injection capacity for the field. Maintaining increased injection capacity has proved to be a challenge. The acquired understanding regarding water quality and longevity of treatments will allow identification of further continuous improvement opportunities to enable sustainable stimulation results.