Description of Paper. Selection among alternative log analysis models is based on the accuracy with which each can predict specific properties. The assessment of predictive accuracy involves core data not used for log calibration. Model selection is made using set of accuracy and vertical resolution criteria, based on both data quality and the requirements of the planned application (e.g., mapping, simulation). The log and core data used in this study are from deep marine reservoirs containing finely laminated sand/shale sequences in which the sand fraction exceeds 70%. Combined effects of thin laminations, variable sand properties, and high shale conductivity, complicate log analysis efforts. Several conventional log analysis models we evaluated provided satisfactory estimates of hydrocarbon pore volume, but none achieved the accuracy required for reservoir flow simulation. A new model was developed based on lithofacies relationships derived from integration of core, log, and geologic data. This model was subjected to the same calibration and testing as the conventional models, and achieved the desired level of predictive accuracy. The test results allowed the model to be applied with confidence to over 2000 feet of uncored pay. Technical Contributions:A method for selecting among alternative log analyses by evaluating predictive accuracyA case study of an integrated evaluation of log, core, and geological informationA simple and accurate log analysis model for finely laminated deep marine turbidites Introduction Deep marine turbidite deposits have become the focus of considerable exploration and development activity worldwide, and particularly within the "deepwater" area of the Gulf of Mexico. This study involves the Green Canyon 205 Unit (GC 205), located 150 miles south of New Orleans in an average water depth of approximately 2600 feet (Fig. 1). A development project for GC 205 is currently being pursued, with Chevron as Operator, and participation by partners Exxon and Fina. The geologic setting, facies distribution, and reservoir architecture for the major sands in this field have been previously described by Rafalowski, et. al. Most of the reserves in this field are contained within very finely laminated sand/shale sequences, with individual lamina often less than one inch thick. Even micro-imaging logs typically have insufficient resolution for quantitative determination of the net reservoir fraction in these formations. Since the shales in these reservoirs have high neutron porosities, moderate density porosities, and high conductivity, accurate assessment of the shale volume (VSh) is critical to all log analysis calculations. Early log analysis efforts were adequate for assessment of original hydrocarbon volumes in-place. However, they did not provide sufficiently accurate characterization of other reservoir parameters required for fluid flow simulation. The need for such simulation to assist with development planning prompted a review of the log analysis methods being used and available options. Data Availability and Quality Well Log Data. Of the ten penetrations drilled within the GC 205 unit, eight encountered oil sands in one or more of the six recognized development horizons. Figure 2 shows the locations of these penetrations with respect to the combined productive limits of the six horizons. Four of these reservoirs are grouped into the Lower Pleistocene "Nebraskan" series (Neb 1, Neb 2, Neb 3U, and Neb 3), while two sands are recognized within the Upper Pliocene series (14200' and 14800'). The Neb series sands contain the bulk of the developable resource, and were the primary focus of our study. P. 119
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractSlow data acquisition rates have generally not been a problem for LWD due to moderate logging speeds while drilling. With the recent advances in drilling technology, high logging speeds impact the log quality and, in particular, the nuclear logs. When a detector passes a longer interval of rock for each acquisition period, its vertical resolution is degraded. For azimuthally sectored data, this is even more of an issue, as bedding features within a sample period get blurred.The objective of the study is to develop a methodology to optimize LWD data acquisition, enabling the E&P company to drill faster and meet its data acquisition objectives. This paper describes analytical simulations and field tests performed to optimize data acquisition for fast drilling in the Norwegian North Sea. Optimization of data acquisition is described as addressing the trade-off between low data density with accurate measurements versus high data density with less accurate measurements.Based on nuclear logs acquired in adjacent wells, bed contrasts were defined for zones of interest. Modeling was done to define the minimum acquisition time needed to detect the defined contrasts. Telemetry was designed with adequate resolution for geo-steering, thus saving bandwidth. The impact on memory data accuracy caused by faster acquisition rates was modeled to check feasibility. Field tests were performed to validate the modeling results.Real-time telemetry accuracy proved adequate and the improved data density provided better definition of bedding features versus standard setup. Memory data contained better vertical resolution, further enhancing bedding features, while maintaining the required accuracy. Understanding all end users' specific data quality requirements is key to an acceptable compromise.Applying this methodology in the planning phase for other wells ensures all stake holders' needs are considered, and aids the overall understanding of LWD acquisition limitations and highlights the possibilities.
Accumulated knowledgefrom the early pioneeringwells andsubsequent exploration history led to the discovery ofseveralfieldsinthe UtsiraHigh area duringthe 1990s. Oneofthese, the Jotun Field, wasdiscovered in1994.The Jotun Fieldconsists ofthree structuresandislocated on the western flankofthe UtsiraHigh, closeto the eastern pinchout ofthe Tertiary submarinefansystem. The reservoiratJotun comprisesPaleoceneHeimdal Formation sandsshed from the East ShetlandPlatform andtransported across the VikingGrabenarea onto the UtsiraH igh byhigh density gravity flow processesdominated bys andyt urbidites. Thesed istalgravity flow deposits displayboththin-bedded sandsalternatingwithshalesandthicker,moremassivesandstones( tens of metrest hick). Minor sandi njections occur throughout the fieldb ut arevolumetrically insignificant.The production wells ino neofthe structuresarec ompleted inaslump andi njection complexabovethick massive reservoirs ands. The Jotun Fieldd evelopment strategyw asdesigned to optimizeoilcapturea ndminimizerisk based on the interpreted reservoirgeology. The initialdevelopment comprised 14d evelopment wells:12 horizontalp roducers,1w aterinjector and1w aterdisposalw ell. Production from the Jotun Fieldstarted in October1 999 andreached peak production inJune2000,with1400 00 BOPD.Afterexceedingi nitial expectations,d ecliningproduction andrisingwatercut prompted aninfill well programme, time-lapseseismic dataacquisition andproduction loggingin2002. The first two wells weredisappointingdueto faciestransition to interbedded sandsandshalesonthe flanksofthe structureandunderprediction ofoil-watercontactmovement. The newly availabletime-lapseseismic datawerethenintegrated withproduction logginga ndupdated depositionalfaciesstudiestoevaluateadditionaldrillingopportunities. The discovery,appraisalanddevelopment history ofthe Jotun Fieldservesasagoodexampleofthe keychallengesinthe Tertiary UtsiraHigh playandthe strengthofapplyingmultidisciplinary teamefforts,partnerco-operation andinvolvement to optimizeassetvalue through tailored drillinganddataacquisition programmes.
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