Clair Field Research Articles

Hydraulic Fracturing Unlocks Potential of Europe’s Largest Reservoir

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 205250, “Hydraulic Fracturing at Clair: Unlocking the Potential of Europe’s Largest Reservoir,” by Alistair M. Roy, SPE, Graeme H. Allan, SPE, and Corrado Giuliani, SPE, BP, et al. The paper has not been peer reviewed. _ Greater Clair, Europe’s largest oil field, has two existing platforms, Clair Phase 1 and Clair Ridge, on production with the potential for a third platform targeting the undeveloped Lower Clair Group (LCG) to the South of Phase 1. In some areas, however, low matrix quality and lack of natural fractures were the dominant characteristics, resulting in lower production rates. The authors write that fracturing technology brings opportunities to unlock poorer Phase 1 and Ridge reservoir areas. Introduction Reservoir Description. The Clair field is 75 km west of the Shetland Islands on the UK Continental Shelf within the extensional Faroe-Shetland Basin. The Old Red Sandstone reservoir is divided into two lithostratigraphic units, the Upper and LCG. The LCG contains the bulk of the oil in place and underpins the Clair development. The reservoir is characterized by large variations in facies and permeabilities. The LCG is subdivided into six units, I through VI, based on variations in sedimentary facies and heavy mineral assemblages. Development drilling preferentially targets the highest quality reservoirs in Units V and III. The LCG is defined as a dual-permeability system with a variable fracture distribution. Three main scales of fracture features are observed in the core: fault-related, fracture corridors unrelated to large offsets, and lower-density joint-type networks. Open fracture density varies considerably by stratigraphy, with the highest densities in Units V and VI. Field Development Phases. Exploration Well 206/08-1A discovered Clair in 1977. Clair underwent a protracted appraisal program before sanction of the Phase 1 development in 2001. The commercial viability of the reservoir was not confirmed until an extended well test in 1996 proved that oil rates from 15,000 to 20,000 BOPD could be sustained from long horizontal wells targeting high-productivity fracture zones. The scale and complexity of the reservoir drove a phased multiplatform development. Phase 1 began production with 20 producer and injector wells coming online between 2005 and 2011. Five additional wells drilled during 2016–2017 increased platform production by 70%. The second platform, Clair Ridge, came online in 2018, and the development wells drilled to date have encountered varying degrees of natural fractures. Design and Characteristics of Well A23 for Hydraulic Fracturing Candidate Well for Propped Fracturing. Horizontal Well A23 was completed in March 2017. The lateral penetrated the low-permeability unfractured Unit VI of the LCG in the Graben area of Phase 1. It crosses the core/graben fault, which is assumed to act as a baffle to communication between Zones 1 and 2 and Zones 3 and 4. Well A23 was put on gas lift production in 2017, producing approximately 1,300 BOPD. The well trajectory was designed to remain 40 m above the shale layer and to facilitate roughly transverse fractures within Unit VI Upper by drilling perpendicularly to the maximum horizontal stress to overcome vertical drainage issues.

Fracture attribute scaling and connectivity in the Devonian Orcadian Basin with implications for geologically equivalent sub-surface fractured reservoirs

Abstract. Fracture attribute scaling and connectivity datasets from analogue systems are widely used to inform sub-surface fractured reservoir models in a range of geological settings. However, significant uncertainties are associated with the determination of reliable scaling parameters in surface outcrops. This has limited our ability to upscale key parameters that control fluid flow at reservoir to basin scales. In this study, we present nine 1D-transect (scanline) fault and fracture attribute datasets from Middle Devonian sandstones in Caithness (Scotland) that are used as an onshore analogue for nearby sub-surface reservoirs such as the Clair field, west of Shetland. By taking account of truncation and censoring effects in individual datasets, our multiscale analysis shows a preference for power-law scaling of fracture length over 8 orders of magnitude (10−4 to 104 m) and kinematic aperture over 4 orders of magnitude (10−6 to 10−2 m). Our assessment of the spatial organization (clustering and topology) provides a new basis for up-scaling fracture attributes collected in outcrop- to regional-scale analogues. We show how these relationships may inform knowledge of geologically equivalent sub-surface fractured reservoirs.

The Clair Field, Blocks 206/7a, 206/8, 206/9a, 206/12a and 206/13a, UK Atlantic Margin

Abstract The Clair Field is a giant oilfield containing in the region of 6–7 Bbbl of stock tank oil initially in place, located approximately 75 km west of the Shetland Islands. As such, it represents the single biggest hydrocarbon accumulation on the UK Continental Shelf. Clair was discovered in 1977, but first production did not occur from Phase 1 until 2005, after a lengthy appraisal period. The major appraisal milestone occurred in 1991 after well 206/8-8 proved up fractured clastic red beds of the Devonian Lower Clair Group. This was followed up with an extended well test on 206/8-10Z, which demonstrated the longer-term performance of the reservoir. Further appraisal on Clair Ridge led to the sanction of the Clair Ridge, which came on stream in November 2018. Following the Greater Clair appraisal programme in 2013–15, development options are currently being worked for Clair South, which will develop the Lower Clair Group reservoirs together with overlying shallow-marine reservoirs of the Cretaceous and Jurassic.

E&P Notes (January 2019)

E&P Notes (January 2019)

Correlation of Hydrocarbon Reservoir Sandstones Using Heavy Mineral Provenance Signatures: Examples from the North Sea and Adjacent Areas

Correlation of hydrocarbon reservoir sandstones is one of the most important economic applications for heavy mineral analysis. In this paper, we review the fundamental principles required for establishing correlation frameworks using heavy mineral data, and illustrate the applications of a wide variety of heavy mineral techniques using a number of case studies from hydrocarbon reservoirs in the North Sea and adjacent areas. The examples cover Triassic red-bed successions in the central North Sea and west of Shetland, which have been subdivided and correlated using provenance-sensitive ratio data and mineral morphologies; Middle Jurassic paralic sandstones in the northern North Sea, correlated using garnet geochemistry; Upper Jurassic deep water sandstones in the northern North Sea, discriminated using rutile geochemistry and detrital zircon age data; and the “real-time” application of the technique at well site in Devonian-Carboniferous fluvio-lacustrine sandstones of the Clair Field, west of Shetland.

Generating value from 4D through efficient integration

The use of time-lapse (4D) seismic at BP now has a track record stretching back more than 20 years. In the North Sea, reservoir types such as Tertiary turbidites and Cretaceous chalks produced clear 4D signals, and uptake increased rapidly in the late 1990s. In the Gulf of Mexico, 4D was generally more challenging due to greater subsurface complexity, but the industry made breakthroughs with modern acquisition systems such as ocean-bottom nodes (OBN). The challenge now is to maximize the value of existing and new surveys by better integration of 4D into reservoir management. As part of this effort, the authors implemented fit-for-purpose workflows for 4D-assisted history matching (4DAHM) and 4D geomechanical modeling. In an example from west of the Shetland Isles, UK, running the 4DAHM match-quality tool on multiple monitors from the Clair Field allows the field team to quickly see how changes in the reservoir simulation model affect the match to the 4D and identify areas of concern. The 4D geomechanics workflow utilizes the Geertsma equation to speed up modeling of effective stress changes due to compaction. It is demonstrated on the Gulf of Mexico Atlantis Field, where the authors were able to resolve a significant mismatch between the reservoir simulation model and observed seismic amplitude responses by modeling a strong stress-arching effect due to reservoir depletion.

Structural geology and well planning in the Clair Field

Abstract The Clair Field is a giant oilfield located approximately 70 km west of the Shetland Isles, UK. It was discovered in 1977 and brought on stream some 28 years later. Key to unlocking its economic potential was a series of appraisal wells drilled in the early 1990s that identified fractures as the primary production mechanism. Structural geology contributed in several ways to the detailed planning of the development and appraisal wells. In the sandy (Tertiary) tophole section, outcrop analogues and offset wells were used to establish an appropriate standoff from major faults. This was to mitigate the risk of wellbore instability in what is otherwise a relatively benign sequence to drill. The mid-section, Upper Cretaceous mudstone is prone to wellbore instability, believed to be caused by strength anisotropy with respect to bedding. Here, polygonal faulting may contribute directly to wellbore instability. The associated bed rotation also influences anisotropic failure, which depends in part on the wellbore-to-bedding intersection angle. An example is given of how an understanding of the structural evolution of the overburden section impacts well casing placement. Finally, judgement on the nature of the faulted contact between two fault blocks was required for the pressure prognosis of a planned well.

3D characterization of fracture systems using Terrestrial Laser Scanning: an example from the Lewisian basement of NW Scotland

Abstract Fractured gneiss lithologies form a basement-cored high, the Rona Ridge in the Faroe–Shetland Basin. Basement structures are known to play an important role in the petroleum system for the overlying giant Clair Field. An onshore analogue exposure in the Lewisian Gneiss Complex at Kinlochbervie in NW Scotland provides an example of a hanging-wall damage zone of a large basement-hosted normal fault. In this study, we used remote sensing (2D), outcrop line sample methods (1D) and a virtual outcrop created by terrestrial laser scanning methods (3D) to characterize spatial variations of the fracture systems. Spacing distributions from 1D line samples collected from exposures and pseudo-wells constructed through the virtual outcrop show power-law distributions. The virtual outcrop data enable us to extend the scale-invariant description from 1 to 3 orders of magnitude. We developed a novel box-counting workflow to provide an assessment of 2- and 3D variations in the fracture properties. Fracture density and fractal dimension are elevated whereas the number of intersections is decreased within a 220 m-wide volume adjacent to the fault. We discuss how the methods and results from this study can aid the development of analogue for basement reservoirs in the offshore UK continental shelf.

Heavy mineral stratigraphic analysis on the Clair Field, UK, west of Shetlands

Hydrocarbons in the Clair Field, west of the Shetland Islands, are hosted by Devonian–Carboniferous clastic red beds deposited in a non-marine fluviolacustrine setting. The succession is almost entirely biostratigraphically barren and, hence, alternative approaches to reservoir correlation are required. Heavy mineral analysis (HMA), which subdivides clastic successions on the basis of changes in provenance and sediment transport history, has proven successful in establishing a high-resolution correlation framework for the Clair Field. Since the technique offers a reliable and rapid method for monitoring the stratigraphy of the Clair reservoir succession, HMA has been undertaken on a real-time basis at well site for virtually all development wells during Phase 1 of the Clair Field development, and for all Phase 2 appraisal wells. Heavy mineral data can be acquired in less than 2 hours from receipt of sample. Consequently, owing to the relatively slow penetration rates frequently associated with Clair drilling, stratigraphic information is usually acquired ahead of logging while drilling. Heavy mineral data are used in the decision-making process in a variety of situations, including picking of casing and coring points, whether to maintain or alter well trajectory, and when to terminate drilling. In the Clair Field, formation tops can be subtle and, since HMA can establish trends and predict formation changes before they are encountered, they are critical in aiding geosteering decisions. HMA has also been used to monitor stratigraphy and to pick formation tops when logging tools have failed, allowing drilling to continue and avoiding tripping to change the bottom-hole assembly. The application of HMA to the Clair Field development is illustrated by reference to a number of wells drilled on the field since 2005.

West of Shetland Development Gathers Momentum

BP is ramping up its West of Shetland operations with the UK government approval to push ahead with the second phase of its giant Clair field development, Clair Ridge. Plans to redevelop the Schiehallion and Loyal fields with a new floating production, storage, and offloading vessel (FPSO) are also gathering pace. The Clair reservoir is the largest known hydrocarbon resource on the UK Continental Shelf (UKCS), occupying an area of 220 sq km. It is located approximately 75 km west of the Shetland Isles in 459 ft of water. Because of its size and complexity, it is being developed in phases. Clair Ridge, in UKCS Block 206/8, lies to the northeast of Clair Phase 1 and will be tapped with a pair of bridge-linked platforms—a drilling and production (DP) facilities platform and an accommodation and utilities (QU) platform. The new platforms have a 40-year design life and will require a total capital investment of about GBP 4.5 billion (USD 7.16 billion). The topsides for the two platforms are being built in modular form by Hyundai Heavy Industries in South Korea and will be transported to the Clair Ridge field on five Dockwise heavylift vessels. Kvaerner Verdal in Norway is building the platform jackets. The DP jacket will have a total weight of 22,300 tonnes and the QU jacket will weigh 9,000 tonnes. Peter Brawley, the Clair Ridge hook-up and export systems manager, said the sheer scale of the project is a challenge in itself. “This is a huge platform we are building. The biggest platform we operate on the UKCS at the moment is Magnus at 34,000 tonnes and here, we have topsides of 40,000 tonnes. It is bigger than anything we have built in the UKCS, so the scale is a challenge,” he said. “On the QU platform we have one large 10,000 tonne module, which comprises the bulk of it. On top, we have a power generation module and on the side, we have the accommodation module. We will have three lifts on QU. “On DP, we have the DP East module, the DP West module, each of which is around 10,000 tonnes. Then we have the compression module that goes on top of DP East and then we have the drilling support module and the drill rig itself. The final two modules are the flare boom and the bridge,” he said. The facilities will have a maximum processing capacity of 120,000 BOPD, which will flow to the Clair Phase 1 pipeline through a new oil export pipeline and onward to the Sullom Voe Terminal. The DP platform will also be tied into the West of Shetland Pipeline System through a carbon steel gas export pipeline.

Wellbore-Instability Predictions Within the Cretaceous Mudstones, Clair Field, West of Shetlands

Summary Some early high-inclination wells were impacted adversely by wellbore instability within Cretaceous mudstones overlying the Clair oil field. Detailed investigations of the possible reasons for borehole failure led to a decision to cut two cores within the unstable interval and carry out laboratory testing to investigate the failure mechanism. Analysis of rock failure based on a "planes of weakness" theory fitted previous drilling observations. This theory has been applied primarily for layered hard rocks (e.g., mining and tunneling) and is here extended to significantly weaker mudstones showing strength anisotropy. Minimum required mud weight predictions were made for a range of well configurations. The results of this study were used to plan an extended-reach-drilling (ERD) development well targeting a previously undeveloped part of the Clair field. The new well was successfully drilled, cased, and brought on stream within budget in 2009. This paper describes the basic geology of the field, rock properties of the Cretaceous mudstones, details of laboratory tests conducted, and analyses carried out. Cretaceous mudstones of the Clair field are characterized by low strength and minor anisotropy. Various rock tests were conducted on core to define the failure behavior: unconfined compressive strength (UCS), single-stage triaxial strength, and multistage triaxial strength tests were conducted, all at various angles to bedding. In addition, the effect of mud invasion was analyzed by performing a multistage triaxial test in drilling mud at high pressure. The analysis used commercial software to evaluate borehole instability in a rock medium that fails along weak planes. Minimum mud weight requirements derived from this analysis were compared with previous drilling experience and were used subsequently for predicting mud weight required to drill an ERD well. Lessons learned from the successful drilling of this well will be applied in future Clair development wells and may be of relevance elsewhere.

Wellbore-Instability Predictions in Cretaceous Mudstones: Clair Field, West of Shetlands

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 124464, ’Wellbore-In stability Predictions Within the Cretaceous Mudstones of Clair Field, West of Shetlands,’ by R. Narayanasamy, SPE, D. Barr, SPE, and A. Milne, BP plc, prepared for the 2009 SPE Offshore Europe Oil & Gas Conference & Exhibition, Aberdeen, 8-11 September. Wellbore instability in Cretaceous mudstones overlying the Clair oil field has prevented successful drilling of high inclination wells in the past. Rock-failure analysis, based on a planes-of-weakness theory, fit previous drilling observations. Minimum-required-mud-weight predictions were made for a range of well configurations. The results of this study were used to plan an extended-reach-drilling (ERD) development well targeting a previously undeveloped part of the Clair field. Introduction The Clair oil field is on the UK Continental Shelf, 75 km west of the Shetland Islands in 140-m water depth. Discovered in 1977, first production was in February 2005 from a fixed steel platform with pipeline export to the Sullom Voe terminal on Shetland. The Clair field covers more than 200 sq km and contains more than 5 billion BO equivalent (BOE), of which 1.5 billion BOE is targeted by the Phase-1 development. The currently producing Clair Phase-1 development comprises fractured Devonian sandstone reservoirs and is produced by waterflooding with a mix of downflank and pattern injection. The Devonian reservoir is more than 500 m thick, but only the upper zones (V and VI—250- to 300-m total thick-ness) are producing, principally through high-inclination or subhorizontal wells designed to target a combination of permeable natural fractures and the best-quality matrix. The reservoir is highly compacted and cemented and does not present wellbore-stability issues while drilling. However, the combination of shallow targets [gas/oil contact at 1550 m true vertical depth subsea (TVDSS) and oil/water contact at 2100 m TVDSS] and moderate water depth requires inclination to be built rapidly in shallow unconsolidated overburden formations. Core from Well A09 was obtained to characterize rock failure through various tests. The tests revealed anisotropic strength behavior. Analyzing several existing wells with the test results enabled predictions of minimum mud weight required for stability in future wells. The full-length paper details the mud-weight predictions for an ERD well and observations made while drilling it. Drilling History Conventional wellbore-stability analysis based on a Mohr-Coulomb failure criterion was consistent with drilling observations in most of the early wells. Subsequently, however, borehole collapse was experienced while drilling through Upper Cretaceous mudstones in Wells A06 and A08. Static mud weights of up to 1.42 SG were used in Well A06 and its two unsuccessful sidetracks at an inclination of 76° (measured from vertical). Similar problems were experienced while drilling Well A08, at a lower inclination of 57° and with 1.36-SG mud weight. An increase in mud weight to 1.54 SG enabled successful drilling of a side-track (Well A08Z) and another well with a similar inclination (Well A11). An intermediate-casing shoe was set in the Cretaceous mudstones in Well A11, and a 65° section then was drilled successfully with 1.58-SG mud weight. A challenging ERD well with 76° inclination (Well A15) was drilled successfully with 1.61-SG mud weight.

Managing the start-up of a fractured oil reservoir: development of the Clair field, West of Shetland

Abstract The Clair oilfield was discovered in 1977 and began production in 2005. It is a heterogeneous fractured sandstone reservoir with an estimated STOIIP of c . 1.5 billion barrels in the Phase 1 development area. An extended appraisal programme was required to assess reservoir deliverability, which is controlled by the distribution of natural fractures. Development drilling increased the understanding of the fracture system, through acquisition of conventional core, open-hole logging, drilling mud-loss recording, production logging and well test transient analysis. These data revealed a complex fracture system of conductive faults and background joints. Post-production formation pressure measurements showed greater lateral and vertical connectivity than would be expected from matrix and fluid properties alone. However, large pressure differences were encountered close to or across features mappable at a seismic scale. Closed fractures or sealing faults can form baffles between compartments, and conductive faults or fractures allow rapid pressure communication. In some cases the connection path or barrier can be identified with seismically mapped features. When the field was put onto water injection, one year after start-up, a key concern was the degree of imbibition of water from the fractures to the matrix. Despite the observed pressure connectivity, water breakthrough did not take place until 2007. Most producers have completions designed to permit zonal water shut-off. A successful intervention was carried out in early 2008, after a production logging run had demonstrated water entry at the toe of a high-angle well. The crestal Core segment of the development benefits from a permanent 4D seismic array of ocean-bottom cables. In 2007 the first permanent monitor survey was acquired and processing gave indications of a 4D response. These 4D data are improving the dynamic reservoir understanding and providing valuable spatial context to the well results.

Application of fluorescence lifetime measurements on single petroleum‐bearing fluid inclusions to demonstrate multicharge history in petroleum reservoirs

AbstractPetroleum‐bearing fluid inclusions emit fluorescent light when excited with UV or visible light. The fluorescence decay time of the emission is dependent upon the wavelengths of the excitation and emission light, and the chemical composition of the petroleum oil. In general heavy oils have short lifetimes, whereas the emission from light oils is much longer lived. One can thus use plots of the fluorescence lifetime versus emission wavelength (τ–λ plots), to show even subtle changes in the chemical composition of the entrapped oil. As a consequence, these τ–λ plots can be used for fluid inclusion research to discriminate different oil populations in situ. In particular, it is demonstrated that τ–λ plots discriminate two sets of inclusion oils in each of four North Atlantic basins [Jeanne d’Arc Basin (Newfoundland), Porcupine Basin (Ireland), Clair field West of Shetland (UK) and Kangerlussuaq Basin (East Greenland)] where multistage oil charge is inferred from other geological evidence.

Late Palaeozoic hydrocarbon migration through the Clair field, West of Shetland, UK Atlantic margin

Geochemical analysis of bitumen- and hydrocarbon-bearing fluid inclusions from the Devonian-Carboniferous Clair field indicates that the reservoirs contain a mixture of oils from different marine and lacustrine sources. Reconstruction of the Clair field oil-charge history using fluid inclusion petrography show that oil-charging occurred at times of K-feldspar, quartz and calcite cementation. Temperature–composition–time data yielded from the integration of fluid inclusion microthermometry with high-resolution Ar–Ar dating, date hydrocarbon-bearing K-feldspar overgrowths at 247±3.3Ma. These data show that in order for oil to be trapped within primary fluid inclusions in K-feldspar overgrowths, hydrocarbon migration throughout the UK Atlantic margin must have been taking place during the Late Palaeozoic and as such, current industry oil-play models based solely on oil charging from Jurassic-Cretaceous marine sources are clearly incomplete and need revision. Apatite fission track analysis and vitrinite reflectance data were used to reconstruct thermal burial histories and assess potential oil generation from Middle Devonian lacustrine source rocks. Thermal history data from wells along The Rona Ridge adjacent to the Clair field show that the Palaeozoic section was heated to greater than 100°C at some time between 270 and 230Ma, confirming that Devonian source rocks were mature and expelling oil during the Late Palaeozoic at the time that authigenic K-feldspar overgrowths were growing in the Clair field.

Modelling and analysis of attenuation anisotropy in multi‐azimuth VSP data from the Clair field

ABSTRACTAnisotropic variations in attenuation are of interest since they can give information on the fracture system and may be more amenable to measurement than absolute attenuation values. We examine methods for detecting changes in relative attenuation with azimuth from VSP data, and validate the techniques on synthetic data. Analysis of a multi‐azimuth walkaway VSP data set from a fractured hydrocarbon reservoir indicates that such azimuthal variations in P‐wave attenuation are observable. The effects are localized in the reservoir, and analysis allows the prediction of a fracture strike direction, which agrees with geological information. The observed effects can be modelled under reasonable assumptions, which suggests the validity of the link between the anisotropic attenuation and the fracturing.

Evolution of hydrocarbon migration style in a fractured reservoir deduced from fluid inclusion data, Clair Field, west of Shetland, UK

A petrographic and fluid inclusion microthermometric study was performed on sandstones from the Devonian-Carboniferous reservoir rocks of the Clair Field, west of Shetland. Fluid inclusion petrographic and microthermometric observations were collected from quartz, K-feldspar and calcite cements and veins. Vein and cement minerals host both aqueous and hydrocarbon two-phase (liquid and vapor-filled) fluid inclusions indicating that cementation occurred during oil charging. The location of hydrocarbon fluid inclusions in the paragenetic sequence of the reservoir rocks indicates that hydrocarbon migration during early-stage diagenesis occurred via intergranular pores as well as fractures, whereas towards the later stages of diagenesis, as porosities were occluded, hydrocarbon migration was predominantly fracture controlled. The microthermometric characteristics of primary and secondary aqueous fluid inclusions in association with hydrocarbon fluid inclusions indicates that cementation and veining during oil charging occurred at temperatures up to 180 °C. Salinity values are variable (0–10.9 wt% NaCl eq.) indicating that fluid mixing occurred during veining and cementation. Basin modeling and vitrinite reflectance data indicate that temperatures of up to 180 °C could not have been attained through burial alone. The high temperatures attained during late-stage diagenesis are interpreted to be caused by high temperature, short-lived fluids circulating within the Devonian-Carboniferous reservoir rocks in association with late Cretaceous and Paleocene magmatism. These high temperature fluid flow events were not recorded in the vitrinite reflectance data because of their short duration.

Pre-development fracture modelling in the Clair field, west of Shetland

Abstract The Clair oilfield is a large fractured sandstone reservoir lying 75 km west of Shetland on the UK continental shelf. Fracture analysis and modelling was carried out in preparation for the phase 1 development, which started production early in 2005. Fracture clusters and discrete fluid inflows observed in wells are associated with faults and other localized deformation features tens or hundreds of metres apart. The reservoir has moderate to good matrix permeability, but well flow rates and profiles are fracture-dominated. Full-field geological models were built using conventional object modelling approaches for matrix and discrete fracture networks for fractures, and upscaled to populate a reservoir simulation grid. Dual-porosity, dual-permeability dynamic modelling (full-field and well-test) was undertaken to understand the fracture and matrix flow contributions and their interaction. Fracture models were conditioned to wells and to seismic data, including coherency and multi-azimuthal velocity information from a four-component, ocean bottom cable three-dimensional seismic survey. At this early stage in field development, there is insufficient calibration to select a single fracture model. Instead, well and depletion plans have been tested against multiple fracture models chosen to encompass a wide range of plausible outcomes.

Seismic anisotropy as an indicator of reservoir quality in siliciclastic rocks

Abstract Improving the accuracy of subsurface imaging is commonly the main incentive for including the effects of anisotropy in seismic processing. However, the anisotropy itself holds valuable information about rock properties and, as such, can be viewed as a seismic attribute. Here we summarize results from an integrated project that explored the potential to use observations of seismic anisotropy to interpret lithological and fluid properties (the SAIL project). Our approach links detailed petrofabric analyses of reservoir rocks, laboratory based measurements of ultrasonic velocities in core samples, and reservoir-scale seismic observations. We present results for the Clair field, a Carboniferous–Devonian reservoir offshore Scotland, west of the Shetland Islands. The reservoir rocks are sandstones that are variable in composition and exhibit anisotropy on three length-scales: the crystal, grain and fracture scale. We have developed a methodology for assessing crystal-preferred-orientation (CPO) using a combination of electron back-scattered diffraction (EBSD), X-ray texture goniometry (XRTG) and image analysis. Modal proportions of individual minerals are measured using quantitative X-ray diffraction (QXRD). These measurements are used to calculate the intrinsic anisotropy due to CPO via Voigt-Reuss-Hill averaging of individual crystal elasticities and their orientations. The intrinsic anisotropy of the rock is controlled by the phyllosilicate content and to a lesser degree the orientation of quartz and feldspar; the latter can serve as a palaeoflow indicator. Our results show remarkable consistency in CPO throughout the reservoir and allow us to construct a mathematical model of reservoir anisotropy. A comparison of CPO-predicted velocities and those derived from laboratory measurements of ultrasonic signals allows the estimation of additional elastic compliance terms due to grain-boundary interactions. The results show that the CPO estimates are good proxies for the intrinsic anisotropy of the clean sandstones. The more micaceous rocks exhibit enhanced anisotropy due to interactions between the phyllosilicate grains. We then compare the lab-scale predictions with reservoir-scale measurements of seismic anisotropy, based on amplitude variation with offset and azimuth (AVOA) analysis and non-hyperbolic moveout. Our mathematical model provides a foundation for interpreting the reservoir-scale seismic data and improving the geological modelling of complex reservoirs. The observed increases in AVOA signal with depth can only be explained with an increase in fracturing beneath the major unit boundaries, rather than a change in intrinsic CPO properties. In general, the style and magnitude of anisotropy in the Clair field appears to be indicative of reservoir quality.

Clair Field: Development of a Waterflooded Fractured Reservoir

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 96316, "Clair Field - Managing Uncertainty in the Development of a Waterflooded Fractured Reservoir," by P.J. Clifford, SPE, A.R. O'Donovan, SPE, K.E. Savory, SPE, G. Smith, and D. Barr, BP plc, prepared for the 2005 Offshore Europe, Aberdeen, 6–9 September. Clair is the largest naturally fractured reservoir developed in the U.K. Recovery is by waterflood. Its 28-year appraisal period reflects the high reservoir complexity, relatively poor-quality conventional-seismic image, and uncertain effect of the conductive fractures. Clair is not predrilled, and the preferred well locations and design will change. Introduction Clair is a naturally fractured Devonian sandstone reservoir with a 1,970-ft reservoir interval containing 23°API oil 47 miles west of Shetland in 500 ft of water. Clair was discovered in 1977 and appraised by a series of vertical wells with disappointing rates. Field potential finally was demonstrated by the drilling of high-angle appraisal wells 206/8-9z and 206/8-10z, culminating in an extended well test (EWT) of 206/8–10z in 1996, which produced 500,000 STB of oil and demonstrated communication with a minimum of 500 million STB. The EWT led to sanction of the Clair Phase 1 development in 2001 and first oil in February 2005. The Clair Phase 1 development comprises the core, graben, and horst fault blocks (Fig. 1) believed to contain approximately 1.5 million STB of oil. Appraisal of the remaining areas of the field is continuing and may lead to sub-sequent development phases. Phase 1 is a single fixed-platform development. The field will be developed by drilling 22 additional wells over a 3-year period. The principal recovery mechanism is waterflood, with a planned ratio of approximately 2 producers per injector. Matrix permeability averages approximately 30 md, and oil viscosity is 3.5 cp at reservoir conditions. Recovery strategy begins with development of the more productive relatively high-permeability fluvial sands of Unit V in the large core segment and proceeds with development of the interbedded lake-margin fluvial sands of Unit VI on the basis of learning from Unit V wells. Drilling in the smaller and less appraised graben and horst blocks proceeds in parallel with the later core development. Natural-Fracture Description. The controlling feature of reservoir development in Clair is the system of natural fractures. Core and image logs demonstrate widespread granulation seams, conductive fractures, and cemented fractures. Use of seismic techniques to distinguish conductive from nonconductive faults and fractures is a key methodology in Clair reservoir description. To describe the possible fracture distributions, and to allow their incorporation into reservoir models, a number of scenarios have been generated. In these scenarios, stochastic distributions of conductive faults or joints have been generated with use of conditioning to seismic data, and these have been upscaled into fracture permeability arrays for incorporation into dynamic reservoir models.