Prudhoe Bay Unit Research Articles

Waterflood Geochemical Modeling and a Prudhoe Bay Zone 4 Case Study

Abstract Scale formation during waterfloods can damage reservoirs far beyond the wellbore region. A comprehensive analysis with geochemical modeling can improve waterflood design in the selection and/or mixing of source waters and thus, mitigate formation damage arising from injecting incompatible fluids. The method also predict the types of scales and their severity at various production stages. This will help optimize treatment schedules and reduce operation costs. In the case study of Zone 4, Prudhoe Bay Unit (North Slope, Alaska), the geochemical model was validated with the laboratory analyses of Zone 4 produced water samples. Then it was used to evaluate the impact of mixing formation brine and seawater on rock-fluid interactions and scale formation. The prediction is consistent with the observation of calcite formation in early production at Prudhoe Bay. The model also predicts the precipitation of iron carbonate and iron sulfide scales as the seawater flood continues.

Well-Productivity Improvement by Use of Rapid Overpressured Perforation Extension: Case History

Abstract This paper describes overbalanced perforating and surging operations as a pretreatment to hydraulic fracturing for the Romeo interval at Prudhoe Bay. Operation conditions are presented and discussed, as well as surface and bottomhole pressure measurements. Well productivity and the amount of proppant placed are compared to results in offset wells where the technique was not applied. The paper shows how the use of the technique allows placement of small, highly conductive fractures in intervals that were not previously considered fracturing candidates due to the close proximity to the gas/oil contact (GOC).The paper also shows pressure transient analysis affirming the technique as a stand-alone stimulation. It is shown that the use of extreme overbalanced perforating and surging treatments prior to hydraulic fracturing produces a substantial increase both in the success rate and the efficiency of the hydraulic fracturing operation and in the production rate of the wells that are pretreated. Finally, a comparison between pressure data and a new radial fracture propagation model shows a good match. The model demonstrates that high-energy treatment can significantly increase the extension and the height of the fracture; this was corroborated by downhole pressure measurements recorded during one overbalance treatment and by well logs. Introduction In 1990 an aggressive hydraulic fracture stimulation program began in the Prudhoe Bay Unit's Sadlerochit reservoir. This paper is limited to the ARCO-operated portion of the field or the Eastern Operating Area (EOA). North Slope wells, like offshore wellbores, are drilled from a central location. These extended reach wells present difficulties for hydraulic fracturing operations because of shear stresses associated with wellbores that do not align with one of the principal in-situ stresses. The fracturing campaign was highly successful and has resulted in an incremental oil rate of 180,000 barrels of oil per day (BOPD) from 1990 through1993 - Two hundred thirty-three wells were hydraulically fractured in the EOA, with a comparable number fractured in the Western Operating Area (WOA). The primary hydraulic fracture stimulation zones are the Romeo and the Zulu. Of these EOA wells, 34% were stimulated in the Romeo formation, 56% in the Zulu formation. Even though the zones are in the same reservoir there are significant differences requiring different hydraulic stimulation approaches. This paper addresses the more difficult to fracture Romeo interval by first describing the problem of Romeo formation fracturing followed by a discussion of the extreme overbalance (EOB) operations done at Prudhoe Bay. The impact of these pre-treatments is discussed on subsequent fracturing treatments and on the well productivity. Several case histories are presented that further illustrate the technique. Stimulation benefit of stand-alone extreme overbalanced perforating treatments is also investigated using bottomhole pressure data. Finally, fracture propagation model predictions of surface and bottomhole pressure are compared with surface and bottomhole pressure recorded during the EOB with fast-response pressure transducers. Formation Description. The Zulu is a clean sand several hundred feet thicken cased between large shales. These thick shales adjacent to the Zulu allow large fractures to be placed without fracturing out of zone. On the other hand, the lower Romeo sands are less continuous, less permeable, finer grained, and are thin sand/shale sequences.

Geophysics in the Multidisciplinary Reservoir Description Team: The RAZOR Project, Prudhoe Bay Unit, Alaska: ABSTRACT

Geophysics in the Multidisciplinary Reservoir Description Team: The RAZOR Project, Prudhoe Bay Unit, Alaska: ABSTRACT

Depositional Setting, Sequence Stratigraphy, Diagenesis, and Reservoir Potential of a Mixed-Lithology, Upwelling Deposit: Upper Triassic Shublik Formation, Prudhoe Bay, Alaska

The Upper Triassic Shublik Formation within the Prudhoe Bay field unit, North Slope, Alaska, is a potentially economic hydrocarbon reservoir comprised of mixed lithology and mineralogy. Its composition includes limestone, phosphate, shale, siltstone, and sandstone, as well as accessory amounts of siderite, glauconite, pyrite, kaolinite, and dolomite. Within the Prudhoe Bay field unit, the Shublik has been subdivided into four zones, lettered from base to top, D through A, which become thinner and show evidence of deposition under higher energy conditions toward the northeast. The formation is truncated to the east by the regional Lower Cretaceous unconformity. Zones within the Shublik comprise a basal transgressive systems tract (conglomerate lag at the Shublik Formation/Ivishak Formation contact through basal zone C shales) and two highstand shallowing-upward parasequences (zones C through B, and zone A, respectively). The parasequences are bounded by shales interpreted to represent deposition during periods of marine flooding. The contact between the Shublik and the overlying Sag River Formation juxtaposes comparatively deeper marine Shublik with shallower water glauconitic sandstones of the Sag River Formation. The contact is unconformable and is interpreted to represent a regional sequence boundary. Lithofacies of the Shublik are interpreted to have been coeval depositional facies of an upwelling system. Relative sea level changes durin Shublik deposition are interpreted to have caused the observed vertical and lateral variability in lithofacies via systematic changes between anaerobic, dysaerobic, and aerobic upwelling conditions. Dissolution of carbonate allochems resulted in the creation of moldic porosity that positively affected reservoir quality (i.e., permeability) in the carbonate packstone/grainstone facies. Areas of highest porosity are in the northern and northeastern parts of the field, which correspond to a combination of facies-controlled reservoir quality improvement toward the northeast and carbonate dissolution along the Lower Cretaceous unconformity and the North Prudhoe Bay fault zone. Oil in place for the Shublik within the Prudhoe Bay unit is estimated to be between 250 and 500 million bbl. Although permeabilities are generally low throughout the field area, the Shublik Formation has the potential to add significant reserves to the Prudhoe Bay field unit.

Horizontal-Well Performance at Prudhoe Bay

Summary The performance of Prudhoe Bay horizontal wells was evaluated after 1 to 5years of production. This paper describes the performance of horizontal wellsin the Western Operating Area of the Prudhoe Bay Unit (PBU), includingsurveillance and well-work achievements, new drilling and completiontechnology, and analytical evaluations. Introduction Production from most wells in the PBU is governed by a large Production frommost wells in the PBU is governed by a large expanding gas cap. As gasapproaches the productive intervals, coning necessitates restrictions onproduction well rate to control rate-sensitive GOR's because of facilitygas-handling constraints. Horizontal wells, called nonconventional wells(NCW's), initially were drilled to provide additional standoff from the gas capand greater oil rates and recoveries than the conventional-well (CW)offsets. The peripheral areas of the PBU receive limited direct pressure support fromthe gas cap, and some sections are being pressure support from the gas cap, andsome sections are being waterflooded in a pressure-maintenance program. Theperipheral area outside the waterfloods was the next target for NCW applicationwhere thin light-oil columns require increased wellbore exposure for highproductivity. NCW's then were drilled as peripheral waterflood producers inboundary patterns. Current development has targeted the low-productivity zonesat the base of the upstructure reservoir. These zones are characterized by poorreservoir quality and reduced formation thickness. In addition, the use of NCW's for gas injection in a peripheral extension ofthe field, the Eileen West End, maximized injectivity for a minimum number ofgas injectors. Existing vertical wellbores have been converted into NCW's withdrainhole technology. NCW's will continue to be used to develop the upstructure base zones andperipheral areas of the PBU. Future potential applications of NCW's includeadditional waterflood development (as injectors and/or producers) and drainholecompletions to produce the thin oil lenses left behind by gas encroachment asthe field continues to mature. There currently are 27 NCW's (Fig. 1) in the PBU, including two gasinjectors. BP Exploration (Alaska) Inc. operates 17 NCW's in the Western Operating Area of the PBU; Arco Alaska, Inc. drilled and operates the remainderof the NCW's in the Eastern Operating Area. Horizontal-Well Types Four types of NCW's are used in the PBU.Five horizontal wells have been drilled at angles of about 90 to verticalin areas known to be relatively free of vertical barriers to flow. This type ofwell provides maximum standoff from gas and/or water contacts while allowingenhanced productivity from the increased wellbore exposure.Fifteenhigh-angle wells were designed for areas where shales indicated potentialimpedance to vertical flow. These wells typically are drilled at 85 to 88 fromvertical and permit production from above and/or below any shales that wouldhave reduced recovery from a horizontal completion. High-angle wells have alsobeen used as gas injectors, where the longer wellbore increases injectivity.Four inverted high-angle wells have been used in areas where shales mayinterfere with the recovery mechanisms and where gas influx under the shales ispredicted. This technique involves drilling the entire light-oil column at ahigh angle and then turning the wellbore back up through the reservoir at anangle exceeding 90. The ability to plug back from encroaching gas influx at theend of the wellbore allows prolonged low-GOR production from this type of well.Three drainholes have been drilled, converting existing CW's into NCWcompletions by sidetracking a horizontal section into the productive intervalfrom the original wellbore. The drainhole completion provides potential costsavings because the existing wellbore is used down to the target reservoir. This reduces geologic uncertainty and eliminates a substantial portion of thedrilling investment for a replacement CW. Selection Criteria The major selection criteria for each type of NCW depend on the developmentobjectives, geology, reservoir fluid contacts, completion design, andeconomics. The geologic input required for each candidate should contain areservoir description, including the ratio of vertical to horizontalpermeability,; an accurate shale description; and an estimate of faultproximity.

Full-Field Simulation for Development Planning and Reservoir Management at Kuparuk River Field

Summary The Kuparuk River field on the Alaskan North Slope produces from twostratigraphically produces from two stratigraphically independent sands of the Kuparuk River formation. A full-field reservoir model was constructed tosupport field management and development planning. The model captures planning. The model captures essential aspects of two independent producing horizons, hydraulically producing horizons, hydraulically coupled at the wellbores, andsimulates dynamic interactions between the reservoir sands and surfacefacilities. The field model is used to plan field development on the basis ofperformance ranking of drillsite performance ranking of drillsite expansions, to assess depletion performance effects of reservoir performance effects ofreservoir management strategies, and to evaluate alternative depletionprocesses and associated reservoir and facility interactions of fieldprojects. Introduction A variety of development options are under evaluation for potentialimplementation at the Kuparuk River field. Several competing depletionmechanisms currently exist in the field. Introducing new projects will add tothe complex interrelationship of these depletion processes. Full-fieldreservoir simulation is used to forecast production performance under existingand future field performance under existing and future field configurations, toevaluate reservoir and facility interactions associated with field developmentalternatives, and to support ongoing field operation and management. This paperdiscusses the application of full-field paper discusses the application offull-field simulation to development planning and reservoir management at the Kuparuk River field. Motivation for Field-Scale Simulation. Using large-scale simulation forreservoir performance appraisal and development performance appraisal anddevelopment decision making has increased steadily* since the early developmentof black-oil reservoir simulators. Full-field reservoir simulation allowsreservoir depletion processes to he fully integrated with surface-facilityoperating constraints, resulting in resolution of dynamic interactions betweenthe reservoir and facilities. The need to quantify reservoir performanceexpectations more accurately spurs the development of more rigorous and complexfull-field reservoir models. Increased understanding and certainty derived fromadvanced field-scale simulation contributes to the decisionmaking process andpartially mitigates the risk associated with the large capital expendituresrequired for reservoir development. Kuparuk Reservoir Characteristics. The Kuparuk River field is located about40 miles [64 km] west of the Prudhoe Bay Unit (Fig. 1). Discovered in 1969, the Kuparuk reservoir contained an estimated 5 billion bbl of original oil in place(OOIP) with estimated recoverable reserves of nominally 1.6 billion bbl. The reservoir is made up of two distinct sandstone members within the Kuparuk River formation, a Lower Cretaceous, shallow, marine-shelf sanddeposit. The members are separated by a major unconformity, and two units arerecognized within each member. As Fig. 2 shows, the lower member contains Units A and B (informally named), with reservoir-quality sands present primarily in Unit A. The upper present primarily in Unit A. The upper member contains Units C and D, with reservoirquality sands present only in Unit C. Fig. 3 illustratesthe lateral extent of the Kuparuk sands. The A sand extends over the entirefield; the C sand covers a smaller area. Fig. 4 shows the dominant structural aspects of the Kuparuk sands. The Kuparuk interval forms a gently dipping anticline ranging in depth from 6,500to 8,500 ft across the structure. The trapping mechanism is a combination ofstratigraphic pinchout, erosional truncation, structural closure, pinchout, erosional truncation, structural closure, and a water/oil contact. Thereservoir is highly faulted by normal faults with up to several hundred feet ofthrow, which has a significant impact on flow unit continuity and fluidmovement. The predominant north/south fault trend density is nominally 3faults/sq mile. Faulting occurred during different depositional periods of the Kuparuk sands, influencing the character of the sand accumulations. Faultingoccurred primarily postdepositional to the A sand and postdepositional to the Asand and syndepositional with the C sand. Consequently, faulting frequency andpatterns are dissimilar for the two sand bodies. The Kuparuk sands are fairly thin, averaging 50 to 100 ft of grossthickness, but laterally extensive, covering roughly 200 sq miles. The C sandcontains several highly permeable, very prolific, interbedded zones permeable, very prolific, interbedded zones having an average permeability thickness of5,000 md-ft. Reservoir quality of the C sand, expressed by the distribution ofreservoir properties, is highly influenced by diagenesis and indirectly relatedto depositional facies. The A sand is characterized by sheet-like sandstonebodies interbedded with shales and mudstones. The A sand reservoir quality iscontrolled by depositional environment, and this sand, with its averagepermeability thickness of 1,000 md-ft, is permeability thickness of 1,000md-ft, is much less productive than the C sand. JPT P. 974

Improved Coiled-Tubing Squeeze-Cementing Techniques at Prudhoe Bay

Summary. This paper presents major changes in coiled-tubing squeeze-cementing techniques used in the Prudhoe Bay Unit Western Operating Area (PBUWOA). Changes include introduction of a polymer diluent to replace borax contamination, increased differential pressures placed on squeeze and coil, reduced cement volumes, and incorporation of an inflow test and resqueeze procedure. These changes resulted in increased squeeze effectiveness by reducing equipment and engineering time requirements and by shortening well shut-in time after the workover. Introduction Coiled tubing was introduced to the Alaskan North Slope because it is fast, mobile, relatively inexpensive, and well suited to subzero conditions. It is used extensively for a variety of purposes, including logging high-angle and horizontal wells, perforating, underreaming, cleaning out fill, squeeze cementing, and stimulating with acid. This paper focuses on squeeze cementing, also referred to as coiled-tubing unit (CTU) workovers. Techniques and data apply only to the PBUWOA. The primary objective of the original coiled-tubing squeeze-cement program, from late 1985 through mid-1988, was to extend plateau oil production. The anticipated decline point was delayed by working over wells that had the greatest potential for increasing oil rate and reducing excess gas. Reducing gas production from the worst offenders freed facility gas capacity to handle oil production from other wells with high producing GOR. These other high-GOR wells produced gas at rates greater than the acceptable field average, but not nearly as high as the wells with the highest priority for workovers. Freeing up facility gas capacity was then equivalent to bringing on shut-in oil wells. Coiled tubing is a continuous string of 1.5- or 1.75-in.-nominal-OD pipe wrapped around a reel and secured to a mobile control unit. Coil is threaded through an injector head (Fig. 1), pulled off the reel, and fed through well-control equipment (including pipe blind, shear and slip rams, and hydraulic control system) and into the well. Currently, about 10 CTU's are available for use on the North Slope, and BP Exploration (Alaska) has four on contract. Fig. 2 depicts a representative wellbore in the PBUWOA. It includes a 9 5/8-in. production casing set just above the Sag River formation and a 7-in. production liner set through 40 to 50 vertical ft of the Sag River formation and about 500 vertical ft of Ivishak formation, the primary productive interval in the field. Most of the wells are completed with a 9 5/8-in. packer with 4 1/2-in. tailpipe set immediately above the 7-in. liner top. The packer and tailpipe assembly are generally completed to the surface with 4 1/2- 51/2, or 7-in. tubing. Original CTU Squeeze Technique The original Prudhoe Bay Unit CTU squeeze technique was developed to reduce reservoir control costs compared with those of an arctic-rig workover. The CTU is mobile and requires less well preparation than an arctic rig. Arctic Conditions. The first technical issue resolved during development of the original program was year-round operating flexibility. Temperatures on the North Slope often dip below -40F and wind speeds reach 60 miles/hr during the winter. An individual on-site laboratory, manifold system, and tank farm were designed and constructed to be mobile and enclosed for heat. Air compressors are used to blow most soft lines dry, and a supply of methanol is kept on location to protect hard lines, coil, and the well, if necessary, from freezing. The CTU itself is well-suited to arctic conditions with an enclosed operating cab, no tubing joints to break or make up, and therefore no rig floor to heat. Removal of Excess Cement. The second major issue concerned removal of excess cement without drilling. In areas other than Alaska, the oil industry uses coiled tubing to squeeze cement into perforations or other liner breaches. In most cases, cement is cleaned out of the wellbore by moving in a rig and drilling out hard cement. Coil can be used to reverse out excess cement after a squeeze. However, special care must be taken with rates and pressures during the reverse-out because coil collapse is a major concern. Coiled tubing is thin-walled, flexible, and relatively fragile compared with jointed pipe. Because several coil collapses occurred early in the program, and published test data were lacking, differential pressures across the coil were limited to 1,500 psi until 1989. To avoid drilling and to reverse out cement within pressure guidelines for the coil and formation, a cement dilution and retardation fluid was developed. JPT P. 455^

Prudhoe Bay Field Study - Return Fluid Analysis

Summary. Monitoring ionic content of returned fluids after various acidizing treatments gives insight into actual chemical acid-spending processes that occur downhole. In this study, laboratory tests and field treatments were performed, and the resultant dissolution processes were monitored. Results show that the high siderite concentration (6 to 12 %) in the Sadlerochit formation accounts for most (60 to 70%) of the hydrochloric acid spending, as well as 10 to 15% of carbonate spending and 10 to 15% of clay dissolution during HF acid treatments. The HF spending was primarily on quartz/ chert in the laboratory. Field results, however, indicate that the secondary clay dissolution process was the primary HF spending reaction. Introduction The Prudhoe Bay field was discovered in 1968, and subsequent drilling confirmed that it was the largest oil and gas field in North America. The Prudhoe Bay Unit became effective on April 1, 1977, and began production on June 19, 1977, after completion of the Trans-Alaska Pipeline System. Since then, more than 750 wells have been completed in the Sadlerochit formation. Initial stimulation treatments were based on calcium carbonate scale removal and subsequent inhibitor squeezes. These treatments were quite effective in a high percentage of wells where scaling problems had been identified. In late 1984 and early 1985, HF acid treatments were started on the Sadlerochit formation to stimulate wells that did not respond to the established EDTA scale treatments. Since then, several HF acid treatments have been performed successfully. However, a greater understanding of downhole chemistry was needed to improve treating response even further. Several authors have presented laboratory studies on HF acidizing and the actual reactions occurring in various core types. Gdanski and Peavy presented a study on well return analysis and a method for calculating the actual downhole reaction with the specific ionic concentrations from fluids returned after a retarded-HF acid treatment. This paper describes a comprehensive study on acidizing in Zones 1B and 4 of the Sadlerochit formation. Mineralogy, solubility, oil, and acidizing chemistry studies were performed in the laboratory with Sadlerochit core samples to give an idea of the products that would be expected upon acidizing fluid return. Also discussed is the field study of several acidizing treatments and analyses of the actual returned fluids. Experimental Procedures Mineralogy. Mineralogy of the various core samples was analyzed by X-ray diffraction (XRD). An X-ray powder diffractometer was used on a bulk powder sample from Well 12–3. Acid Solubility Tests. In these tests, 1.00 g of disaggregated sample (from Well 12–3) was placed into 100.0 nit of either 15% HCl or 12 % HCl/3 % HF acid for 2 hours at 150 degrees F [66 degrees C] under a N2 gas blanket. Solubilities were determined by weight loss. Total iron content was determined by boiling the disaggregated sample with HCl acid containing H2O2. Extracted iron was determined by titration with dichromate. Dissolved-Solids Analysis. The supernatant fluids from the acid solubility tests were analyzed for dissolved solids contents. Cationic concentrations of Ca, Mg, Si, Ba, Al, Sr, Na, Fe, and K were determined from atomic absorption measurements. Total Fe concentrations on Well 12–3 samples were obtained from atomic absorption measurements; Fe3+ and Fe2+ concentrations were obtained spectrophotometrically. All concentrations are expressed in milligrams per liter. Returned Fluid Collection and Analysis. An elaborate collection scheme was implemented to perform a return fluid analysis. Samples of acids used to treat the formation or tubing were collected before the job to provide a known acid concentration and ionic content. When possible, a sample of the produced formation water was collected for ionic reference of the makeup fluid. Ions for which fluid was evaluated were Cl, SO4, Si, Fe (total Fe, Fe2+, and Fe3+), Ca, Al, K, Mg, Sr, Ba, Na, and F. Analyses for the specific ions were performed in a laboratory on the North Slope. In addition to the specific ion concentrations, a date, collection time, production rate, cumulative water production, water cut, pH, specific gravity, and live acid concentration of the returned samples were recorded. Mineralogy Return analyses-from two of the four production zones in the Sadlerochit formation (Zones 1B and 4, with the emphasis on Zone 4 wells) was completed. JPT P. 466⁁

Characterization of hydrocarbon gas within the stratigraphic interval of gas-hydrate stability on the North Slope of Alaska, U.S.A.

In the Kuparuk River Unit 2D-15 well, on the North Slope of Alaska, a 60 m-thick stratigraphic interval that lies within the theoretical pressure-temperature field of gas-hydrate stability is inferred to contain methane hydrates. This inference is based on interpretations from well logs: (1) release of methane during drilling, as indicated by the mud log, (2) an increase in acoustic velocity on the sonic log, and (3) an increase of electrical resistivity on the electric logs. Our objective was to determine the composition and source of the gas within the shallow gas-hydrate-bearing interval based on analyses of cutting gas. Headspace gas from canned drill cuttings collected from within the gas-hydrate-bearing interval of this well has an average methane to ethane plus propane [C 1/(C 2+ C 3)] ratio of about 7000 and an average methane δ 13C value of −46% (relative to the PDB standard). These compositions are compared with those obtained at one well located to the north of 2D-15 along depositional strike and one down-dip well to the northeast. In the well located on depositional strike (Kuparuk River Unit 3K-9), gas compositions are similar to those found at 2D-15. At the down-dip well (Prudhoe Bay Unit R-1), the C 1/(C 2 +C 3) ratios are lower (700) and the methane δ 13C is heavier (−33%). We conclude that the methane within the stratigraphic interval of gas hydrate stability comes from two sources— in situ microbial gas and migrated thermogenic gas. The thermal component is greatest at Prudhoe Bay. Up-dip to the west, the thermogenic component decreases, and microbial gas assumes more importance.

An Immiscible WAG Injection Project in the Kuparuk River Unit

Summary Immiscible water-alternating-gas (WAG) injection has been successfully used in the Kuparuk River Unit as a means of controlling excess gas production. Additionally, simulation results have indicated that WAG injection can increase economic oil recovery by improving waterflood conformance. WAG recovery mechanisms, simulation results, field performance, and field surveillance are discussed. Introduction The Kuparuk River Unit lies on the North Slope of Alaska about 40 miles [64 km] west of the Prudhoe Bay Unit, Fig. 1 shows the location of the field, which covers about 1 15,000 acres [46 500 ha]. Oil production currently averages 290 MSTB/D [46 × 10(3) M3/d] with an associated gas production rate of 320 MMscf/D [9.1x10(6) std M3/d]. After fuel usage and limited gas sales, about 240 MMscf/D [6.8 × 106 Std M3/d] of the gas is injected back into the formation. Effective utilization of the injected gas is crucial to the near-term oil rate and long-term oil recovery of the unit. The Kuparuk reservoir structure is a slightly dipping northwest/southeast-trending anticline at about 6,000 ft [1829 m] subsea. The outline of the field is defined by a stratigraphic pinchout and truncation to the west and south and along the line of an oil/water contact to the east and north. Two marine sandstone producing intervals are found within the Kuparuk reservoir. Both sands were initially undersaturated at reservoir pressures of about 3,100 psi [21 MPa] and an initial reservoir temperature of 158 degrees F [70 degrees C]. Kuparuk crude oil has an average stock-tank gravity of 24 degrees API [0.91 g/cm3]. oil viscosity is 2 cp [2 mPa - s] at the initial pressure of 3, 1 00 psi [21 MPa], and solution gas is 450 scf/STB [80 std m3/stock-tank m3] at the bubblepoint pressure of 2,950 psi [20 MPa]. The total recoverable reserves for the unit are more than 1,700 MMSTB [270 × 106 stock-tank m3]. The upper sand body, designated Sand C, contains about one-third of the original oil in place (OOIP). It is moderately fractured with an average permeability/thickness, kh, of 4,000 md-ft [ 1200 md - m] and an average porosity of 22 %. The lower sand body, designated Sand A, contains the bulk of the reserves with an average kh of 1,500 md-ft [460 md - m] and an average porosity of 24%. Sand A, which has very few natural fractures, is more continuous than Sand C. The two sands are separated by the nonproductive B interval, which is made up of siltstones, shales, and some sandstones. Fig. 2 is a type log of the sands and Fig. 3 is a field map showing the approximate areal extent of Sands C and A. The Kuparuk field began producing in Dec. 1981 under solution-gas drive. Lacking a market for the majority of the produced gas, the unused portion was injected into two areas of Sand C. Thin, relatively horizontal sands and the lack of an original gas cap resulted in early breakthrough of the injected gas. Limited gas-handling facilities dictated that high-WR wells be shut in, deferring oil production from the gas injection areas. To date, more than 500 MMSTB [80 × 106 stock-tank m3] of the OOIP in Sand C has been adversely affected by gas injection. The areal extent of the gas-affected Sand C is depicted by the thin solid lines in Fig. 3. Limiting the expansion and accelerating the blowdown of this gas-affected area is clearly important to maximizing near-term oil rate. In evaluating the gas-handling problem, alternative projects were considered on five premises: the project must have favorable economics, it must not adversely affect oil reserves, it must be environmentally safe. it must use the gas efficiently, and it must be capable of implementation in a relatively short amount of time. Potential opportunities that satisfied all of these constraints included miscible injection, offsite sales for fuel gas, offsite injection into other horizons, foam injection, and immiscible WAG injection. Although several of these alternatives were ultimately used, this paper deals specifically with immiscible WAG injection.

Waterflood Surveillance in the Kuparuk River Unit With Computerized Pattern Analysis

This paper describes the computer-aided waterflood surveillance method used in the Kuparuk River field. The flood is monitored pattern by pattern, with production and injection allocations verified by comparison of measured field pressures with pressures calculated by material balance. The resulting detailed knowledge about waterflood progress has led to operational changes and workovers to optimize waterflood performance.

Horizontal Drilling Techniques at Prudhoe Bay, Alaska

Summary Three extended-departure horizontal wells have been drilled and completed in the Prudhoe Bay Unit, AK, by Standard Alaska Production Co. Horizontal slotted-liner completions of 1,575, 1,637, and 1,163 ft [480, 499, and 354 m] were achieved at an average vertical depth of 9,000 ft [2743 m]i. Over the three-well program, improvements in technology and operating procedures have resulted in a 40% reduction in cost per foot. When compared to conventional completions, production data from the horizontal wells indicated rate benefits up to 300% and a potential increase in ultimate recovery. This paper discusses the development of the techniques used to drill horizontal wells at Prudhoe Bay and reviews the horizontal drilling operations for each well. Introduction The application of horizontal drilling to the Prudhoe Bay field is driven by the goal of increasing ultimate field recovery. Conventional recovery methods are expected to leave an estimated 12 billion bbl [19 Gm3] of oil in place. Horizontal drilling in areas with gas and water coning potential and in regions of uneconomic oil column thickness was viewed as a potential method to maintain Prudhoe production levels and to increase ultimate recovery. In the midfield area at Prudhoe Bay (Fig. 1), the oil column lies between an expanding gas cap and a water leg. Throughout the production life of a well, high formation permeability allows production life of a well, high formation permeability allows increasing gas and water fractions because of coning. The overall production rate of the field will eventually be limited by the gas production rate of the field will eventually be limited by the gas handling capacity because the produced gas and water must be reinjected. A horizontal completion, strategically placed between the gas cap and water leg, will allow increased production rates at lower drawdown pressures and, consequently, will reduce gas and water coning tendencies. In the southwestern portion of the field where the oil column is less than 100 ft [30 m] thick, development using conventional wells is hindered by economic considerations. Because the gas cap is absent in this area, horizontal wells can be drilled along the top of the oil zone to expose longer reservoir sections that provide economical production rates while minimizing water production. In Jan. 1984, Standard Oil Production Co. began work on a project to develop the technology to drill and to complete horizontal project to develop the technology to drill and to complete horizontal wells at Prudhoe Bay. The strategy chosen was to drill a test well in south Texas to provide a technical basis, followed by three Prudhoe Bay wells to optimize the drilling techniques. To maximize the Prudhoe Bay wells to optimize the drilling techniques. To maximize the transfer of technology, drilling supervisors and a geologist from Standard's Alaska staff were assigned to the test well. Key individuals of the team that had drilled four successful horizontal wells in Europe were employed as consultants. The south Texas test well, Braune-Wieding No. 1, was designed to model closely the proposed Prudhoe Bay horizontal well profile. A 1,900-ft [579-m] horizontal section (inclination greater profile. A 1,900-ft [579-m] horizontal section (inclination greater than 84 degrees) was successfully placed in a 30- to 40-ft [9- to 12-m] -thick sand near 10,300 vertical ft (3140 m]. The well established and verified several planning and operational techniques. A top-drive system proved beneficial in dealing with anticipated directional drilling conditions, especially tight hole problems. Using, this system, two o three connections were eliminated and back-reaming while circulating 90-ft [27-m] sections was possible. To maximize torque available at the bit, a torque/drag simulator was used to design the wellbore profile and drillstring configuration. Experience was gained in high-angle directional drilling using steerable mud motors and conventional rotary assemblies. Measurement-while-drilling (MWD) systems were used extensively and proved indispensable for directional surveying and formation identification using gamma ray and resistivity sensors. Geologic markers were used to adjust and refine the directional profile continually while building angle to horizontal. Wellbore stability was a critical consideration in the high-angle sections of the well, and invaluable experience was gained in maintaining stability with high-weight, low-fluid-loss drilling fluids. Adequate hole cleaning was achieved with optimal mud properties and efficient solids removal equipment. The well was properties and efficient solids removal equipment. The well was logged with drillpipe-conveyed tools and completed using a slotted liner placed through the entire horizontal section. The completion incorporated a specially built liner hanger/packer and a circulating string that permitted drilling fluid displacement from the slotted liner.

Transportation Requirements for Drilling Operations on the Arctic North Slope of Alaska

Summary Since the OPEC oil embargo of 1973, U.S. oil companies have been placing increasing emphasis on exploring for and producing oil located within the U.S. Alaska's North Slope has received a great amount of attention recently as there exists a known transportation system (the Trans Alaska pipeline) and because geological information indicates the potential for pipeline) and because geological information indicates the potential for large producing reservoirs. Drilling on Alaska's Arctic North Slope poses a number of interesting operational problems, including transporting and supporting drilling rigs to their respective locations. Sohio Alaska Petroleum Co. has extensive experience in transporting and supporting drilling figs in development operations (Prudhoe Bay) and exploration locations both on- and offshore Alaska's Noah Slope. This paper addresses how arctic drilling figs are transported to development locations within the Prudhoe Bay Unit and to remote on- and offshore locations. Principal topics deal with the current methods by which rigs are moved and how daily drilling operations are supported. In addition, this paper discusses transportation systems that may be required when drilling operations extend beyond the Barrier Islands of Alaska's North Slope. Introduction Drilling operations on Alaska's North Slope have come a long way since the discovery of oil at Prudhoe Bay in 1968. During the early days of drilling at Prudhoe, rigs were transported to the Slope by Hercules C-130 aircraft, barges up the west coast of Alaska, or cat trains up the 375-mile [603-km] winter-haul road out of Fairbanks. In 1975, the all-weather Trans Alaska pipeline haul road to Prudhoe Bay was completed, which provided an pipeline haul road to Prudhoe Bay was completed, which provided an alternative method to bring rigs to the slope. This paper explains how drilling figs are transported to drilling locations on Alaska's North Slope. The figs and support equipment now being used in the development of Prudhoe Bay have day rates that exceed $50,000. To minimize the time it takes in the Prudhoe Bay field to move a fig from one well to the next requires the use of specially designed fig-transportation systems. Two such systems are described, one with rollers on skids and another with rubber-tire wheels coupled to a jacking system. Exploration drilling up to 60 miles [97 km] from Prudhoe Bay is being conducted. This work involves moving Prudhoe Bay development rigs to both on- and offshore locations. This paper discusses moving rigs to exploration locations by Hercules aircraft, rolligons, trucks over ice roads, and barges-the methods being used by most operators drilling on the North Slope. Arctic North Slope Environment The North Slope of Alaska is bordered to the north by the Chukchi and Beaufort Seas and to the south by the Brooks Mountain Range (Fig. 1). The entire 90,000 sq miles [233 099 km 2] of land making up the North Slope lies wholly above the Arctic Circle. Prudhoe Bay, the largest oil field in North America, is located within this region and occupies about 0.5% of the overall area. Situated on the edge of the Beaufort Sea, Prudhoe Bay is approximately 250 miles [402 km] north of the Arctic Circle and 1,300 miles [2092 km] south of the North Pole. JPT p. 2308

Joint Geologic/Engineering Analysis of the Sadlerochit Reservoir, Prudhoe Bay Field

This paper demonstrates the importance of coordinated geological and engineering effort to develop an accurate reservoir description. The techniques discussed and applied when developing the description of the Sadlerochit reservoir of Prudhoe Bay Field have particular application where sophisticated numerical simulation models are used to evaluate operating alternatives for a field. Introduction The Prudhoe Bay Field on the north coast of Alaska is the northernmost oil field in the world, situated about 250 miles (402 km) north of the Arctic Circle. The field was discovered in 1968, and subsequent drilling confirmed that it is the largest oil and gas field in North America. Shortly after the discovery, the major working-interest owners and the State of Alaska recognized the benefits of operating the field as a unit; unitization negotiations began in 1969. The Prudhoe Bay Unit, which is operated by ARCO Oil and Gas Co. and Sohio Petroleum Co., became effective April 1, 1977, and is Petroleum Co., became effective April 1, 1977, and is one of the few units in the U.S. formed before production began. After completion of the Trans-Alaska production began. After completion of the Trans-Alaska Pipeline System, the field began producing June 19, Pipeline System, the field began producing June 19, 1977, almost 9 years after its discovery.During the past 8 years, the Prudhoe Bay Field has been the subject of intensive geologic study and engineering analysis, both to determine in-place volumes and to develop an operating plan for the field. This paper describes the methods used by geologists and engineers to develop reservoir descriptions of Prudhoe Bay for use in numerical simulation studies. Similar studies were conducted by Exxon Co. U.S.A., ARCO Oil and Gas Co., and Sohio Petroleum Co. Since these studies were conducted independently, they naturally led to somewhat different descriptions. Thus, data given here do not always correspond to the best estimates of all three companies, nor did the three companies apply the methods described next in all cases. Results of independent reservoir performance studies, based on the companies' reservoir descriptions, were used to design production facilities, to select initial completion production facilities, to select initial completion intervals, and to develop a long-range operating plan for the field. Geologic Setting The first step in the development of a reservoir description should always be an intense geological study. Such a study is fundamental for explaining the anomalies present in the reservoir, such as a tilted water-oil contact, fracture system, lithologic units, and shale continuity.The principal oil and gas accumulations at Prudhoe Bay Field are in rocks of Permo-Triassic age. Fig. 1 shows the geologic setting for the Prudhoe Bay Field and gives some clues as to the geologic history of the area. The Prudhoe Bay Field is a combination structural and stratigraphic hydrocarbon trap situated on the south flank of the Barrow Arch. The northern limit of the field is established by a series of normal faults, downthrown to the north, which have up to 1,000 ft (305 m) of displacement.The Permo-Triassic sediments were derived from a source area situated north of the present coastline. Various unconformities in the Prudhoe Bay area indicate that the Barrow Arch was at or near sea level several times during its history. JPT P. 933