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Coghlan G.,Venture Production Plc
Proceedings of the Annual Offshore Technology Conference | Year: 2010

The Central North Sea Pilot field lies in UK license block 21/27. In 1989 a discovery of heavy oil - by North Sea standards - was made in Eocene sands at a depth of 2700ft TVDSS. Three vertical appraisal wells determined relatively extensive, thin package of turbidite sands (ca.100ft) of limited relief (ca.150 ft). Early flow-testing was constrained by difficulties in sustaining flow because of separation and flaring problems due to low rates, water coning, also sand production. Sampling was problematic with oil properties ranging from 17-22 degAPI and 90-160 cP. In 1998, a 'prover', horizontal well was completed with an ESP with the intent to prove up sustainable, commercial rates, however this was not achieved, because the oil samples pointed to an oil of much lower quality than expected, 13 degAPI and 1900 cP. Venture Production acquired the field in 2001 as part of a package of acquisitions. Subsequently all historic data were reviewed and a major effort to move field development forward resulted in the identification of several innovative approaches, centred on a cylindrical hull FPSO to commercialise this geographically stranded (nearest infrastructure 25miles), technically and commercially challenging opportunity. A postulated, developable OIIP of 110 MMstb with a viscosity of ca.100 cP or less was to be targeted by horizontal, hydraulically pumped wells and a waterflood. Key uncertainties were a) the oil quality distribution and b) the need to recover samples of sufficient volume to allow flow assurance issues (such as calcium napthenate and sodium soap) to be assessed. A further appraisal well was proposed to acquire the necessary, large-volume, representative samples on wireline. An innovative appraisal strategy utilising a geotechnical drillship with much-reduced drillex was planned but the program could not clear all necessary HSE hurdles - resulting in a delay of 1 year and a conventional drilling program (and costs). The appraisal well was drilled in 2007 and determined that oil quality was variable and unpredictable and the necessary minimum OIIP/ reserves for project sanction could not be assured. Follow-up studies resulted in a decision to relinquish the acreage after 20 years of work. Copyright 2010, Offshore Technology Conference. Source

Nesbit R.,Schlumberger | Overshott K.,Venture Production Plc
Petroleum Geology Conference Proceedings | Year: 2010

Twenty-three years after BP discovered the Chiswick Field in 1984, first gas production was achieved by Venture Production. During its long period of appraisal and development, this asset has passed between five different operators and a large number of co-venturers. Prior to development, the field represented one of the largest undeveloped gas volumes present in the UK Southern North Sea. Key uncertainties include reservoir compartmentalization, low net/gross ratios and poor reservoir permeability, uncertainties in structural mapping and gas-water contact depths, as well as a widely varying Carboniferous subcrop and significant lateral changes in fluviatile sandstone architecture. Drilling and completion during the first phase of development were a significant challenge, with ambitious long and deep fracture-stimulated horizontal wells. The installation comprised a five-slot minimum facilities well-head platform with production tied back via the Venture-operated Markham J6A Platform with gas landed in Den Helder, Holland. As part of Phase II development a further three wells are being planned to accelerate recovery and access the remaining undeveloped reserves in both the primary Carboniferous and secondary Rotliegend reservoirs in the Chiswick Field. © Petroleum Geology Conferences Ltd. Published by the Geological Society, London. Source

Purvis K.,Venture Production Plc | Overshott K.E.,Venture Production Plc | Madgett J.C.,Venture Production Plc | Niven T.,Venture Production Plc
Petroleum Geology Conference Proceedings | Year: 2010

The Ensign Gas Field is located in the Sole Pit basin in the Southern North Sea. The reservoir is the Rotliegend Group Leman Sandstone Formation of Lower Permian age and comprises sediments deposited in an arid continental environment. The main gas-bearing interval in the field consists of sabkha, waterlain and minor aeolian sands, reflecting deposition in an erg margin/lake margin setting. The poor primary reservoir quality of these sands has been severely reduced by extensive illite cementation resulting in average air permeabilities of ,1 mD. Attempts to develop the field economically utilizing fracture-stimulated vertical wells has met with mixed results, with flow rates of 14 MMscf per day and lower being measured during testing. The most recent appraisal well drilled on the field was a long horizontal well that was stimulated with five hydraulic fractures resulting in an economic flow rate of 44 MMscf per day. Analysis of the core and log data acquired during the appraisal of the field has shown that the reservoir contains a heterogeneous distribution of fractures, faults and micro-faults. The fracture population is dominated by conductive north-south striking fractures, with subordinate NNW-SSE resistive fractures and NE-SW mixed fractures that are arranged in clusters, with zones of high and low fracture density. Well results to date suggest that the NE-SW open and partially open fractures observed in core do not improve reservoir productivity, but those orientated north-south that are conductive appear to improve well deliverability. © Petroleum Geology Conferences Ltd. Published by the Geological Society, London. Source

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