Endicott Field Research Articles

Evidence That a Burning Oil Well Can Sometimes be the Best Option

An oil well blowout can burn like a rocket, which can be a good thing. Burning leaves little or no oil behind, according to a recent study (SPE 189610). The study has been used to make a case for an oil spill response plan now before regulators to develop a field with more than 100 million bbl of reserves in the Beaufort Sea. Plan approval is one of the remaining barriers facing Hilcorp, the operator in a partnership with BP to develop the Liberty field. If there is a blowout of a well on the gravel island that will be built for the project, the plan is to minimize the impact by igniting the well, and keeping it lit until a relief well can be drilled to plug it. Spill plans based on burning have been an accepted option at other fields in that area, including the nearby Endicott field that was developed by BP and sold to Hilcorp in 2014. But unlike Liberty, Endicott is regulated by the state. In the past, burning was favored because it was a better option than trying to clean up a spill in that harsh environment, which can range from difficult to impossible. Now getting a spill plan approved by federal regulators is considerably more complicated. Regulations written since the Macondo spill in the US Gulf of Mexico require the operator to demonstrate that a spill can be cleaned up and a relief well can be drilled, said Mike Dunn, operations manager for Hilcorp’s North Slope asset management team. The plan was challenged by environmental groups, whose critical descriptions of the project took the company’s 90,000 B/D worst-case discharge estimate and assumed all of the oil would be spilled. To make its case, the partners hired Boots & Coots, one of the best-known oil well firefighting firms that is now part of Halliburton. They brought in a former rocket scientist from the US space agency, NASA, to develop a method to calculate how efficiently a well fire would burn the medium-weight crude that would likely surge out of the conventional field. The Liberty spill plan is not a new one. “Hilcorp, as well as the previous operator of the leases [BP], have determined that the best remedy for a blowout is to light the well on fire,” Dunn said.

Mechanistic Modeling of Low-Salinity Waterflooding Through Coupling a Geochemical Package With a Compositional Reservoir Simulator

SummaryLow-salinity waterflooding is an emerging enhanced-oil-recovery (EOR) technique in which the salinity of the injected water is substantially reduced to improve oil recovery over conventional higher-salinity waterflooding. Although there are many low-salinity experimental results reported in the literature, publications on modeling this process are rare. Although there remains some debate regarding the mechanisms of low salinity waterflooding process (LoSal EOR®)*, the geochemical reactions that control the wetting of crude oil on the rock are likely to be central to a detailed description of the process. Because no comprehensive geochemical-based modeling has been applied in this area, it was decided to couple a state-of-the-art geochemical package, IPhreeqc (Charlton and Parkhurst 2011), developed by the US Geological Survey, with UTCOMP (Chang 1990), the compositional reservoir simulator developed by The University of Texas at Austin.A step-by-step algorithm is presented for integrating IPhreeqc with UTCOMP. Through this coupling, we are able to simulate homogeneous and heterogeneous (mineral dissolution/precipitation), irreversible, and ion-exchange reactions under nonisothermal, nonisobaric, and both local-equilibrium (away from the wellbore) and kinetic (near wellbore) conditions. Consistent with the literature, there are significant effects of water-soluble hydrocarbon components—e.g., carbon dioxide (CO2), methane (CH4), and acidic/basic components of the crude—on buffering the aqueous pH value and more generally, on the crude oil, brine, and rock reactions. Thermodynamic constraints are used to explicitly include the effect of these water-soluble hydrocarbon components. Hence, this combines the geochemical power of IPhreeqc with the important aspects of hydrocarbon flow and compositional effects to produce a robust, flexible, and accurate integrated tool capable of including the reactions needed to mechanistically model low-salinity waterflooding.Different geochemical-based approaches to modeling wettability change in sandstones (e.g., interpolation on the basis of total ionic strength and multicomponent ion exchange through surface complexation of the organometallic components) were implemented in UTCOMP-IPhreeqc, and the integrated tool is then used to match and interpret a low-salinity experiment published by Kozaki (2012) and the field trial performed by BP at the Endicott field.

Technology Focus: EOR Performance and Modeling (January 2011)

Technology Focus SPE hosted two enhanced-oil-recovery (EOR) conferences in 2010: One was the 2010 SPE Improved Oil Recovery Symposium in Tulsa and the other was the 2010 SPE EOR Conference at Oil & Gas West Asia, Muscat, Oman. Many other SPE conferences had sessions on EOR technologies. Therefore, it is not surprising that more than 350 papers were presented on the topic in the past year. These papers covered past field-application experiences and accomplishments, current strides, and future directions. As in previous years, when I selected papers to highlight EOR this year, I classified the papers into the categories of gas injection, chemical methods, thermal methods, conformance control, microbial EOR, carbonate-reservoir EOR, reservoir-problem-identification technologies, and novel EOR methods such as low-salinity waterflooding and nanoparticles for EOR. However, it was still quite difficult to select only four to highlight from so many outstanding papers. In the past few EOR features, I highlighted chemical methods, CO2 EOR and sequestration, low-salinity waterflooding, particle gel for conformance control, wettability alteration, and methods to identify reservoir channels. Even though those topics are still quite important and many new ideas and information were presented this year, I decided to give preference to topics not highlighted before and to papers that comprehensively summarize field experiences. Overall, the leading-edge EOR technologies presented in SPE meetings this past year will be applied increasingly on a global scale and will increase the oil recovery of mature oil fields significantly as the technologies mature. EOR Performance and Modeling additional reading available at OnePetro: www.onepetro.org SPE 133089 • “Rock/Fluid Characterization for Miscible-CO2 Injection: Residual-Oil Zone, Seminole Field, Permian Basin” by M.M. Honarpour, SPE, Hess Corporation, et al. SPE 129899 • “Potential for Polymer Flooding Reservoirs With Viscous Oils” by R.S. Seright, SPE, New Mexico Petroleum Recovery Research Center. See SPE Res Eval & Eng, August 2010, page 730. SPE 132487 • “Air Injection in Heavy-Oil Reservoirs—A Process Whose Time Has Come (Again)” by M.G. Ursenbach, SPE, University of Calgary, et al. See J Can Pet Technol, January 2010, page 48. SPE 129925 • “Nanoparticle-Stabilized Supercritical CO2 Foams for Potential Mobility-Control Applications” by David Espinosa, SPE, University of Texas at Austin, et al. SPE 129692 • “Demonstration of Low-Salinity EOR at Interwell Scale, Endicott Field, Alaska” by Jim Seccombe, SPE, BP plc, et al. SPE 139667 • “Tertiary Oil Recovery and CO2 Sequestration by Carbonated-Water Injection” by N.I. Kechut, SPE, Heriot-Watt University, et al. SPE 132359 • “Identifying Injector/Producer Relationships in Waterflood Using Hybrid Constrained Nonlinear Optimization” by H. Lee, University of Southern California, et al.

Use of Flow Units as a Tool for Reservoir Description: A Case Study

Summary This paper presents a method where fluid flow units are used in reservoir description. We developed the proposed method using core and well-log data from the Endicott field on the North Slope of Alaska. Sedimentary intervals of the cored wells are divided into major zones on the basis of core description information. The major zones are further subdivided into subzones to allow less variation in geologic and petrophysical properties within each subzone and more variation between the subzones. On the basis of the transmissibility, storativity, and net- to- gross-thickness data, the subzones are classified into four distinct fluid flow units by use of the statistical method of cluster analysis. We use a regression relationship established between the core and well-log data in the cored wells to estimate the permeability of the uncored wells, allowing for extension of flow units to these wells. We present stratigraphic cross sections to illustrate areal variations of the petrophysical properties in the Endicott field.

The application of 3-D depth migration to the development of an Alaskan offshore oil field

Inconsistencies in fault positioning between overlapping 3-D seismic surveys over the northwestern part of the Endicott Field highlighted lateral positioning errors of the order of 1000 ft (330 m) in the seismic images. This large uncertainty in fault positioning placed a high and often unacceptable risk on the placement of wells. To quantify and correct for the seismic positioning error, 3-D velocity models were developed for ray‐trace modeling. The lateral positioning error maps produced revealed significant variation in the mispositioning within the Endicott Field that were mainly caused by lateral variations in permafrost thickness. These maps have been used to correct the positions of mapped features and have enabled several wells to be successfully placed close to major faults. Prior to this analysis, these wells were considered too risky to place optimally. The seismic data were 3-D poststack depth migrated with the final velocity model, producing a repositioned image that was consistent with the ray‐trace predictions. Additionally, a general enhancement of data imaging improved the interpretability and enabled the remapping and subsequent successful development of the peripheral Sag Delta North accumulation.

Evolving Fluvial Style in the Kekiktuk Formation (Mississippian), Endicott Field Area, Alaska: Base Level Response to Contemporaneous Tectonism

The hydrocarbon reservoir at Endicott field, offshore from the Sagavanirktok delta in northeastern Alaska, is found in the Upper Mississippian (Visean) Kekiktuk Formation. The trap is bounded by the northwest-southeast-trending Tigvariak and Mikkelson Bay faults, and the younger east-west-trending Niakuk fault. The Kekiktuk comprises sandstones, siltstones, and mudstones with locally significant coals and conglomerates, and is subdivided into three major reservoir zones based on the relative dominance of these lithologies. Zone 1 (the lowest) comprises mudstones, siltstones, and coals with subordinate isolated sandstones, and represents deposition within a low-lying swamp plain. With very low net-to-gross ratio, this zone is considered to be effectively nonreservoir. Major movement on the Mikkelson Bay and Tigvariak faults created a half-graben with uplift to the north and east and a very significant drop in base level. This change resulted in fairly widespread deposition of zone 2, medium- to coarse-grained sandstones from sandy bed-load braided streams. However, those sandstones thin significantly to the west, away from the faults. Continuing tectonism at this time created local shifts in base level, manifest as diversion of streams, widespread abandonment, and subsidence leading to the creation of a arge lake. The lacustrine deposits are widespread, and effectively divide zone 2 into two subzones. Those subzones are mappable sheet sandstones, and constitute the best reservoir at Endicott field in terms of net-to-gross ratio, porosity/permeability, and sandstone connectivity. Base level shows evidence of rising dramatically at the end of zone 2. This rise is attributed to continuing tectonism within the basin, and is particularly associated with the east-west-trending mid-field fault system at Endicott field, as well as ongoing activity on the Tigvariak/Mikkelson Bay fault system. Thus, at the base of zone 3 (subzone 3A), in the southern and eastern parts of the field, the rocks are mudstones and widespread coals, and contain at least one unequivocally marine mudstone. These rocks are lower delta-plain interdistributary bay-fill deposits, with rare distributary channel sandstones. North and west of the mid-field fault system, the marine mudstone is absent and the facies changes significantly with the loss of dominant coal and a concomitant increase of dist ibutary channel sandstones. Reservoir properties of subzone 3A, including connectivity, are significantly different in this area. Subzone 3B is a thick accumulation of fine-grained alluvial overbank deposits within which occur rare, isolated anastomosed channel sandstones of limited connectivity. This subzone makes minimal contribution to Endicott field reserves. Subzone 3C is characterized (particularly in its upper part) by well-developed fining-upward cycles indicating mature meandering streams. The relationships between these two highest subzones of the Kekiktuk at Endicott field indicate they represent an aggradational episode initiated by tectonically induced avulsion and set against a background of rising base level. To the west, at some distance from the Tigvariak/Mikkelson Bay f ult system, zone 3 is much thinner than at Endicott field, and is dominated by mudstones and coals. This evidence emphasizes the control that contemporaneous tectonism related to those faults had on sediment (especially sandstone) distribution within the Kekiktuk Formation. Base level changes can be identified within the End_Page 1723------------------------------ Kekiktuk Formation in the North Slope subsurface by careful lithofacies analysis and an awareness of key constraining indicators, such as are revealed by palynology, paleontology, and structural geology. By analogy with shallow-marine rocks, sequence stratigraphic concepts may be extended to continental successions. However, one must approach such problems with a full awareness of the impact of tectonism on base level and basin development.

Design and Implementation of World's First Arctic Offshore Waterflood, Endicott Field, Alaska

Design and Implementation of World's First Arctic Offshore Waterflood, Endicott Field, Alaska

Reservoir Characterization and Development Strategy in a Low Net to Gross, Discontinuous Fluvial System, Endicott Field, Alaska

The upper Kekiktuk Formation of the Endicott field contains stacked, low net to gross discontinuous fluvial sands. There are a variety of facies amid slightly sinuous to meandering channels. Stratigraphic correlations utilize log profile patterns, RFT measurements (differential depletion), and surveillance data. Incorporation of depositional facies into geological maps provides the framework for reservoir simulation models. Field performance coupled with an extensive surveillance program indicates that better sand continuity exists than was previously estimated from early stochastic models. Finely gridded two-dimensional models, incorporating the depositional facies and stochastic shale distributions, were built to characterize gas and water secondary recovery processes. Two-dimensional results were scaled up to three-dimensional models to determine field development strategy. Model results have been utilized to locate production and injection wells and to optimize offtake strategy. Water injection has been initiated, and sustained high injectivity has been achieved. The evolution from stochastic sand distribution to deterministic mapping and detailed reservoir simulation is predicting substantial recovery benefits compared to early models.

Development of the Endicott Field (Kekiktuk Formation), North Slope, Alaska

Endicott field, located 2 mi offshore in the Arctic Ocean, produces approximately 100 MBPD from Mississippian Kekiktuk Formation fluvial sands. The field is the first Arctic offshore development. Currently, 65 wells have been drilled from two man-made gravel drilling and production islands. Production started in 1987, and 77 MMBO have been produced to date. Original volumes in place are estimated at 1 billion STB, 365 bcf of gas-cap gas, and 750 bcf of solution gas. The Kekiktuk Formation, deposited by a southerly flowing fluvial system in response to the Ellesmerian Orogeny, rests unconformably on Franklinian (Devonian) basement. The field is a combined structural/stratigraphic trap and is delineated by three major normal faults. Within the field, the Endicott Group sediments are truncated by the regional Lower Cretaceous unconformity (LCU). A reservoir seal is provided by the overlying conformable Itkilyariak Formation carbonates and Cretaceous shales above the LCU. Due to complex reservoir geometry, a subzone approach to reservoir development, surveillance, and management has been implemented. Structural dip combined with continuous interbedded shales and sealing intrareservoir faults divide the reservoir into six separate hydrologic subzones. Additionally, structural dip creates narrow oil corridors in each reservoir subzone. All development wells are within approximately 1,500more » ft of the updip gas cap and downdip aquifer. The high priority placed on incorporating reservoir description with surveillance data has resulted in optimal field management and minimized development risk.« less

Oil and Gas Development in Alaska in 1987

During 1987, exploration continued its decline from the 1985 high. Four exploration wells were drilled or drilling in 1987 compared to 14 in 1986. Three of these wells were in the Arctic (onshore and offshore); the fourth was in the Cook Inlet basin. Seismic crew-months were 18.6 for 1987 compared to 30.3 months for 1986. Production, mainly from the super giant Prudhoe Bay field, increased to an average of 2.06 million BOPD, making Alaska the top oil-producing state. One new field, the Lisburne pool of Prudhoe Bay field, was put into production in late 1985, and a new field, the Endicott, was placed in production in 1986. Endicott field produces the first oil from a field in the Beaufort Sea of the Arctic Ocean. As 1987 closed, prospects for the restart of Conoco's Milne Point field and the announcement by Standard Alaska Production Company that it planned to develop its Beaufort Sea Niakuk discovery indicated that development would be in the offing in 1988.

Reservoir Description of Endicott Field, Prudhoe Bay, Alaska: ABSTRACT

Located about 2 mi offshore and several miles east of Prudhoe Bay, the Endicott field contains about 1.4 billion reservoir bbl of oil and 0.5 billion reservoir bbl of gas. Hydrocarbons occur within Mississippian fluvial sandstones of the Kekiktuk formation, which unconformably overlies the Neruokpuk Formation and grades upward into the Kayak and Itkilyariak formations. Stratigraphy is subdivided into three lithofacies that, from the base upward, reflect deposition in a swamp/lacustrine/flood plain environment (zone 1), a braided stream system (zone 2), and a meandering stream system (zone 3). Sediment dispersal was from a northerly source. Endicott field structure defines a southwesterly plunging antiform that is bounded to the north, northeast, and southwest by major normal faults and is truncated to the northeast by the Lower Cretaceous Unconformity (LCU). Shales overlying the LCU and shales of the Kayak and Itkilyariak formations form the reservoir cap. Reservoir properties within the hydrocarbon column vary by zone with zones 3 and 2 typified by an average net/gross-porosity-water saturation-permeability of 37%-18%-22%-500 md and 88%-22%-13%-1,100 md, respectively. In contrast, zone 1 quality is very poor. Reservoir sands are compositionally very mature and exhibit an enhanced pore network. Diagenetic minerals include quartz along with lesser kaolinite and carbonate. Gas is present from about 9,500 ft (2,850 m) to 9,855 ft (2,958 m), oil is down to 10,180-10,200 ft (3,054-3,060 m), and tar accumulations are down to 10,400 ft (3,120 m) subsea. Average oil gravity is 23° API. Geochemical data indicate that the tar accumulations originated through a physical deasphalting process. Cenozoic imbibition resulted in water overriding tar. End_of_Article - Last_Page 656------------

Geological Setting of North Slope Oil Fields, Alaska: ABSTRACT

The North Slope is a prolific hydrocarbon province in which discoveries to date amount to some 60 billion bbl of oil in place and 50 tcf of gas in place. Reservoirs and prolific source rocks occur throughout the stratigraphic column, which consists of a lower (or Ellesmerian) megasequence of Carboniferous to Jurassic age and an upper (or Brookian) megasequence of Early Cretaceous to Recent age. Discovered oil is almost equally divided between Ellesmerian and Brookian reservoirs. Patterns of hydrocarbon generation and migration have been controlled by deposition of clastic sedimentary wedges derived from the Brooks Range orogen. In the Late Jurassic to Early Cretaceous, the main oil kitchen was located in the Western Colville trough. Clastic depocenters and associated kitchen areas migrated progressively eastward with time and are now located in the East Beaufort offshore. Important source rocks include the Jurassic Kingak and Late Triassic Shublik Formations of the Ellesmerian megasequence, and the Aptian-Cenomanian HRZ and Turonian-Paleocene Shale Wall formations of the Brookian megasequence. In the Ellesmerian megasequence, productive reservoirs are known at several stratigraphic levels, with best reservoir properties associated with secondary porosity development in subcrop beneath a mid-Hauterivian unconformity. The Kekiktuk Formation (Mississippian), oil- and gas-bearing in the Endicott field (ca. 1 billion STBOIP), is a fluvially dominated unit, locally deposited in fault-controlled basins. The Lisburne Group (Mississippian to Early Permian) contains oil in the Lisburne pool of the Prudhoe area (?2-3 billion STBOIP). The reservoir is primarily early diagenetic dolomites within a thick platform carbonate sequence. The major reservoir on the North Slope is the Early Triassic Ivishak Formation, reservoir to the Prudhoe field (22 STBOIP), the Seal Island discovery (?1 billion STBOIP), and target in the recent Mukluk well. Sands and conglomerates were deposited by a series of alluvial fan deltas shed from a nearby northern landmass. Arctic Ocean rift events culminated in mid-Hauterivian continental breakup, which generated the subcrop unconformity of the rift margin uplift. Post-unconformity sands associated with local erosion of Ellesmerian End_Page 663------------------------------ and basement strata occur in widespread sheets. These sands can be important reservoirs,such as the Kuparuk and Point Thomson formations, of late Hauterivian-Barremian age (?ca. 11 STBOIP total). Finally, within the Brookian megasequence, large volumes (?ca. 20 billion STBOIP) of relatively heavy oils are trapped in the Late Cretaceous to early Tertiary West Sak and Ugnu formations. These sands are of marine-shelf to fluvial/deltaic depositional environments, topset strata of a Laramide prograding clastic wedge. End_of_Article - Last_Page 664------------

Sedimentological Evolution of Mississippian Kekiktuk Formation, Sagavanirktok Delta Area, North Slope, Alaska: ABSTRACT

The reservoir interval in the Endicott field, located under the delta of the Sagavanirktok River east of Prudhoe Bay, is the Mississippian Kekiktuk formation. The rocks are quartzose, and lithofacies and sequence analysis of core material shows that the Kekiktuk in that area can be subdivided into three sedimentologically distinct intervals, each of which reflects a different fluviatile depositional environment. The lowermost interval (zone 1) rests directly on metamorphic basement and comprises interbedded coal, mudstones, siltstones, and fine-grained sandstones. These rocks were deposited in a very low-lying swamp plain containing local lakes and sluggish, highly sinuous streams. Zone 1 is overlain sharply by zone 2, which comprises medium to coarse-grained, multistory andstone that was deposited within an unconstrained braided river system. The braid plain contained both ephemeral and permanent lakes, and periodic gravity flows deposited coarser sediment into the latter. That sequence passes gradationally upward into zone 3, which is composed of coarse-, medium-, and fine-grained sandstones, as well as siltstones, mudstones, and coals. The lower part of zone 3 is dominated by upward-fining sandstone sequences, interpreted as channel bars deposited within a moderately sinuous fluvial system. They pass gradationally upward into other, distinct upward-fining sequences, which differ in having higher proportions of siltstone, mudstone, and coal. Those rocks were deposited in a more highly sinuous (meandering) fluvial environment. The rocks grade upward int shallow marine sediments of the Kayak/Itkilyariak formations. The vertical sequence within the Kekiktuk in this area permits an interpretation of the structural history of the basin during Kekiktuk time. End_of_Article - Last_Page 669------------