Prudhoe Bay Field Research Articles

Analysis of the technology for increasing the recovery and intensification of hydrocarbon production

The analysis and improvement of the method of additional stimulation of horizontal wells – carrying out multi-zone hydraulic fracturing, which allows to significantly increase the productivity of the well, increase the drainage area, which is especially important in formations with low permeability. In this paper, the oil recovery methods used at the Yuzhnoye field, the method of modeling hydraulic fracturing were considered, and hydraulic fracturing of a highly permeable formation was simulated for two wells 1 and 3 (double-wellbore) in this field. The optimization of the hydraulic fracture design is aimed at creating a fracture of maximum conductivity and minimum length. Since neocom is a highly permeable formation, the TSO (tipscreenout) technology is proposed for hydraulic fracturing – this is end screening. This TSO technology is successfully applied at the Prudhoe Bay field (USA), in the Gulf of Mexico, Indonesia, the North Sea, Canada, Brazil, Venezuela, Vietnam, Saudi Arabia. In Russia, an example of successful design and execution is the hydraulic fracturing operation with TSO in well 4370 of the Muravlenkovskoye field, Noyabrskneftegaz company. The hydraulic fracturing method will increase the vertical permeability and unite the disparate parts of the reservoir, which will make it possible to more efficiently develop the reserves of the Neocomian deposits in the field, system for electricity consumption for the purpose of short-term forecasting of electricity consumption.

North Alaska Super Basin: Petroleum systems of the central Alaskan North Slope, United States

North Alaska Super Basin oil fields have produced more than 18 billion bbl of oil with at least 5 billion bbl remaining in existing fields, and estimated yet-to-find resources exceed 10 billion bbl in three prolific petroleum systems. Since discovery of the two largest United States conventional oil fields at Prudhoe Bay and Kuparuk River in the 1960s, technological advancements including three-dimensional seismic data with amplitude vs. offset analysis, horizontal and extended reach drilling, and identification of source rocks for light oils have enabled new discoveries including Willow and Pikka. Oil in the Prudhoe Bay field is interpreted as a mixture cosourced by lateral migration from Triassic Shublik Formation shale and carbonate, Lower Cretaceous highly radioactive zone (HRZ) shale, and Lower Jurassic Kingak Shale. The bulk properties of Prudhoe Bay main field oils are consistent with the modeled oil composition expelled within the fetch area, and the presence or quality of carrier beds apparently did not affect oil migration efficiency. The Shublik Formation is interpreted as the oil source for Kuparuk River field, the HRZ shale is interpreted as the oil source for Tarn field, and the Kingak Shale is interpreted as the oil source for Alpine field. Point McIntyre field is interpreted as sourced by the same three source rocks as Prudhoe Bay field, and Fiord field is interpreted as cosourced from Shublik and Kingak. West Sak field is interpreted as a mixture of moderately biodegraded oil that spilled from the Prudhoe Bay field and lightly biodegraded condensate that leaked from the underlying Kuparuk River field.

A lateral well in the Shublik Formation, Alaska North Slope, with implications for unconventional resource potential

Analyses of a horizontal well drilled in the Shublik Formation within the southern part of the Prudhoe Bay field provide the first glimpse of the unit’s potential as an unconventional resource. Drilled in 1996, the 1450 ft (442 m) long well, PBU X-19B L1, targeted the 17 ft (5 m) thick Shublik Zone B. More than 70% of the lateral well path sampled that target, a feat of precise geosteering years before the unconventional revolution. The well operator’s drilling plan focused on the middle subzone of Zone B. The well history ascribes the focus on the middle subzone to its high silt content, open fractures, and significant hydrocarbon shows. Contrary to the drilling narrative, cuttings from 41 intervals indicate that siltstone monotonically decreases in Shublik Zone B, on average, from 50% to 40% to 30% in the three subzones from top to base. The limestone concentration inversely varies with the siltstone concentration through Zone B, steadily increasing from top to base (40%, 50%, and 60%). Hydrocarbon shows in the upper and middle subzones of Zone B range from good to fair, whereas the shows in the lower Zone B are weaker. Unfortunately, scant geochemical analyses of oil produced from the Shublik flow test combined with engineering difficulties prevent a definitive conclusion as to the source of the oil — the fractured Shublik Formation or the underlying Ivishak Sandstone. However, on the basis of favorable lithology, hydrocarbon shows, and fracture density, the upper and middle subzones of Zone B should be targeted as a potential unconventional accumulation if and when a well is drilled in the pod of active source rock downdip.

Automated Operations and Wired Drillpipe Benefit Arctic Drilling

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 191574, “Delivering Drilling Automation II: Novel Automation Platform and Wired Drillpipe Deployed on Arctic Drilling Operations,” by Riaz Israel, Doug McCrae, Nathan Sperry, Brad Gorham, Jacob Thompson, and Kyle Raese, BP, and Steven Pink and Andrew Coit, SPE, NOV, prepared for the 2018 SPE Annual Technical Conference and Exhibition, Dallas, 24–26 September. The paper has not been peer reviewed. This paper presents a case history of drilling automation system pilot deployment, including the use of wired drillpipe, on an Arctic drilling operation. Two major aspects of technology were introduced during this pilot, the first being a drilling automation software platform that allowed secure access to the rig’s drilling control system. The second component was a wired drillstring, which provides high-speed delivery of downhole data from a series of distributed downhole sensors. Introduction In an effort to enhance the safety of its operations, improve well construction efficiency, and leverage the potential opportunities presented by digitalization of drilling, the operator has initiated a Remote Operations and Intelligent Automation Project. The project involved the deployment of an automation operating system (AOS) on top of an existing drilling control system. The AOS provides the ability for secure, programmatic control of the rig’s major drilling hardware through the use of software. The software interface allows for custom configuration of several routine drilling activities for automated execution. The project also evaluated the latest version of the service company’s wired drillpipe (WDP). At the time of writing, the project has delivered eight wells, with various combinations of the technology implemented. The overall objectives of the project were to evaluate The readiness of the AOS for wider deployment The reliability of the latest version of WDP The maturity of the AOS drilling applications The effectiveness of this technology in reducing well costs For each well, key performance indicators (KPIs) were defined that aligned with the project-level KPIs and are dependent on the specific aspect of the technology being used on that well. Field Description The giant Prudhoe Bay field, on the North Slope of Alaska on the edge of the Arctic Circle, was discovered in 1968 with an initial estimate of 22 billion to 25 billion bbl of oil in place and has been in production since June 1977. Since the field began production, it has generated more than 12.5 billion bbl of oil, making it the most productive US oil field. The field has been a proving ground for advanced drilling techniques, including multilateral and coiled tubing, now used in oil fields around the globe. Production from Prudhoe Bay is supported by ongoing drilling activity. Technology Description An overview of the automation technology is presented in Fig. 1.

The role of calcareous and shaly source rocks in the composition of petroleum expelled from the Triassic Shublik Formation, Alaska North Slope

For nearly thirty years, the Triassic marine carbonate Shublik Formation has been suggested and confirmed as a key source rock for hydrocarbons in the North Slope of Alaska. The formation accounts for roughly one third of the oil in the supergiant Prudhoe Bay Field, and for nearly all of the oil in the second largest Kuparuk River Field. Recent studies of oil types in the vicinity of the Northstar Field suggested presence of “shaly” organofacies of the Shublik Formation based on the likely Triassic age and marine shale biomarker signatures of some analyzed oil samples. The current work fills the gap between biomarker analysis of predicted “calcareous” and “shaly” oil types and source rock geochemistry. Biomarker-based oil-source rock correlation confirms the presence of two genetically-distinct organofacies and related oil families. Both groups were deposited under a similar redox condition (anoxic to suboxic) with dominantly marine algal input but in either (1) a clay-rich or (2) a clay-poor depositional setting. Chemometric evaluation of multivariate biomarker data reveals mixtures with variable degrees of mixing between end members. Analysis of diamondoids confirms mixed oil types and establishes diamondoid signatures of source rock end-members. This allows for correlation of biomarker-poor, overmature Shublik source rock samples to oils, and extends these interpretations over large areas of the North Slope.

Optimizing the Use of Miscible Injectant at the Greater Prudhoe Bay Fields

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 180420, “Optimizing the Use of Miscible Injectant at the Greater Prudhoe Bay Fields,” by S.X. Ning, SPE, B.S. Jhaveri, E.M. Fueg, SPE, G. Stechauner, J.L. Jemison, SPE, and T.A. Hoang, BP Exploration (Alaska), prepared for the 2016 SPE Western Regional Meeting, Anchorage, 23–26 May. The paper has not been peer reviewed. Miscible injectant (MI) has been used at Prudhoe Bay and its satellite fields for more than 30 years. This paper provides an overview of all enhanced-oil-recovery (EOR) projects in the Greater Prudhoe Bay (GPB) region and presents the process and methodology for MI allocation to these projects and to individual injection patterns. A new approach is used to determine the amount of MI allocated to each project on the basis of predicted marginal MI use per barrel of EOR oil. Introduction The MI-gas EOR process at Prudhoe Bay began in late 1982. In late 1986, the Central Gas Facility (CGF) began operation, enabling the first field-scale EOR project, the Prudhoe Bay Miscible Gas Project (PBMGP), to start in early 1987. Since then, the PBMGP has expanded to more than 170 injection patterns in the main field of Prudhoe Bay. Fig. 1 provides a layout of the oil fields on the North Slope of Alaska. The CGF is a gas-processing plant that makes natural-gas liquids (NGLs) for shipment in the Trans-Alaska Pipeline System and MI for EOR projects. The CGF currently processes an annual aver-age of approximately 7.5 billion scf/D of produced gas to generate approximately 40,000 STB/D of NGL and more than 200 million scf/D of MI. The feed gas comes from three different sources—solution gas from the produced oil, free reservoir gas from the gas cap, and returned MI (RMI) that was previously injected into the reservoir. The total amount of MI produced at the CGF is the sum of the fresh MI (which can be forecast by the GPB full-field simulation model) and the recaptured RMI (which can be forecast by COBRA and process modeling). COBRA is a full-field scale-up tool for predicting MI performance on the basis of type-pattern-simulation-model results. MI gas produced at the Prudhoe Bay CGF is a rich gas composed primarily of carbon dioxide (approximately 21%), methane (approximately 32%), ethane (20%), propane (25%), and a small amount of butane and heavier components (approximately 2–3%). Most of the GPB EOR projects are pattern floods that use a water-alternating-gas (WAG) injection to improve areal and vertical sweep efficiencies.

Major Alaskan Discoveries Promote Great Expectations

The Pikka Field discovered by Armstrong Oil & Gas is just 2 to 3 miles wide, about 30 miles long, could produce 1.2 billion barrels of oil, and is one of three major finds that have shattered assumptions about what is possible in the most explored parts of Alaska’s North Slope. “The Armstrong discovery, and especially the size of that discovery, was stunning to everyone,” said David Houseknecht, a geologist for the US Geological Survey who has done multiple assessments of the potential in the area. “The thinking was the biggest oil pool we could imagine had 200 to 250 million barrels of recoverable oil. These discoveries coming in with more than a billion barrels or 300 million barrels, at least, really change things by an order of magnitude.” The find by Armstrong in March may not be the biggest of the three. A discovery by Caelus Energy in Smith Bay called Tulimaniq could produce twice as much oil though the development challenges are also much greater. And Conoco Phillips’ Willow discovery could ultimately produce from 3.3 to 3.9 billion, and add more than 400,000 B/D of production in the next decade. It is an impressive total, even when discounted for the fact that these are early estimates in a costly area for development in a period of struggling oil prices. In addition, what has been learned about identifying the subtle signs of oil trapped within two large formations—the Nanushuk and the Torok—could open up greater opportunities. The recent finds could turn the Nanushuk from a minor reservoir into a “virtually unexplored play fairway covering at least 9000 to 15000 km2 that includes both onshore and shallow offshore areas,” said Houseknecht. He made the comment during a presentation at the recent annual meeting of the American Association of Petroleum Geologists in Houston, where even poster sessions on the North Slope drew crowds. Those finds highlight advances in the tools used to look for oil pockets trapped in the earth, and unconventional techniques needed to maximize production from conventional reservoirs that are tighter than the free-flowing reservoirs found in the aging Prudhoe Bay field to the east. “The bottom line is, because of 3D seismic and because of the completion practices used for unconventionals, we can now reasonably look at low-permeable Brookian [Nanushuk and Torok] reservoirs as viable,” he said. One sign of the industry’s confidence was bidding at state and federal lease sales in December, where Conoco Phillips was the most aggressive bidder, picking up about 600,000 net acres, said Alison Wolters, a research analyst for Wood Mackenzie.

Facies analysis and its relation to point-sourced growth faults in river-dominated prodeltaic delta front deposits of the Cretaceous Ferron Notom Delta, Utah, USA

This study evaluates the evolution of a small-scale growth fault within a deltaic parasequence of the Ferron Sandstone, Utah. Analysis is based on 4 stratigraphic logs, and a panorama covering 100 m of lateral exposure.Five growth-fault blocks are displayed in strike and dip views. The listric faults dip basinward, and sole out into bedding parallel decollement surfaces associated with deformed prodelta shales, which also form diapirs. Throw on individual faults averages 4 m and heave increases with depth from ∼2.5 to ∼5 m. Strikes on fault planes average 160°, and fault dip decreases with depth from 50° to 0°, where they become parallel to bedding.Pre-growth facies comprise heterolithics with abundant graded beds, current-ripples, wave-ripples, small-scale soft sediment deformation, and a low bioturbation index. This indicates deposition in a river-dominated, storm-influenced delta that was supplied primarily by storm-triggered flood events and prograded rapidly. Growth strata are primarily planar and quasi-planar fine sandstones deposited as upstream and downstream accreting mouth bars.Faulting initiates with the building of a “critical load” reflecting a low-angle delta front foreset, probably linked to deposition in a mouth bar. Mobile prodelta muds form diapirs that breached the sediment-water interface, providing accommodation for the fault blocks. Termination of faulting occurred when sandy growth strata contacted and locked into higher strength pre-growth heterolithics deeper in the section. Minor deformation of growth strata is demonstrated by synthetic microfaulting in growth sands.This study emphasizes a localized stress field (i.e., point sourced) associated with sandy mouth bar deposits, which acted as fault initiation points. This contrasts with the distributed stress regimes commonly associated with regional-scale growth faults along continental margins. This can lead to expanded, but localized, reservoir compartments within river-dominated deltaic systems, especially those in epeiric seas or other shallow-water sedimentary basins, such as Prudhoe Bay Field, Alaska.

Improving People’s Lives: Minimizing Impact

President's column Last December I had the pleasure of returning to the Kingdom of Saudi Arabia and touring the giant Manifa oil field. Manifa produces a heavy, sour crude oil from six, long (up to 40 km), stacked reservoirs in shallow water (Arukhe 2014). The shallow waters have abundant sea grasses and corals and are teeming with marine life. Shrimping and fishing are important parts of the local economy. The development of the Manifa field is a fascinating story showing how creative solutions can minimize impact on the environment. Manifa was discovered by Saudi Aramco in 1957. The discovery well targeted both the shallower formations productive in the large Safaniya coastal field and the deeper Arab formations so productive onshore. Neither zone was productive; however, the discovery found excellent productive layers in between, including three that were only produced in small volumes onshore and three that had never before proved productive. The heavy, sour crude was similar to Khursaniyah, one of the three major types of crude present in large quantities in the Kingdom. Demand was less for this crude than for Safaniya and Arab crudes but the market for heavy sour crudes was improving (Aramco World 1963). The first development was in 1962, and the field was brought on stream in 1964. The field produced for 20 years before being mothballed in 1985 because of low demand (Aldossary 2015). Manifa’s history can be contrasted with that of Prudhoe Bay in Alaska. While specific reserve estimates for Manifa are not public information, both fields are very large. The Prudhoe Bay field was discovered in 1968 and did not begin production until 1977. Prudhoe production peaked at about 1.5 million BOPD in 1989. Prudhoe Bay crude averages 27.6 °API and had a significant domestic market to serve. Manifa crude is 26–31 °API and has from 2.8% to 3.7% sulfur content (Croft and Patzek 2009), with less of a market at the time. It is fairly astonishing that roughly comparable fields would go down such radically different paths. Manifa would remain mothballed until 2006. Saudi Aramco redeveloped the field consistent with a very long life production time horizon for its large reservoirs (Saudi Aramco 2016). But the old way of approaching shallow offshore fields would not be acceptable. The use of jackup rigs in these shallow waters would have required excessive dredging, and the size of the reservoir eliminated the possibility of effective development from the shore. A new approach to development would be needed. A creative plan to develop man-made islands connected by a causeway would allow conventional onshore rigs to be used to develop this offshore field. A long causeway was considered, but early designs would have decreased water circulation vital to distributing nutrients and oxygen vital to marine life. With more than 4 million man-hours of work in the design phase, a solution was developed to build 27 man-made islands connected by 41 km of causeways. To ensure needed water circulation, the causeway does not go all the way across the bay and 14 bridges were built into the causeway to further improve circulation (Aldossary 2015). Production commenced in 2012 ahead of schedule and under budget in a development that earned a UNESCO Environmental Responsibility Award nomination. It is an impressive development of which Saudi Aramco is rightly proud, with eventual production capacity of 900,000 BOPD or more. As our helicopter approached the massive processing facility, I looked at the three large flare stacks. There was nothing being flared. Was the field shut in? No, the design and normal operations of the field use all of the produced gas and creative operations practices mean that almost no gas is flared. Excess electricity produced by the facilities goes into the power grid.

Coiled-Tubing-Deployed Shutoffs in Alaska With a Polymer Gel and Microfine Cement

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 173655, “Coiled-Tubing-Deployed Gas and Water Shutoffs in Alaska With a Polymer Gel and Microfine Cement,” by D.B. Robertson, SPE, BP; M.A. Brown, Petrotechnical Resources of Alaska; L.H. Duong, SPE, BP; O.V. Ivanova, Schlumberger; and A. Tambe, SPE, BP, prepared for the 2015 SPE Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, USA, 24–25 March. The paper has not been peer reviewed. A common problem in oil and gas wells is excess free gas or water production from only certain portions of the completed interval. A coiled-tubing-deployed profile-modification technique was developed primarily to shut off excess free-gas production from the heel of cased-and-perforated horizontal oil wells. The technique has also been used for water and gas shutoff in both vertical and horizontal wells in a variety of lower-completion types. Introduction Coiled-tubing work has a well- established track record in North Slope of Alaska oil fields involving several thousand interventions of various types. Fig. 1 is a photograph of a typical Arctic-winter coiled-tubing operation. Most of the approximately 1,700 wells in the Prudhoe Bay field penetrate either an extensive gas cap or the aquifer in the sandstone reservoir. Mechanisms for excess free-gas or water production can be related to poor primary-cement jobs of production liners, fluid-contact movements over time, coning, or corroded or damaged liners. In general, any through-tubing-profile modification that can be performed to reduce excess free-gas and water rates and increase oil rate or time on production is beneficial to overall field production. With many candidate wells, there has been a continuous evolution in job design and execution techniques over the years.

Understanding the impact of open-framework conglomerates on water–oil displacements: the Victor interval of the Ivishak Reservoir, Prudhoe Bay Field, Alaska

The Victor Unit of the Ivishak Formation in the Prudhoe Bay Oilfield is characterized by high net-to-gross fluvial sandstones and conglomerates. The highest permeability is found within sets of cross-strata of open-framework conglomerate (OFC). These cross-strata are preserved within unit-bar deposits and assemblages of unit-bar deposits within compound (braid)-bar deposits, and may form thief zones limiting enhanced oil recovery. We incorporate recent research that has quantified important attributes of preserved sedimentary architecture into high-resolution models. Waterflooding experiments using these models demonstrate the control that such architecture has on oil production rate, water breakthrough time, and spatial and temporal distribution of residual oil saturation. We found that when the pressure gradient is orientated perpendicular to the palaeoflow direction, the total oil production and the water breakthrough time are larger, and the remaining oil saturation is smaller, than when it is orientated parallel to palaeoflow. The pressure difference between production and injection wells does not affect sweep efficiency, although the spatial distribution of oil remaining in the reservoir critically depends on this value. Oil sweep efficiency decreases slightly with increase in the proportion of OFC cross-strata. Whether or not clusters of connected OFC span the domain does not visibly affect sweep efficiency.

Arctic Alaska's role in future United States energy independence

For decades, Arctic Alaska has provided US mainland states with plentiful oil supplies. As reserves in the Prudhoe Bay fields decrease, however, the USA has been forced to consider new options to guarantee the nation's energy security. While debates continue to rage about its reliance on foreign oil, increased prices, consumption levels, and climate change, the USA is now contemplating whether predicted new discoveries might actually allow it to become an exporter rather than importer of oil and gas in the near future. This paper considers the role Arctic Alaska might play in helping secure future US energy security and independence. It also considers what other options exist for securing the State of Alaska's own future post-Prudhoe Bay.

Production Method for Methane Hydrate Sees Scientific Success

The testing flare burns brightly during a methane hydrate production test of the Ignik Sikumi No. 1 well on the Alaskan North Slope. A production method that could unlock large reserves of methane hydrate in sand-dominated reservoirs was tested successfully from a scientific and operational standpoint in a recent research experiment on the Alaskan North Slope (ANS). The experiment was conducted by the National Energy Technology Laboratory (NETL) of the United States Department of Energy (DOE) in partnership with ConocoPhillips and Japan Oil, Gas, and Metals National Corporation. A proof-of-concept test was conducted between 15 February and 10 April at the Ignik Sikumi No. 1 well in the Prudhoe Bay field operated by ConocoPhillips. The production technique featured the injection of carbon dioxide (CO2) to exchange and release methane (CH4) from the hydrate, a method developed through laboratory collaboration between the University of Bergen in Norway and ConocoPhillips. The released gas was then produced by means of reservoir depressurization. “The test objective was to perform injection and flow-back from a single well to validate that the CO2/CH4 exchange mechanism demonstrated in laboratory tests will occur in a reservoir of natural methane hydrates,” said Ray Boswell, technology manager for gas hydrates at the NETL. It was the first field-level trial of a production method involving the exchange of CO2 with the methane molecules contained in a methane hydrate structure. “The focus of the test, including the design of the well, was on the technical feasibility of this new technology, rather than an attempt to produce gas at commercial rates,” Boswell said. CO2 Mixture Injected in Reservoir The Ignik Sikumi well test was equipped with downhole fiber-optic distributed temperature and acoustic sensing, three downhole pressure gauges, and full surface instrumentation, including high-resolution in-line gas chromatography. Over a 13-day period, a carbon dioxide/nitrogen mixture was successfully injected into the 30-ft-thick reservoir interval, saturated with methane hydrate, without loss of injectivity. This was followed by a production stage in which the pressure was held above the stability pressure of the in-situ methane hydrate. CH4 was produced during this stage, and initial data analyses indicated that CO2 exchange was achieved. Ongoing analyses of the extensive datasets acquired at the field site are under way to determine the overall efficiency of simultaneous CO2 storage/CH4 production from the reservoir. As part of the demonstration, the depressurization phase of the test extended for 30 days. The longest previous field test of depressurization to extract gas from hydrate lasted 6 days as part of a Japanese-Canadian testing program at the Mallik well in Canada’s Northwest Territories during 2007 to 2008.

Kuparuk oil field, Alaska, a mixture of Kekiktuk gas condensate and Shublik oil

Kuparuk River is a giant oil field located on the Colville High, west of Prudhoe Bay field, on the North Slope of Alaska. The Kuparuk oils have values greater than 0.5 for the aromaticity (B) parameter (= toluene/n-C7) and less than 1 for the paraffinicity (F) parameter (= n-C7/MCH). Using two parameters in isolation, one would interpret Kuparuk as the residue from repeated episodes of phase segregation and gas-cap leakage. This process, termed “evaporative fractionation,” is experimentally proven to concentrate naphthenic and aromatic hydrocarbon with low fugacity in the parent oil phase while enriching the daughter gas-condensate phase in alkanes. Reassessment of the geochemistry of the Kuparuk field within the context of a regional evaluation of North Slope petroleum systems suggests a very simple charge and filling model where the Kuparuk accumulation remained a single phase throughout its history. Oil and solution gas derived mainly from the Shublik Formation, together with gas and very light naphthenic-aromatic condensate derived from Kekiktuk Conglomerate coals shared a common migration path into Kuparuk field. This study illustrates that the B-F plot must be used with caution because factors other than evaporative fractionation, such as source input, can influence these ratios based on data from Southeast Asia, Alberta, and North Slope basins. This study also suggests that the Sohio 1 Mukluk well did not successfully result from the presence of Kuparuk thief sands, thus petroleum migration continued to the Kuparuk field.

A Tool for Liner Running and Cementing Using Electric-Line Coiled Tubing

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 120992, "The Side Exhaust Liner-Running Tool: A Tool for Liner Running and Cementing Using E-Line Coiled Tubing," by Greg Sarber, SPE, and Mark Johnson, SPE, BPXA; Bob Harris, SPE, and Carl Diller, Northern Solutions; and John Milne and Alan Holloway, Baker Hughes, originally prepared for the 2009 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, 31 March-1 April. The paper has not been peer reviewed. A new system for running and cementing liners using electric-line coiled tubing (CT) has been proved on the North Slope of Alaska. The side-exhaust liner-running tool (SELRT) provides the functionality to run and release a liner while using a liner wiper-plug (LWP) system to ensure good cement quality. A jointed-pipe liner is conveyed and cemented with the CT containing an electric umbilical. This innovative equipment has proved to be a substantial health, safety, and environment (HSE) benefit and yields savings in rig time. Introduction There has been a continuous CT-drilling (CTD) campaign on the North Slope of Alaska since 1994. This program re-enters existing vertical wells and drills horizontal sidetracks in the Prudhoe Bay, Kuparuk, Endicott, and Milne Point fields. These sidetracks typically are drilled through 4 1/2-in. production tubing without pulling the tubing or removing the existing production tree. More than 575 new sidetrack wells have been drilled in these fields since 1994. Before 2001, conventional 2 3/8-in.-outside-diameter CT (electric-line-umbilical free) was in use. When a well reached total depth (TD), the typical completion was a solid/cemented liner followed by CT-conveyed perforating guns. The liner-running tool used a ball-drop system to release the liner and a CT dart/LWP system to ensure that uncontaminated cement was placed accurately behind the liner. This system proved quite reliable and robust and accounted for the majority of wells drilled up to 2001. In 2001, a new measurement-while-drilling (MWD) bottomhole assembly (BHA) was tested. To operate, this BHA required an electrical umbilical inside the CT. This drilling system provided higher data-telemetry rates, more real-time downhole information, and better directional control using an electrical downhole orienter instead of a mechanical orienter. This system proved to be especially beneficial in managed-pressure- and underbalanced-drilling (MPD and UBD) applications. The electric orienter minimized shale damage by eliminating the pump cycles needed to operate a mechanical orienter. This new equipment provided sufficient time savings to enable a 30% increase in effective rate of penetration. Unfortunately, some of the productivity gains realized from using the electric-line CT BHA were lost when it came to completing the wells. To run and cement the liner, the CT reel containing the electric line had to be replaced with an electric-line-free reel to use the existing liner-running equipment. Reel swaps are an HSE risk when conducted in the middle of drilling operations, especially when conducted in Arctic winter conditions; the reel exchange consumed some of the time-savings benefits of using the new drilling BHA, additional operating costs were required to inventory two types of CT, and exchanging reels caused a delay from when the well reached TD until the liner was on bottom.

Optimized EOR Design for the Eileen West End Area, Greater Prudhoe Bay

Summary The Prudhoe Bay field, on the north coast of Alaska, is the largest oil field in North America. Discovered in 1968, the Prudhoe Bay field is a massive sandstone reservoir complex covering more than 200 square miles. Eileen West End (EWE) is a western extension of the Prudhoe Bay field, connected only through the aquifer. It consists of two tilted fault blocks, each with a gas cap and an oil leg with a combined oil originally in place (OOIP) of more than 750 million STB. Production began at EWE in June 1988, approximately 11 years after Prudhoe field startup. Designing an optimal development strategy for a large oil reservoir like EWE is a challenging objective, both technically and commercially. It is especially true when the reservoir is structurally complex with numerous crossing faults. EWE is also complex stratigraphically, with both continuous and discontinuous shale bodies and tightly cemented sandstone intervals. In such cases, the logical starting point is to use the analog of a successful project, such as mainfield Prudhoe Bay. EWE initially was developed in the same style as Prudhoe Bay. To accomplish this, excess produced gas from Prudhoe Bay was injected into the EWE gas caps with a hope that the reservoir would produce with effective gravity drainage in a manner similar to that of Prudhoe Bay. Conductive faults and shale barriers, however, led to unexpected early gas breakthrough. High gas/oil ratios reduced the oil production rate, leading to a reduced recovery factor from the field. A review of surveillance data, material balance studies, fluid mapping, simulation, and other analog data changed the perception that gravity drainage was an efficient recovery process at EWE. The work also showed that the aquifer influx was stronger than anticipated. As a result, gas injection was stopped in 2001, and water injection into the gas caps was started for pressure maintenance and to prevent oil from resaturating the gas cap. To mitigate the prospect of low recovery from EWE, a modified comprehensive recovery plan was developed. A pattern water-alternating-(miscible)-gas (WAG) flood was initiated in 2003. The initial WAG patterns targeted areas with large gas cap expansion and gas underruns to capture oil trapped in these gas-invaded intervals. The WAG flooding is being expanded to areas of low gas cap expansion and peripheral regions. The main features of the modified comprehensive recovery plan are: stop injection of lean gas into the gas cap; inject water into the gas cap to maintain the reservoir pressure and prevent the strong bottom aquifer from pushing oil into the gas cap; develop pattern floods to maximize volumetric sweep; and initiate a WAG flood to optimize ultimate recovery. The flood patterns are developed by converting existing producers into injectors and also by drilling infill injection wells. This paper describes the technical process used to select the major design parameters of the pattern WAG flood to optimize EWE recovery. The key parameters evaluated were slug size, injection rate, WAG ratio, and WAG sequencing. A fine-grid, fully compositional numerical simulator was used to determine the optimal design parameters. The modeling indicated that multiple WAG cycles with high voidage replacement ratio (VRR) during the gas cycle with an overall WAG ratio of 1 provided the largest cumulative oil recovery. Timing of the first gas slug within the first year after start of waterflood in addition to realignment of the injection and production wells also optimizes recovery. Surveillance of the secondary and tertiary recovery through well performance monitoring and surface and downhole data acquisition combined with classical reservoir engineering is ongoing to ensure that the EWE enhanced-oil-recovery (EOR) project remains optimized.

Well Integrity Operations at Prudhoe Bay, Alaska

Summary This paper discusses the well-integrity-management system used at the Prudhoe Bay field located in Alaska. The focus is on systems and processes implemented to manage the well operations and interventions phase of a well's life. Well integrity is a multifaceted discipline, spanning a well's life from design to abandonment. The engineering aspects of well integrity have received increasing attention in recent years as public scrutiny and resultant regulatory requirements have evolved. The issue of sustained casing pressure (SCP) on the annulus of a well has also shaped current well-integrity practices. There have been several recent applied-technology workshops focused on well integrity, demonstrating its increasing importance. However, there is notably little well-integrity-related literature in the SPE paper library (see Michel 1995; Attard 1991; Soter et al. 2003; and Bourgoyne et al. 1999 for a listing of relevant papers). The well-integrity-management system used at Prudhoe Bay has been evolving since field startup in 1977. Extensive experience has resulted in the design and management of systems to ensure safe operations; compliance with industry standards, regulatory-agency requirements, and internal company policies; and incorporating "lessons learned" from local incidents. This paper focuses on the operational and well intervention phases of a well's life and discusses evolution of the well-integrity-management system. Current operating practices are reviewed using BP's "7 Elements of Well Integrity" categorization. Finally, the data-management system used to monitor the well-integrity-system status is reviewed.

De-convoluting mixed crude oil in Prudhoe Bay Field, North Slope, Alaska

Seventy-four crude oil samples from the Barrow arch on the North Slope of Alaska were studied to assess the relative volumetric contributions from different source rocks to the giant Prudhoe Bay Field. We applied alternating least squares to concentration data (ALS-C) for 46 biomarkers in the range C 19–C 35 to de-convolute mixtures of oil generated from carbonate rich Triassic Shublik Formation and clay rich Jurassic Kingak Shale and Cretaceous Hue Shale-gamma ray zone (Hue-GRZ) source rocks. ALS-C results for 23 oil samples from the prolific Ivishak Formation reservoir of the Prudhoe Bay Field indicate approximately equal contributions from Shublik Formation and Hue-GRZ source rocks (37% each), less from the Kingak Shale (26%), and little or no contribution from other source rocks. These results differ from published interpretations that most oil in the Prudhoe Bay Field originated from the Shublik Formation source rock. With few exceptions, the relative contribution of oil from the Shublik Formation decreases, while that from the Hue-GRZ increases in reservoirs along the Barrow arch from Point Barrow in the northwest to Point Thomson in the southeast (∼250 miles or 400 km). The Shublik contribution also decreases to a lesser degree between fault blocks within the Ivishak pool from west to east across the Prudhoe Bay Field. ALS-C provides a robust means to calculate the relative amounts of two or more oil types in a mixture. Furthermore, ALS-C does not require that pure end member oils be identified prior to analysis or that laboratory mixtures of these oils be prepared to evaluate mixing. ALS-C of biomarkers reliably de-convolutes mixtures because the concentrations of compounds in mixtures vary as linear functions of the amount of each oil type. ALS of biomarker ratios (ALS-R) cannot be used to de-convolute mixtures because compound ratios vary as nonlinear functions of the amount of each oil type.

Technology Drives Deepwater GOM Winning Streak

The oil and gas industry appears to be on a winning streak in the deepwater Gulf of Mexico. When major newspapers in New York, Washington, Los Angeles, and other cities run lengthy articles focusing on an extended well test 175 miles offshore Louisiana, as they did last September about Chevron's Jack-2 well (Walker Ridge Block 758), then something is up. Likewise, something is up when BP discovers, as it did last August, 800 net ft of pay in 5,860 ft of water at Kaskida (Keathley Canyon Block 292). That opened an important new lane in the Lower Tertiary play. As industry consulting firm Wood MacKenzie later reported, 2006 was "an exceptional year for exploration in the deepwater Gulf of Mexico," with discoveries such as Pony (Green Canyon Block 468) by Hess and Great White West (Alaminos Canyon Block 856) by Total adding to the buzz. The discovery rate per well drilled in 2006 climbed to more than 40 million barrels of oil equivalent, the consulting firm noted, making it the most successful year since 1999 when BP discovered Thunder Horse. Discussing U.S. production, Cambridge Energy Research Associates labeled the Lower Tertiary play "the most significant oil trend since the discovery of the Prudhoe Bay field in 1968" and said that as much as 800,000 barrels per day—11% of U.S. production—could be flowing from this reservoir in the GOM by 2012–14. The essential driver of the success so far, and of that possibly just over the horizon, is technology that continually challenges and in so many cases finds ways to overcome steep technical obstacles that once seemed indomitable. Recent advances in seismic-acquisition techniques, for example, have brought step changes in the quality of images obtained from beneath the extensive and often thick salt canopy of the deepwater GOM, areas that not too long ago were simply avoided as virtually impossible imaging targets. Fifth-generation dynamically positioned (DP) rigs being delivered are equipped to lead drillers out to 12,000-ft waters, while synthetic mooring lines are enabling floating production facilities to cross the 8,000-ft threshold and look beyond to where the new rigs will go and the next producing floaters will follow. Innovative real-time monitoring tools are guiding drillers down some of the longest, costliest, and riskiest wellbores with the narrowest pressure-gradient windows for reaching their targets safely. And expandable pipe is enabling these drillers to meet high-risk downhole contingencies with flexible, optimized casing programs. What follows is a look at those and other technologies, with perspectives from the people who work with them and in some cases helped develop them.

Well-Integrity Operations at Prudhoe Bay, Alaska

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 102524, "Well-Integrity Operations at Prudhoe Bay, Alaska," by J. Anders, SPE, S. Rossberg, SPE, A. Dube, SPE, H. Engel, SPE, and D. Andrews, SPE, BP Exploration (Alaska) Inc., prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24-27 September. Well integrity spans the entire life of the well. The issue of sustained casing pressure (SCP) on the annulus of a well has shaped current well-integrity practices. The well-integrity-management system used at Prudhoe Bay has been evolving since field startup in 1977. Extensive experience has resulted in the design and management of systems to ensure safe operations and compliance with industry standards, regulatory-agency requirements, and internal company policies. The full-length paper details the operational and well-intervention phases of well life and discusses evolution of the well-integrity-management system. Introduction BP Exploration (Alaska) Inc. is operator of the Prudhoe Bay field, on the north slope of Alaska. There are approximately 1,330 wells in the field including 416 gas lift, 591 naturally flowing, and 323 injectors. Wells produce at rates as high as 10,000 BFPD and 100 MMcf/D. Gas-injection wells inject as much as 250 MMcf/D. Tubing sizes vary from 3 1/2 to 7 in. to accommodate the range of rates. Shut-in tubing pressure on naturally flowing wells is 2,400 psi. Produced gas contains 20% CO2, resulting in the extensive use of corrosion-resistant alloys for well tubulars. A 2,000-psi gas lift sys-tem pressure is available, resulting in as much as 2,000-psi shut-in pressure on gas lift wells and the potential for as much as 2,000 psi on well annuli. Fig. 1 illustrates a typical completion. Well integrity is defined in the NORSØK Standard D-010 (developed by the Norwegian petroleum industry) as the "Application of technical, operational, and organizational solutions to reduce risk of uncontrolled release of formation fluids throughout the life cycle of a well." This is a highly effective definition and has been adopted by BP in Alaska. Well-Integrity-Program Design Well integrity has been an ongoing effort throughout the history of Prudhoe Bay. During the design phase, all potential uses for the well should be considered, including conversion to artificial lift and injection and well-operating and -servicing requirements. Regulatory requirements and industry standards are available to guide the drilling and completion phase, but there are few guidelines for the operation, production, and workover phases. Well-integrity engineering was managed as a component of a production engineer's job responsibilities until the mid-1980s. Because well integrity can present potential conflicts with production delivery contracts, the well-integrity programs were unified under one position, the well-integrity engineer, in 2000. Industry standards, regulatory requirements, company standards, and local events are evaluated and incorporated into the Prudhoe Bay well-integrity system. These are summarized in the Alaska "Well Integrity System Policy." Each operational group, such as drilling, well operations, and the well-integrity team, has further refined these requirements into standard operating procedures (SOPs) used by engineers, operators, and technicians during performance of their job duties.