The Main Area Claymore Reservoir: A Review of Geology and Reservoir Management

Abstract

Summary The Main Area Claymore reservoir (MACR) is the major reservoir of the Claymore field, located 110 miles [177 km] northeast of Aberdeen in U.K. Block 14/19, offshore North Sea. An integrated team effort by geologists, geophysicists, and engineers has led to an increase in recoverable oil for the MACR. Concurrently, the MACR production increased from 47 to 57 MSTB/D [7472 to 9062 stock-tank m3/d] from mid-1984 to the end of 1986. The MACR is of Late Jurassic Age. Fine- to coarse-grained sandstones of the Sgiath and Piper formations are succeeded by the very-fine-to medium-grained sandstones of the Claymore sandstone member (CSM) of the Kimmeridge clay formation. The CSM constitutes the bulk of the MACR and is divided into two informal reservoir units: the low gamma ray sands (LGRS) and the high gamma ray sands (HGRS). The principal early field problems were lack of sufficient pressure support, uneven water advancement in both the horizontal and vertical directions, and a large pressure gradient across the reservoir. Thus, more offtake and selective injection points were required to improve oil recovery. Growth of geological and engineering knowledge of the MACR has resulted from infill drilling and the integration of repeat formation tester (RFT) pressures, flowmeters, well logs, detailed core studies, and three-dimensional (3D) seismic. Increased current oil production and recoverable reserves are the consequences of this work. To improve oil recovery, a 10-slot subsea template for water injection was installed in Summer 1985. Three subsea water injectors have been drilled from this template and five platform wells redrilled as producers to downdip areas of the MACR. The recent drilling program owes its success to the combined efforts of a multidisciplinary team, which resulted in the optimum placement of wells and the adoption of selective completion to optimize areal and vertical sweep efficiencies. Introduction The Claymore field is located in the U. K. offshore North Sea Block 14/19. The MACR, the major reservoir of the Claymore field, was discovered by Well 14/19–2 in May 1974. This well encountered 519 net ft [158 m] of Late Jurassic oil sandstones, with the top sand at 8,067 ft subsea (SS) [2459 m SS]. An oil/water contact (OWC) was penetrated at 8,655 ft SS [2638 m SS]. After the discovery, three wells, Wells 14/19–3, 14/19-4, and 14/19–5, were drilled in the MACR. Four more wells were drilled outside the MACR in Block 14/19 before field development. Production from the MACR began in Nov. 1977. The MACR contained 978 × 106 bbl [155.5 × 10(6) M3] of 25 to 31 degrees API [0.90- to 0.87-g/cm3], highly undersaturated oil. The oil viscosity ranges from 2.5 cp [2.5 mPa.s] at the crest of the structure to 7.0 cp [7 mPa.s] near the OWC. The MACR average permeability is 150 md; the average porosity is 21.5%. This paper describes key points of geology, some of the historical problems, and the multidisciplinary team approach to improve geologic and engineering understanding of the reservoir. This team approach to reservoir management has led to an optimum development, resolution of historical problems, and an increase in oil production and ultimate recovery. Geology and Reservoir Properties Structural Setting. The Claymore field is located on the southwest margin of the Witch Ground graben, a northwest-trending branch that developed off the existing central North Sea graben system (Fig. 1). The Main Area Claymore (MAC) is a triangular, south-dipping, truncated fault block, lying on a dip slope, dipping away from the Witch Ground graben. The structure results from the intersection of three tectonic trends: the northeast/southwest Ordovician/Devonian Caledonian trend, the west/east Carboniferous Permian Hercynian trend, and the northwest/southeast Jurassic/ Cretaceous Cimmerian trend. Deposition of the Late Jurassic MACR was intimately related to major Cimmerian tensional movements as the Witch Ground graben developed. Uplift, tilting, and erosion took place before deposition of the Cretaceous. Fig. 2 is a top MACR structure map, and field statistics are given in Table 1. Reservoir Terminology. The stratigraphic nomenclature for MAC is shown in Fig. 3. The MACR is divided into four units: the Sgiath formation, the Piper formation, the LGRS, and the HGRS. The LGRS and HGRS are two informal reservoir subdivisions of the CSM of the Kimmeridge clay formation. Table 2 summarizes the reservoir parameters of these units. Sgiath and Piper Formations. The Sgiath and the Piper formations are of minor importance in the MACR. They contained only 5% of the total stock-tank original oil in place: the Sgiath is restricted to the updip area because of structural elevation and Piper sand facies are restricted to the southeast. The Oxfordian Sgiath formation consists of paralic sands, coals, and shales that rest with minor angular unconformity on fluvial deposits of the Triassic Skagerrak formation. Sgiath sands comprise subarkosic, finingupward beds that represent the onset of Late Jurassic marine transgression into the Witch Ground graben. The Late Oxfordian/ Kimmeridgan Piper formation consists of organic-rich silty shales, with some poor reservoir quality, heavily bioturbated sands present only in the southeast, Well 14/19–4 to Well CO7 area. The Piper delta fringe to marine, fine-grained clastics were deposited as Jurassic sea level rose over the downwarping Witch Ground graben. Claymore Sandstone Member (CSM). The Late Kimmeridgian to Mid-Volgian rifting of the Witch Ground graben was accompanied by a massive influx of fine-grained sands that filled in the de-veloping topographic lows. The CSM sands were deposited into a stratified water column, where anoxic bottom layers favored the preservation of organic matter. Kerogen is present both as silty laminae and dispersed within the sands, giving rise to high gamma radiation levels up to 120 API units. The LGRS have an average level of 50 API units, compared with 70 API units in the HGRS. More kerogen is present in the HGRS where the average bed thickness is 0.5 ft [0.15 m], compared with 1.0 ft [0.3 m] for the LGRS (Table 2). The differences in bed thickness and reservoir properties, particularly permeability, are the major distinguishing features between the HGRS and the LGRS. The permeability differential is most apparent in the oil leg, with higher resistivity values in the more permeable zones (Fig. 3). Other logs-particularly dipmeter, density/neutron, RFT, and production logs-have been used to improve the HGRS/LGRS throughout the field. The HGRS and LGRS were probably derived from the same provenance. They are clean, fine- to very-fine-grained subarkoses with very little detrital or authigenic clays. Cementation is principally by quartz overgrowth with only minor, late-stage carbonate concretion development.