|THE CLIPPER SOUTH FIELD DEVELOPMENT, SNS|
|Field Developments and Case Studies|
1RWE Dea UK
The Clipper South gas field is located in the Sole Pit of the mature Southern Basin of the UKCS. The original licences were awarded to Shell/Esso in the first licencing round in 1964. The field was discovered in 1983 by operator Shell and further appraised in 1992. The field comprises a Rotliegend Leman sandstone formation, comprising primarily Aeolian and fluvial deposits. It has a >95% net to gross ratio with a 600 ft thick gas column. It is spread over an area of 25 square kms, and located only 7 kms from active pipeline infrastructure. It has an estimated 500 BCF of gas in place. Despite these favourable statistics, it has never been developed; until now.
|TIGHT GAS RESERVOIR|
The Clipper South reservoir, like many of its Sole Pit neighbours, is tight; the permeability is very low, the gas flows poorly. Although the reservoir sand is described as “clean” and has a moderate porosity of 9%, the pore connectivity, quantified by permeability, has become impaired through a process of “illitisation”. Illitisation is a diagenetic process which has resulted from the reservoir being deeply buried, thus exposed to high temperature and pressure, after its deposition. Clipper South sits on an axis of the Sole Pit basin which is believed to have been buried particularly deeply. Although less deep now, the reservoir retains the severe diagenetic impairment of its permeability.In terms of flow rates, the discovery well 48/19a-3 tested at an initial rate of 1 MMscfd. The effective permeability was assessed as 0.04 to 0.10 milliDarcies. For tight gas fields, hydraulic fracturing is well established as a means to enhance productivity. Shell undertook a hydraulic fracture treatment on the 48/19a-3 well. The fracture treatment and the data gathering were meticulously planned and documented. After fracturing, the same tested interval flowed at a steady, but disappointing rate of 3 MMscfd. After nine years of reflection, Shell returned to the field in 1992, hoping to achieve commercial productivity through a horizontal well. The 48/19c-13Z appraisal well was drilled with a 2,200 ft near horizontal reservoir section. Under test, this well produced at a maximum rate of 1.5 MMscfd. The permeability was assessed at 0.12 milliDarcies assuming a 60 ft flowing interval. Clipper South was duly consigned to the well files. After fifteen years lying dormant, Clipper South was offered for auction by Shell and Esso, and a new owner was found in Fairfield Energy, a privately funded start-up company with an appetite for innovation.Fairfield worked towards determining a development solution and quickly identified a concept, which it believed could be profitably developed. It then sought a partner to help realise this plan. Fairfield’s new partner, and now the Clipper South Operator is RWE Dea UK.
|DEVELOPMENT WELL CONCEPT|
Horizontal wells with multiple massive-hydraulic-fractures. This is the well concept selected by Fairfield to break through the Clipper South permeability barrier.
Fracturing entails the propagation of a fracture in the reservoir by pumping viscous fluid at high pressure into the reservoir through a restricted entry point. Once formed, the fracture is held open by injecting a slurry of fluid mixed with selectively sized sand or proppant. This process is repeated in sequence through discrete entry points along a horizontal wellbore to create multiple fractures. The fractures serve to vastly increase the surface area of reservoir exposed to the wellbore, resulting in the enhanced production capacity of the tight reservoir. This technology is gaining momentum globally, having been employed onshore in the US for exploiting shale gas, and also for developing tight Rotliegend gas fields onshore in Germany. Currently, two gas fields have been developed in the Southern North Sea with this technology: Centrica’s Chiswick field (Carboniferous reservoir, developed by Venture Petroleum) and Eon Ruhrgas’ Babbage field (Leman reservoir). The latter is the nearest analogue to Clipper South and started production in August 2010.
|CHARACTERISING AND BENCHMARKING THE RESERVOIR|
To demonstrate the feasibility of
Data, where available, was collected from analogue fields with similar reservoir properties and fracture treatments. The results of this study were summarised in a single graph, which shows the aggregated productivity index of a multiple-fractured well as a function of the reservoir permeability and the combined fracture treatments on each well. The initial productivity and ultimate recovery per fracture were used as the two key tests of commerciality.
|MODELLING THE WELLS AND THE RESERVOIR|
A Clipper South full-field model was built to determine the optimum number of wells and fractures required to deplete the field. Analogue fields studied have employed up to nine hydraulic fracture treatments per well. Nevertheless, a maximum of seven hydraulic fractures per well was considered an appropriate limit for offshore operations. Fractures were modelled by the use of local grid refinements. To ensure model stability, these were upscaled from a real fracture width of up to one inch to a modelled width of thirty feet. Different fracture dimensions were applied to represent variable treatment sizes, constrained by vertical closure and the height of the wellbore entry point relative to the top and bottom of the reservoir. The modelling determined that the optimum recovery from the field could be achieved with twenty seven fractures conveyed by five horizontal wellbores. The most significant variables in the evaluation were the assumed reservoir permeability and the total effective surface area to flow generated by the fractures. This latter parameter is the product of the fracture dimensions, the number of fractures and the assumed fracture efficiency. Whilst neighbouring fields have benefitted from the presence of open natural fractures in the reservoir (indeed some evidence of natural fractures is observed in the Clipper South cores), the Clipper South model assumed no production contribution from any open natural fracture system.
The offshore execution of hydraulic fracturing has historically been undertaken by purpose-built “frac” boats, which are generally in limited supply. Recent
Fracturing operations are usually undertaken from a stimulation vessel alongside a drilling rig. Rig-based coiled tubing services are required to undertake selective zone perforating for each fracture entry point and to clean-out and isolate each zone in sequence. After the full sequence of fractures has been performed, the zone isolations are removed and the well is cleaned up through temporary well test equipment. The fracturing and clean-up of a single well can take four to six weeks, which can be costly in terms of rig use.
|DEVELOPMENT FACILITIES CONCEPT|
Clipper South will be developed using a standalone wellhead platform. A key feature of the Clipper South platform is its ability to support well fracture, clean-out and testing operations without the requirement for a drilling rig. This is facilitated by the provision of a large (33 m x 38 m) deck space, accommodation for 40 personnel, and a 25 tonne rated crane.
Wells with multiple fractures are likely to produce some proppant during their producing life. The abrasive nature of the proppant-entrained gas determines the need for solids removal equipment. The platform will be equipped with wellhead hydro-cyclones to eliminate entrained solids.
Once the wells have been fractured and the wells are clean, the platform is designed to operate as an un-manned facility under normal production conditions.
The Clipper South development will make use of existing pipeline infrastructure. Three pipelines are located within fifteen kilometres of the field, and the LOGGS system has been selected as a suitable host for Clipper South.
The selected development concept reduces both capital development and life-cycle costs. The deck space and accommodation will facilitate walk-to-work and standalone well interventions throughout field life.
The development programme entails the construction and installation of the platform and pipeline, which will be tied back to the LOGGS complex. The installations are planned for the summer of 2011. The first phase of drilling will be undertaken through the platform, commencing in Q4 2011. A total of five wells are planned of which three or four will be drilled in Phase 1. First gas is planned for Q1 2012.
The Clipper South development would not be possible without the imagination, commitment and courage of both Joint Venture partners, RWE Dea