Precipitation from and corrosion by formation water co-produced with target hydrocarbons can cause serious problems, and an early knowledge of water chemistry is important for completion and facilities design. Owing to the high cost of interventions, this knowledge is particularly important in deepwater developments and subsea completions. Samples of formation water are obtained by producing from the well completed in the water leg or sampling after water production occurs naturally. The former method carries significant cost and the latter method may delay the knowledge of the water chemistry. Alternatively, a formation tester can be run into the wellbore to collect small samples directly from the formation.. In wells drilled with water-based mud, the results are generally mixed because successful collection of formation water requires that the tool be able to discriminate between the water and invaded filtrate. The method depends on the contrast in color or resistivity between formation water and water-based mud filtrate to determine when it is collecting water, and this contrast often doesn't exist. This paper presents a new solution. A mud tracer was used to change the optical properties of the mud filtrate to make it detectable downhole. Laboratory experiments checked the compatibility of the tracer with gypsum or glycol mud system, sensitivity to high clay content, and ability to be detected with another tracer, and individually and in combination with a dark-colored filtrate. Shop experiments were carried out to establish a relationship between different tracer concentrations and optical properties at specific wavelengths. This relationship represents the basis of tracer detection and contamination prediction in real time downhole. The first trial was carried in the Otter field in the northern North Sea. The field comprises three producers and two injectors with subsea completions. Downhole water samples were obtained during the logging phase on one of the injectors at an early stage of the field development. Sample quality and flushing time were optimized using the new technique. Sample analysis results compared well with later production tests. Introduction Water production happens naturally in many oilfields. Generally, the production of water is unwanted and measures are taken to avoid or to minimize it. Knowledge of the chemistry of the produced water is incorporated into the production process. For example, potential for scaling and corrosion influences material selection of the well completions and surface facilities. The quality of produced water may also impact the decision about water injection for the fear of mixing incompatible waters.1 It is expensive to dedicate a production test for the sole purpose of obtaining a formation water sample. Although information about water chemistry is important, the cost of obtaining a sample can be high enough that the test may be delayed or canceled if obstacles arise. Wells generally are completed with the aim of preventing or at least delaying water production, so it sometimes seems easy to defer analysis. Water chemistry may thus be only available when water production naturally occurs, long after metal completion goods, chemical injectors, etc. have been placed. This may not be the ideal situation. Therefore, obtaining a formation water sample using a wireline formation tester at an early stage of field development is an attractive solution. If the sampled well is drilled with oil-based mud (OBM), current technology provides a simple way to differentiate between OBM filtrate and formation water2,3. If the sampled well is drilled with water-based mud (WBM), differentiation can be difficult. The most commonly used downhole sensors rely on resistivity or the colour difference between formation water and WBM filtrate. Often these values are close and can not be used as a mean of differentiating the two fluids. As we report, adding the proper synthetic dye to the WBM colors the filtrate, providing clear differentiation from formation water.

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.

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

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.

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