Abstract Sandstones of the Lower Cretaceous Kuparuk River Formation comprise major reservoirs on the North Slope of Alaska. Original oil-in-place for the Kuparuk field is estimated at approximately 5 billion barrels. The Kuparuk field provides an excellent example of large scale reservoir heterogeneity created by multiple sandstone bodies. It also illustrates the control of depositional facies and diagenesis on reservoir quality. Stratigraphically, the Kuparuk River Formation is comprised of four distinct units; A, B, C, and D. Reservoir-quality sandstones are found primarily in units A and C. The A sandstone intervals, occurring within the lowermost unit, were deposited in a regressive shelf setting. In contrast, the C sandstones, present above an erosional unconformity, were deposited in a transgressive shelf setting. The reservoir in unit A is characterized by lenticular, shingled, sheet-like sandstone bodies. Average dimensions of these bodies are about 24 km (15 mi) long, 13 km (8 mi) wide, and 15 km (50 ft) thick. The best reservoir-quality sandstones in unit A are dominated by facies types indicative of episodic storm deposition. These types include hummocky cross-stratified and wave-rippled, flaser-bedded facies. Sandstone beds in these facies range from 0.1 to 1 m (0.5 to 3 ft) in thickness. Also present are facies types characterized by high mudstone to sandstone ratios. These include wavy-bedded and lenticular-bedded facies, and shale with lenticular sandstone streaks. These facies are not reservoir-quality because of high clay content and small scale, discontinuous sedimentary structures. The reservoir in unit C is characterized by a blanket-like geometry. Sandstone geometries within unit C are poorly defined because of syndepositional faulting and erosional truncations within the unit. The C sandstones are massive due to bioturbation and are highly glauconitic. The best reservoir-quality sandstones occur in the basal and uppermost intervals. Both intervals have unconformities at their base. In the case of the basal interval, this is a major erosional unconformity within the Kuparuk River Formation. These subunits are characterized by intense siderite cementation and subsequent partial dissolution. The distribution of reservoir properties is directly related to diagenesis and indirectly related to depositional facies. In summary, reservoir quality and heterogeneity in sandstone bodies within unit A are controlled by depositional processes. Lithofacies characterization is the key to understanding the lateral continuity and distribution of permeability and porosity within this reservoir unit. In contrast, post-depositional, diagenetic controls on reservoir quality are exhibited by sandstone bodies comprising the C unit. In this case, the distribution of permeability and porosity are controlled by siderite cementation and dissolution. In both the A and C units, a sedimentological approach to reservoir characterization is essential for a thorough understanding of reservoir quality and distribution of producible sandstones.

Abstract Anaerobic processes have only recently been recognized as an important mechanism in the biodegradation of crude oils. They are normally invoked to explain extensively biodegraded oils with little or no possibility of contact by oxygenated waters from an active aquifer. This work with Kuparuk Field indicates that early stages of anaerobic biodegradation can be subtle and easily missed, yet have economic impact. Kuparuk River Field, North Slope of Alaska, comprises two reservoir intervals: vertically stratified and imbricated lower shoreface sandstones (A sands), and overlying shallow marine sandstones with complex permeability structure (C sands). The vertical and lateral distribution of viscous oil (less than 20° API) shows a strong relationship to structure and faulting in the Kuparuk Field. Multiple mechanisms for the origin of tars and viscous oils can be proposed, including early aerobic biodegradation, anaerobic biodegradation, inorganic oxidation and gas deasphalting. This geochemical study, integrated with stratigraphic, structural and production data, was undertaken to help understand the origin and distribution of tar and viscous oil in the field. Obvious depletion of n -alkanes and other paraffins, classically regarded as indicative of early biodegradation, is not observed in examined samples. However, Kuparuk viscous oils show slight to extreme selective depletion in long-chain alkyl aromatic (LCAA) hydrocarbon families (e.g. alkylbenzenes and alkyltoluenes). This is interpreted as indicative of an early stage of anaerobic microbial degradation that likely destabilized the oil to promote subsequent precipitation of asphaltenes as tar. Depletions in LCAAs in core samples in the field are linked to decreased hydrocarbon/nonhydrocarbon ratio and to an increase in the high molecular weight (>C 50+ ) components of Rock-Eval 6 pyrolysates. Using a calibration curve constructed from oil Rock-Eval 6 pyrolysis, the API gravity of core oil plus bitumen can be estimated. Tar-plugged formations with depleted LCAAs have estimated API gravities <8°. Portions of the Kuparuk reservoir with higher iron content tend to show greater depletions in LCAA. Anaerobic biodegradation is likely mediated by dissimilatory iron-reducing bacteria. Biodegradation likely destabilizes the oil with respect to asphaltene precipitation such that later arrival of petroleum leads to tar in the reservoir. Increased tar and depleted LCAAS correspond to intervals with lower productivity indices, thus indicating a significant impact on petroleum producibility.

ABSTRACT The Kuparuk A sand reservoir has performed beyond the predictions of the original reservoir model. Water break-through has been late, original oil volumes appear to have been underestimated, and hydraulic fracture performance has exceeded expectations. The Kuparuk A sand was deposited in a nearshore, storm-dominated marine environment and is characterized by a high degree of lithologic heterogeneity. It has long been recognized from core that numerous thin clean sands (less than 0.5-1 ft thick) constitute a significant portion of the reservoir. The original petrophysical model was not able to resolve these features and computed “pay” intervals were restricted to thicker (greater than 1-2 ft thick) and less shaly sequences. Recent work with micro-scanner resistivity data has shown that the thin sand beds can be resolved and the volume of sand computed. The electrical images can easily segregate thin sand and shale lithologies because of their resistivity contrast. This contrast allows the thinly-interbedded sand-shale sequences to be quantified using a net-to-gross curve. Results were calibrated using whole core to verify the image analysis. Integration of the micro-scanner resistivity data with a conventional clay volume algorithm led to a thin-bed model that was applied field-wide. This new thin-bed model is unique in that it has the ability to distinguish the thicker, water floodable pay sands, from the thinner clean beds which may have a lower recovery factor. The relationship between clay volume and net-to-gross determined from the electrical images furnishes a decreasing thin bed sand volume with increasing clay volume. Application of the updated thin bed model should impact the oil-in-place determination and lead to recognition of possible recompletion opportunities in the “A” sand. Additionally, such opportunities may be recognized in the overlying Kuparuk “B” interval where numerous hydrocarbon-bearing thin sand beds may be present.

Abstract The Kuparuk River Field, located on the North Slope of Alaska, is the second largest oil field in the U.S. Discovered in 1969 with production beginning in 1981, the reservoir interval extends over 280 square miles and has a gross thickness of 300 ft. STOOIP is estimated to be 6 BBO , of which 2 BBO have been produced to date. The field is produced from approximately 1000 wells on 160 acre spacing from 44 drill sites, employing a north-south line drive with waterflood, and miscible WAG processes. A major initiative has been undertaken to build a new full-field reservoir simulation model as a leveraging tool for managing the field performance. Key issues to be addressed using this model include EOR expansion to additional drill sites and field-wide evaluation of potential by-passed oil. In addition, this modeling work will support justification and planning of infill CTD (coil tubing drilling) and rotary wells. To support this reservoir engineering effort, a full-field geocellular model has been constructed, integrating 20 years of field data and reservoir characterization work. The full-field model consists of 151 million total cells of which approximately 20 million active cells are in the fine scale model. The fine scale model has been up-scaled in preparation for full field compositional flow simulation which, in turn, may impact flood design, EOR adjustments, data acquisition strategies, and budgetary long range planning. Small sectors of the model are extracted to look at individual well patterns in more detail. Using such sector models enables the identification, planning, and execution of infill drilling opportunities.

Abstract The Kuparuk River field on the North Slope of Alaska (Figure 1) is the second largest producing oil field in North America. Currently the production from the Lower Cretaceous Kuparuk formation exceeds 300,000 barrels of oil per day under waterflooding. This reservoir is overlain by the Colville, West Sak, and Ugnu reservoirs which contain an estimated 20 billion barrels of oil in place. These formations are unconsolidated, have widely varying fluid and rock properties, and will require waterflooding and enhanced oil recovery processes. Development options for all of these reservoirs include hydraulic fracturing of the injection and production wells; hence, characterization of the in-situ stress field is critical for optimizing field performance and recovery. The regional crustal stress field on the North Slope is extensional with maximum principal horizontal stress oriented northwest-southeast. Previous work on fracture direction in Kuparuk, however, indicated that the in-situ stress field was more complex in its orientation. The Kuparuk reservoir occurs within a broad northwest to southeast-trending anticline which plunges to the southeast. Normal fault patterns within the Kuparuk River field show two dominant strike trends: (1) northwest-southeast and (2) north-south. In this study the hydraulic fracture direction, at both shallow and deep horizons, was determined by integrating geologic, engineering, petrophysical and geophysical data. Dipmeter logs were processed and interpreted to determine wellbore breakout directions for both shallow and deep horizons. Formation microscanner (FMS) images were used to discriminate between incipient wellbore breakout zones and mechanical fracturing from drilling. Hydraulic fracture screenout data were correlated

Abstract X-ray computed tomography (CT) is an established technique for non-destructively characterizing geological cores. CT provides information on sediment structure, diagenetic alteration, fractures, flow channels and barriers, porosity and fluid-phase saturation. A portable CT imaging system has been developed specifically for imaging whole-round cores at the drilling site. The new system relies upon carefully designed radiological shielding to minimize the size and weight of the resulting instrument. Specialized X-ray beam collimators and filters maximize system sensitivity and performance. The system has been successfully deployed on the research vessel JOIDES Resolution for Ocean Drilling Program’s legs 204 and 210, at the Ocean Drilling Program’s refrigerated Gulf Coast Core Repository, as well as on the Hot Ice #1 drilling platform located near the Kuparuk Field, Alaska. A methodology for performing simple densiometry measurements, as well as scanning for gross structural features, is presented using radiographs from ODP Leg 204. Reconstructed CT images from Hot Ice #1 demonstrate the use of CT for discerning core textural features. To demonstrate the use of CT to quantitatively interpret dynamic processes, we calculate 95% confidence intervals for density changes occurring during a laboratory methane hydrate dissociation experiment. The field deployment of a CT represents a paradigm shift in core characterization, opening up the possibility for rapid systematic characterization of three-dimensional structural features, and leading to improved subsampling and core-processing procedures.