This paper is presenting a methodology to model karstic diagenesis with geometrical processes. This fast procedure is efficient to model karstic drainage zones in an uncertainty framework with multiple realizations. The technique is firstly depicted: from a set of simple parameters (paleo-aquifers, infiltration or dissolution zones, conduits characteristics: length, direction, density, and aperture) the incremental porosity and permeabilities associated to karstic processes are calculated directly on the reservoir grid; different typologies of karst can be addressed: "plateau" karst, hydrothermal karst and island sponge karst. Subsequently, an application to a real field case is addressed with multiple realizations of the fast procedure. The Object 2 reservoir of Kharyaga carbonate oil field, lying 60 km north of the Artic Polar Circle, in Nenets Autonomous Territory was modeled with a multi-phase island karst in agreement with the sedimentological interpretation from cores and borehole images. Several hundred realizations have been performed; each realization is scanned with connectivity computations in order to sort the models regarding relevant criteria (volumes connected to wells). Some recommendations and conclusions are suggested from several experiments on this topic. Outlet Ground water level Conduits Emersion SurfaceVadose Zone Epikarst (inlet)

Total, operating on behalf of Shell, ExxonMobil and Dana, is developing the Otter field in the North Sea. The development plan calls for three horizontal producers and two water injectors. Their location is critical to optimize production and reserves in this complexly faulted reservoir. The first well started producing in October 2002. The reservoir model assumed fault transmissibility and predicted that there would be a small but measurable depletion by the time the third well was drilled. When this well was entering the reservoir in January 2003, it was important to determine whether the reservoir drawdown matched the reservoir model. Formation pressure information was required as soon as possible, as this would have implications on the onward drilling program of well three and possibly on the relocation of one of the injectors. Since this well was penetrating the reservoir section sub-horizontally, any wireline formation tester would have to be run on drill pipe. An innovative technology, the Drilling Formation Tester (DFT), was utilized to gather the formation pressure data. The DFT is a Logging While Drilling Tool (LWD) that performs formation pressure test using a dual packer configuration, a downhole pump, and a quartz gauge. It uses mud-pulse telemetry to transmit the downhole formation pressure data to the surface in real-time. Multiple tests can be performed to measure formation pressure and establish the formation fluid gradient. A Formation Evaluation LWD suite was run with the DFT. This allowed geosteering of the well into the optimal part of the reservoir and to investigate the reservoir pressure regime while drilling. This combination of LWD tools facilitated while drilling a comprehensive understanding of the reservoir, its fault compartments and pressure regime. The real-time pressure data indicated that the well was located in a high permeability layer, confirmed the reservoir pressure model and facilitated the real-time decision-making process. The use of an LWD formation pressure tester was economic by saving an extra trip in the hole that would be required to acquire drill pipe conveyed wireline pressure data. It both added value through reduced operational risks as well as saving direct and indirect formation evaluation costs. Introduction The Otter Field, located in UK Blocks 210/15a and 210/20d in the Northern North Sea (Figure 1), is operated by Total on behalf of partners Shell, ExxonMobil and Dana. Development has proceeded using three extended reach, sub-horizontal producers and two water injectors, in order to optimise reserves recovery and minimise development costs1. The field (originally called Wendy) was discovered in 1977 by the Phillips 210/15–2 well that tested 4746bopd from Middle Jurassic Brent Group sandstones. Following 3D seismic acquisition in 1994, this discovery was appraised by Fina well 210/15a-5, which tested at a rate of 7650bopd. TotalFina drilled a successful third well, 210/15a-6 (Figure 2), in 2000 and the decision to proceed with development plans was confirmed. The Otter field comprises four major fault blocks within an overall easterly dipping structure (Figure 3). Subsidiary faults divide the accumulation into several minor blocks, all with the same oil-water contact depth. Based on the three exploration and appraisal wells, the Brent reservoir is approximately 100m thick in the Otter Field, but the oil column is, at maximum, only some 60m and the bulk of the oil occurs in the Upper Brent, within the Tarbert and Ness formations with a small amount in the Etive. Top seal is provided by the Mid to Late Jurassic Heather shales. Otter oil has a gravity of 36.5° API and a GOR of 79m3/m3 (443 scf/bbl). The reservoir is normally pressured with the crest of the structure at a depth of 1970mSS2.

The 2002 to 2003 OtterFieldd evelopment drillingc ampaignu tilized ac ombination ofd etailed trajectory planninga ndi ntegrated geosteeringtechniques. The objectiveofthisw orkwast om aximizeoil recovery,withaminimaln umbero fwells,f rom the complexlyfaulted Otters tructure.Toachievethis,subhorizontalp roduction wells wereplanned to track neart op reservoir,through the structuralculminations,to connectadjacent fault blocks. Otteristhe most northwesterly ofthe Brent Province fieldsofthe Northern North Sea, located inUK blocks210/15a and210/20d, 530 kmnorthofAberdeen,operated byTOTAL withpartners Shell U.K.Exploration andProduction,ExxonMobilandDana.The fieldwasdiscovered bythe Phillips 210/15-2 well in1977 (thencalled Wendy) andappraised byFinawell 210/15a-5 in1997,following3Dseismic acquisition in1994.The decision to proceed withdevelopment wasconfirmed afterthe success ofappraisalwell 210/15a-6 drilled byTotalFinain2000.The Otterstructureisaneasterly dippingtilted panelthatisdivided into four major blocksandseveralminor blocksbyanetworkofsubsidiary faults. The reservoiristhe MiddleJurassic Brent Group,withthe uppermost Tarbert Formation shallow marinesandstonescomprisingthe mainproducingtarget. The oilsource rock isthe LateJurassic KimmeridgeClay,present inthe off-structureareas,though locally absent overthe OtterFieldarea. Top sealisprovided bythe Mid-to LateJurassic HeatherShales. The Otteroilisamedium gravity crude (36.5 8 API)withaGOR of79m 3 /m 3 (443scf/bbl),inanormally pressured reservoiratacrestaldepthof1970 msubsea. Otterwell planningwasconducted usinga3Dgeocellularmodelbased on interpretation ofbothconventionaland acoustic impedance inversion seismic datasets. Apilot study,prior to development drilling, included geochemical andpetrophysicalr eservoiru nitdefinition andthe forwardmodellingofL WD logresponsei ns ub-horizontal wells. The results ofthesestudieswereused to aid geosteering, incorporatingrealtimec hemostratigraphyand LWD dataatthe wellsite.Inaddition,boreholeresistivity imageswhiledrillingwereused to assist instructural interpretation inrealtimeandthus to guide the well trajectory to maximizethe paysection. Akeycomponent in usingthesenewt echnologiesw ast he office-based integration ofa ll the datavia web-based monitoringofthe operations.Three production wells targetthe culminationsatt he extremitiesofthe OtterField, supported byadowndip waterinjector,all drilled from acentrally located subsea template.Followingthe successful drillingofthe first production well,210/215a-T1,production start-up wasinOctober2002,via subsea tieback to the Eiderfacility.

This paper demonstrates how new Logging While Drilling (LWD) and Measurement While Drilling (MWD) tools were used to optimise placement of 3 sub-horizontal wells in a faulted, sand-shale oil bearing Brent Group reservoir known as the Otter Field, Northern North Sea, United Kingdom. As the target reservoir layer is only 8m thick and sub-seismic faulting and subtle changes in dip occur in the field, geosteering of the well paths was anticipated prior to commencing drilling. To aid with geological steering of the wells a new LWD tool was run: the azimuthal GR-resistivity device and this provided high-resolution borehole images of formation geology (eg. formation layering and dip, fault location and orientation). Using state-of-the-art mud-pulse MWD telemetry and the world-wide web, the images and other LWD data (eg. porosity) were made available, real-time, to both the onshore and offshore drilling team. Detailed geological cross sections constructed in real-time from the image logs aided steering the wells to the optimum geological locations. One of the three production wells [well 210/15a-T2 (P1)] is used to demonstrate how the imaging while drilling, viewed real-time via the web, was applied. This case study highlights the benefits the technology brought to the drilling operation and field development in terms of efficiency improvements in geological analysis and well steering decision making and maximized oil production through optimum well placement. Introduction Otter Field Background The Otter Field, located in UK Blocks 210/15a and 210/20d in the Northern North Sea, is operated by Total E&P UK plc on behalf of partners Shell, ExxonMobil and Dana (Figure 1a). Development has proceeded using three extended reach, sub-horizontal producers and two water injectors, in order to optimise reserves recovery and minimise development costs1. The field (originally called Wendy) was discovered in 1977 by the Phillips 210/15–2 well that tested 4746bopd from Middle Jurassic Brent Group sandstones. Following 3D seismic acquisition in 1994, this discovery was appraised by Fina well 210/15a-5, which tested at a rate of 7650bopd. Total Fina drilled a successful third well, 210/15a-6, in 2000 and the decision to proceed with development plans was confirmed. The Otter field comprises four major fault blocks within an overall easterly dipping structure (Figure 1b). Subsidiary faults divide the accumulation into several minor blocks, all with the same oil-water contact at 2052mSS. Based on the 3 exploration and appraisal wells, the Brent reservoir is approximately 100m thick in the Otter Field, but the oil column is, at maximum, only some 60m and the bulk of the oil occurs in the Upper Brent, within the Tarbert and Ness formations with a small amount in the Etive. Top seal is provided by the Mid to Late Jurassic Heather shales. Otter oil has a gravity of 36.5° API and a GOR of 79m3/m3 (443 scf/bbl). The reservoir is normally pressured with the crest of the structure at a depth of 1970mSS2. The main producing target is the 8m thick lower unit, T10, of the Upper Brent Tarbert Formation and is composed of shallow marine sandstones. The main reservoir engineering criteria were:To stay as high as possible in each block to maintain a minimum 32m vertical stand-off above the oil-water contact.To achive a minmum of 150m of reservoir section along the drain in each block

This paper presents the key of success for the development of a complex prospect, the Sarr dolomitic reservoir in the Kharir field, located onshore Yemen. The drilling of horizontal wells was considered to limit the early water encroachment observed on vertical producers and to improve both the oil production and the final recovery. A careful data acquisition program, a close cooperation between all the parties involved in the drilling process, with the implementation of common decision procedures, allowed geosteering in optimized reservoir targets, while preserving the safety of the horizontal drilling operation. The Kharir Sarr field is a multi-layered oil bearing dolomitic reservoir interbedded with tight limestones. Variable petrophysical properties characterize the dolomite in this field, following the geometry of elementary sedimentary facies, their stacking, their structural position, and finally their diagenetic history. On top of the structure, the reservoir is interpreted as dolomitized patchy biostromes, very difficult to target and to appraise with vertical wells. Monitoring the data acquired in real-time, referenced to pre-job-modeling, provided the key elements for cautious decision-making on trajectory definition. The expertise developed in geological steering has contributed to boost oil production and add significant field reserves. Introduction Field data overview TOTALFINAELF E&P YEMEN (interest 28,57%) operates the Block 10, located in the Hadramaout area, east of the Republic of Yemen, on behalf of the East-Shabwa association, which comprises also COMECO 28.57%, OCCIDENTAL 28,57% & KUFPEC PETROLEUM LTD 14,29%. The Kharir Sarr field has been discovered in April 1993 by well A (Fig. 1). 2D infill seismic was shot in 1994. Two additional delineation wells (Wells B & C), drilled in 1998, have cored the complete Sarr dolomitic section. The Kharir Sarr formation is draping a basement high, created by Jurassic rifting, and reactivated during the Oligocene Aden Gulf rifting. The Sarr formation, dated Valanginian (Cretaceous) is constituted of interbeds of limestone, chalky limestone, dolomite and shale. Reservoir definition The Sarr dolomite reservoir S4 has been subdivided into five layers, namely S4a to S4e (Fig. 2). The Sarr dolomite cycle started with Early Valanginian middle ramp limestones overlain by argillaceous material of the Sarr Shale (S5 reservoir layer), over which the reservoir-forming bivalve bioaccumulations developed. This evolution illustrates a shallowing-up evolution in terms of depositional environment, from the middle ramp limestones at bottom, to the more proximal, inner ramp mollusk facies. Two pulses of slight re-opening and deepening of the depositional environment are noticed at the base of S4b & S4a layers, interbedded with dolomitized algae laminations, i.e. very shallow deposits. At the end of the interval, a marked deepening (S3) is associated with the middle ramp limestones very similar to the base of the cycle (S5). The reservoir facies consists of pervasively dolomitised mollusk bioaccumulations (Fig. 3). Those are considered lens-shaped mounds of 1 to 2 meters in thickness, with lateral extension that may reach a ten's of meters. Their stacking provides interesting continuity of the distribution of vuggy porosity. The embedding mudstone, although devoid of vugs, presents good moldic and intercrystalline, relatively well connected porosity. Field data overview TOTALFINAELF E&P YEMEN (interest 28,57%) operates the Block 10, located in the Hadramaout area, east of the Republic of Yemen, on behalf of the East-Shabwa association, which comprises also COMECO 28.57%, OCCIDENTAL 28,57% & KUFPEC PETROLEUM LTD 14,29%. The Kharir Sarr field has been discovered in April 1993 by well A (Fig. 1). 2D infill seismic was shot in 1994. Two additional delineation wells (Wells B & C), drilled in 1998, have cored the complete Sarr dolomitic section. The Kharir Sarr formation is draping a basement high, created by Jurassic rifting, and reactivated during the Oligocene Aden Gulf rifting. The Sarr formation, dated Valanginian (Cretaceous) is constituted of interbeds of limestone, chalky limestone, dolomite and shale.