Prudhoe Bay Unit Research Articles

3-D Geological Modeling for Numerical Flow Simulation Studies of Gas Hydrate Reservoirs at the Kuparuk State 7-11-12 Pad in the Prudhoe Bay Unit on the Alaska North Slope

3-D Geological Modeling for Numerical Flow Simulation Studies of Gas Hydrate Reservoirs at the Kuparuk State 7-11-12 Pad in the Prudhoe Bay Unit on the Alaska North Slope

Characterization of the Structural–Stratigraphic and Reservoir Controls on the Occurrence of Gas Hydrates in the Eileen Gas Hydrate Trend, Alaska North Slope

One of the most studied permafrost-associated gas hydrate accumulations in Arctic Alaska is the Eileen Gas Hydrate Trend. This study provides a detailed re-examination of the Eileen Gas Hydrate Trend with a focus on the gas hydrate accumulation in the western part of the Prudhoe Bay Unit. This integrated analysis of downhole well log data and published geophysical data has provided new insight on structural, stratigraphic, and reservoir controls on the occurrence of gas hydrates in the Eileen Gas Hydrate Trend. This study revealed the relatively complex nature of the gas hydrate occurrences in the Eileen Gas Hydrate Trend, with gas hydrates present in a series of coarsening upward, laterally pervasive, mostly fine-grained sand beds exhibiting high gas hydrate saturations. Most of the gas hydrate-bearing reservoirs in the Eileen Gas Hydrate Trend are laterally segmented into distinct northwest- to southeast-trending fault blocks, occur in a combination of structural–stratigraphic traps, and are only partially hydrate filled with distinct down-dip water contacts. These findings suggest that the traditional parts of a petroleum system (i.e., reservoir, gas source, gas migration, and geologic timing of the system formation) also control the occurrence of gas hydrates in the Eileen Gas Hydrate Trend.

Geological Reservoir Characterization of a Gas Hydrate Prospect Associated with the Hydrate-01 Stratigraphic Test Well, Alaska North Slope

Geological reservoir characterization is essential for accurate evaluation of gas production performance from gas hydrate reservoirs. Particularly, the understanding of reservoir architecture and heterogeneity is of great importance since these are considered as major controls on fluid hydrodynamic and thermodynamic conditions. This study deals with well log and three-dimensional (3-D) vertical seismic profile (VSP) data acquired from the Hydrate-01 Stratigraphic Test Well within the 7-11-12 prospect, Prudhoe Bay Unit, Alaska North Slope and reports on the results of geological/geophysical evaluation related to the geological structure and reservoir properties of the 7-11-12 prospect. The structural trends of the target reservoirs, based on well correlations, are mostly consistent with the predrill prediction using the surface seismic data, and infer the existence of subseismic faults cutting through the Hydrate-01 well. The 3-D VSP data confirm a down-to-the-east normal fault that offsets the reservoir units across the Hydrate-01 well, which is concordant with the well identification of the same fault, and indicate a northeast-dipping relay structure associated with the overstepping normal faults. The edge enhancement attribute associated with discontinuity generated from the 3-D VSP data shows small faults/fractures, possibly as part of a complex fault network within the imaged normal fault system. These results reveal that the 3-D VSP data provide detailed structural information that is not present from the surface seismic data. The Hydrate-01 well log data confirm the occurrence of gas hydrate at high saturation in the two targeted sand units (B1 and D1 sands), and the comparison to a nearby pre-existing well (7-11-12 well) shows the same general trend in gas hydrate saturation as a map of seismic impedance generated from surface seismic data. The well log data also suggest that the base of gas hydrate occurrence in the Hydrate-01 and 7-11-12 wells is almost aligned at the same depth in both of the targeted B1 and D1 sand reservoirs. Especially for the D1 sand in the Hydrate-01 well, the resistivity logs show a sharp transition from high gas hydrate saturation to fully water-saturated within the D1 sand, suggesting a common gas hydrate/water contact. The results of this study will be used to construct the geological models needed for reservoir simulation studies and they can provide important insights into the geological factors that control the occurrence of gas hydrate on the Alaska North Slope.

Sensitivity and Uncertainty Analysis for Natural Gas Hydrate Production Tests in Alaska

The Japan Research and Development Consortium for Pore Filling Hydrate in Sand (MH21-S), the U.S. Department of Energy National Energy Technology Laboratory (DOE NETL), and the U.S. Geological Survey (USGS) are planning a long-term production test from gas hydrate (methane hydrate) bearing reservoirs in the Prudhoe Bay Unit in northern Alaska. Prediction of gas and water production using 2D reservoir simulation models can be very useful for decision-making for long-term production testing. However, the input parameters applied to the simulation model, which are essentially based on the most likely values obtained from the well-log interpretation and core sample measurements of the Hydrate-01 stratigraphic test well (STW), have some degrees of uncertainty. In this study, to evaluate the impact of uncertainties in the input model on the prediction results of gas and water production as well as to analyze how each input parameter contributes to the uncertainties of prediction results, we conducted uncertainty analysis and parameter sensitivity analysis based on two different methods (the regression-based method and the Sobol’ method). The sensitivity analyses reveal that the parameters regarding relative permeability (exponential of the gas relative permeability (Ng) and residual gas saturation (Sgcr)) and the intrinsic/effective permeability of the lower B1 sand significantly contribute to the uncertainties of the gas and water production predictions. In addition, the uncertainty analyses reveal that the P50 value of cumulative gas production can result in less than the reference case with the most likely values for the input parameters due to the uncertainty of Ng. These results indicate that reducing the uncertainties of gas relative permeability and residual gas saturation is essential for more reliable numerical simulations both for prediction of test well performance and subsequent history matching of field test results.

Scientific Results of the Hydrate-01 Stratigraphic Test Well Program, Western Prudhoe Bay Unit, Alaska North Slope

The United States Department of Energy, the MH21-S Research Consortium of Japan, and the United States Geological Survey are collaborating to enable gas hydrate scientific drilling and extended-duration reservoir response testing on the Alaska North Slope. To feasibly execute such a test, a location is required that is accessible from existing roads and gravel pads and that can be occupied without disrupting ongoing industry operations. A review of potential locations meeting these criteria determined the likely occurrence of gas hydrate in two fine-grained marginal-marine sands of Tertiary age in the vicinity of the inactive “Kuparuk State 7-11-12” exploration pad in the western Prudhoe Bay Unit (PBU). Existing well and seismic data for that site were insufficient to preclude the potential for free gas occurrence within the deeper (and most prospective) target sand. Therefore, with support from the PBU Working Interest Owners, Alaska Department of Natural Resources, and Petrotechnical Resources Alaska, the Hydrate-01 Stratigraphic Test Well (STW) was drilled in December 2018 to confirm the suitability of the site for future gas hydrate scientific testing. The Hydrate-01 well was successfully drilled to −3290 ft (1003 m) subsea vertical depth at a bottom hole location of approximately 900 ft (∼275 m) east of the surface location. The drilling program featured acquisition of a full suite of logging while drilling data, the collection of side-wall pressure cores, and the installation of distributed temperature and distributed acoustic sensor fiber-optic cables. The log data acquired confirmed the occurrence of gas hydrate at high saturation in two target sands. Integrated evaluation of log and sidewall core data provide petrophysical and geomechanical property information that allow for potential reservoir response to depressurization to be simulated. The deeper “B1 sand” is deemed to be most favorable for reservoir response testing as a result of confirmed gas hydrate occurrence in sediments of high intrinsic permeability, location within 100 ft (30 m) of the base of gas hydrate stability, and minimal risk for direct communication with permeable water-bearing (hydrate-free) zones. The shallower “D1 sand” provides a secondary target that is differentiated by colder in situ temperatures and the interpreted direct hydraulic communication to a lower section of non-hydrate-bearing, water-saturated sand. The Hydrate-01 log data also confirm the occurrence of at least one sub-seismic fault in close proximity to the B1 sand reservoir. To better image the distribution of the gas-hydrate-bearing reservoir sections and associated faults, a three-dimensional (3D) vertical seismic profile was conducted in early 2019 using the distributed acoustic sensors installed as part of the Hydrate-01 STW completion. Detailed two-dimensional (2D) and 3D geologic models have been constructed to enable numerical simulations to inform the planning for potential future scientific tests of reservoir response to depressurization at the site.

Planning and Operations of the Hydrate 01 Stratigraphic Test Well, Prudhoe Bay Unit, Alaska North Slope

The National Energy Technology Laboratory, the Japan Oil, Gas and Metals National Corporation, and the U.S. Geological Survey are leading an effort to conduct an extended gas hydrate production test in northern Alaska. The proposed production test required the drilling of an initial stratigraphic test well (STW) to confirm the geologic conditions of the proposed test site. This well was completed in January 2019 in cooperation with the Prudhoe Bay Unit Working Interest Owners. The Prudhoe Bay Unit Hydrate-01 STW was spudded on 10-December-2018. Downhole data acquisition was completed on 25-December-2018, and the rig was released on 01-January-2019. The Hydrate-01 STW was drilled in two sections, including the surface hole that was drilled to a depth of 2248 ft measured depth (MD) (685 m MD) and cased, and the production hole section that was drilled to a depth of 3558 ft MD (1084 m MD) and also cased. A thermally chilled mineral-oil-based mud was used in the main (production) hole section of the well to maintain wellbore stability and quality of the wellbore acquired data. The primary wellbore data were acquired using logging-while-drilling tools. A sidewall pressure core system was also deployed to gather grain size and other data needed for the design of the future production test wells. In addition to confirming the geologic conditions at the test site, the Hydrate-01 STW was designed to serve as a monitoring well during future field operations. Therefore, two sets of fiber-optic cables, each including a bundled distributed acoustic sensor (DAS) and a distributed temperature sensor (DTS), were clamped to the outside of the production casing and cemented in place. In March 2019, the project team acquired three-dimensional (3D) DAS vertical seismic profiling data in the Hydrate-01 STW. Temperature surveys were also acquired with the DTS as deployed in the Hydrate-01 STW during the completion of the well and nearly continuously since March-2019.

Numerical Simulations of Depressurization-Induced Gas Hydrate Reservoir (B1 Sand) Response at the Prudhoe Bay Unit Kuparuk 7-11-12 Pad on the Alaska North Slope

Numerical Simulations of Depressurization-Induced Gas Hydrate Reservoir (B1 Sand) Response at the Prudhoe Bay Unit Kuparuk 7-11-12 Pad on the Alaska North Slope

Optimal Wellbore Placement of a Penta-Lateral Well in the Schrader Bluff Reservoir, North Slope, Alaska

Summary A significant oil resource exists within the Schrader Bluff and stratigraphic equivalent West Sak reservoirs located on the central North Slope of Alaska. The Schrader Bluff resource is under development in the Kuparuk River Unit, Milne Point, and within the Prudhoe Bay Unit. These areas have developed reservoirs with oil viscosities up to 200 cp under waterflood and viscosity-reducing miscible gas injection. A grass roots penta-lateral gas-lifted producer was drilled and completed to unlock untapped oil in the northern portion of the Polaris S-Pad Schrader Bluff viscous oil reservoir in Prudhoe Bay, Alaska. This producer was the first multilateral well drilled in the Orion and Polaris Schrader Bluff reservoirs in ≈8 years. The team worked to unlock surface and subsurface opportunities, delivering a substantially lower cost of access than planned. Production rate from Schrader Bluff reservoir wells has a positive correlation with contacted net sandstone. Optimal well placement in each of the five laterals was key to the delivery of a successful project. A novel approach to geosteering was used to maximize net sandstone exposure, utilizing deep azimuthal resistivity and real-time user-guided multilayered inversion modeling.

Multiple physical properties of gas hydrate-bearing sediments recovered from Alaska North Slope 2018 Hydrate-01 Stratigraphic Test Well

Knowledge of the petrophysical and geomechanical properties of gas hydrate-bearing sediments is essential for predicting reservoir responses to gas production from gas hydrate reservoirs. In December 2018, Stratigraphic Test Well Hydrate-01 was drilled in the western part of the Prudhoe Bay Unit, Alaska North Slope, as part of the technical planning effort for a future long-term gas hydrate production test. Side-wall pressure coring was conducted to recover gas hydrate-bearing sediments from two reservoir sections named Unit B and Unit D. A total of 34 cores were successfully recovered during five runs of a wireline deployed pressure corer, and a total of 17 cores were preserved for advanced laboratory analysis. The samples were frozen inside the pressure core autoclave by liquid nitrogen while at high pressure before being removed and stored under liquid nitrogen at atmospheric pressure. High-resolution X-ray computed tomography showed the samples were high-quality, with undisturbed lithological layers. The Unit B and D sediments were categorized as sand or sandy silt with high hydrate saturation. Gas compositions suggest the hydrates formed with thermogenic and microbial mixed gases. Permeability tests and triaxial compression tests were conducted on the hydrate-bearing sediments. Low strengthening and high permeability at hydrate saturation Sh > 80% were observed. There was a small permeability reduction during the triaxial compression tests owing to porosity loss with increasing effective stress in the highly permeable sandy sediment after hydrate dissociation. The apparent minimal changes in porosity and permeability during the tests were due to the low-clay content and low compressibility of the quartz sand grains in the recovered cores. X-ray powder diffraction and thermal conductivity analysis also suggested a high quartz content for the analyzed samples.

Polymer-Flood Field Pilot Enhances Recovery of Heavy Oils on Alaska’s North Slope

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 195257, “First-Ever Polymer-Flood Field Pilot: A Game-Changer To Enhance the Recovery of Heavy Oils on Alaska’s North Slope,” by Abhijit Dandekar, SPE, University of Alaska Fairbanks; Baojun Bai, Missouri University of Science and Technology; and John Barnes, SPE, Hilcorp Alaska, et al., prepared for the 2019 SPE Western Regional Meeting, San Jose, California, 23–26 April. The paper has not been peer reviewed. Although polymer flooding has become a promising enhanced oil recovery (EOR) technique, no field tests have been performed to date in Alaska’s underdeveloped heavy-oil reservoirs. The overall objective of the research outlined in the complete paper is to perform a field experiment to validate the use of polymer flooding in this challenging environment. At the time of writing, no unexpected injectivity issues or polymer breakthroughs have been encountered and the two horizontal producers are showing positive response to the polymer injection, resulting in incremental increase in oil production rate. Introduction The Alaska North Slope (ANS) contains vast resources of heavy oils, primarily concentrated in the West Sak (also called Schrader Bluff) and Ugnu reservoirs. There are currently six fields producing heavy oil in Alaska: Orion, Polaris, Milne Point, Tabasco, Kuparuk, and Nikaitchuq. Tabasco is a Kuparuk River Unit (KRU) satellite, and the Ugnu formation overlies the West Sak/Schrader Bluff formation across the North Slope fields. The estimated total oil in place within these reservoirs is approximately 20 billion–25 billion bbl, with approximately two-thirds of the heavy oil lying under the KRU. At present, oils from the West Sak/Schrader Bluff formation are being developed. Despite the fact that heavy oil represents approximately a third of known ANS original oil in place (OOIP), the development pace has been slow, with cumulative production contributing only 1% of the OOIP slopewide. High development costs, significant logistical and environmental challenges, and low oil recovery resulting from conventional techniques have been the major factors for underdevelopment of these vast resources. Thermal recovery methods, such as steam injection, are impractical on the ANS because of the high cost and, more importantly, the concerns associated with thawing the nearly 2,000 ft of permafrost, which could cause massive environmental damage. From a technology standpoint, preliminary laboratory and simulation studies have indicated that polymer flooding has great potential to enhance oil recovery from the Schrader Bluff reservoirs, but these have yet to be tested because of the lack of field tests. In fact, no large-scale polymer flood of heavy-oil or other unconventional resources has occurred to date in the United States, although it has been tested and implemented in other countries such as Canada and China. Initial scoping studies suggest that successful implementation of polymer flooding could increase heavy oil recovery by 50% on the ANS. Description of the Polymer Field Pilot Area and Test Wells The project area, the Milne Point Unit (MPU), is between the Prudhoe Bay Unit (PBU) and the KRU. The MPU is approximately 30 miles northwest of the PBU and 15 miles northeast of the KRU. The current working interest owners of the MPU are the operator, 5Hilcorp Alaska (50%), and BP Alaska (50%).

Modeling recovery of natural gas from hydrate reservoirs with carbon dioxide sequestration: Validation with I\u0121nik Sikumi field data

Fundamental understanding of guest gas replacement in hydrate reservoirs is crucial for the enhanced recovery of natural gas and carbon dioxide (CO2) sequestration. To gain physical insight into this exchange process, this work aims at developing and validating a clathrate hydrate model for gas replacement. Most of the practical concerns associated with naturally occurring gas hydrates, including hydrate formation and dissociation in interstitial pore space between distributed sand particles in the presence of salt ions and in irregular nanometer-sized pores of those particles, irregularity in size of particles and shape of their pores, interphase dynamics during hydrate formation and decay, and effect of surface tension, are addressed. An online parameter identification technique is devised for automatic tuning of model parameters in the field. This model is employed to predict the laboratory-scale data for methane hydrate formation and decomposition. Subsequently, the model is validated with the field data of the Prudhoe Bay Unit on the Alaska North Slope during 2011 and 2012. In this Iġnik Sikumi field experiment, mixed CO2 (i.e., CO2 + N2) is used as a replacement agent for natural gas recovery. It is observed that the proposed formulation secures a promising performance with a maximum absolute average relative deviation (AARD) of about 2.83% for CH4, which is even lower, 0.84% for CO2 and 1.67% for N2.

Key aspects of numerical analysis of gas hydrate reservoir performance: Alaska North Slope Prudhoe Bay Unit “L-Pad” hydrate accumulation

In previous work, we reported the development of the 3D geostatistical hydrate reservoir model of "L-Pad" (Myshakin et al., 2016). In this paper, gas production sensitivity on key reservoir parameters are studied. Hydraulic communication with an aquifer and optimal depressurization strategies are subjects of investigation. Uncertainty in initial in situ permeability within 0.1–10 mD range leads to 2.0 × 108–3.5 × 108 ST m3 of gas produced over 10 years. Accounting for reservoir quality and irreducible water saturation leads to noticeable change in productivity. Sequential depressurization of hydrate-bearing units was found to be more attractive versus simultaneous depressurization.

The Iġnik Sikumi Field Experiment, Alaska North Slope: Design, Operations, and Implications for CO2–CH4 Exchange in Gas Hydrate Reservoirs

The Iġnik Sikumi Gas Hydrate Exchange Field Experiment was conducted by ConocoPhillips in partnership with the U.S. Department of Energy, the Japan Oil, Gas and Metals National Corporation, and the U.S. Geological Survey within the Prudhoe Bay Unit on the Alaska North Slope during 2011 and 2012. The primary goals of the program were to (1) determine the feasibility of gas injection into hydrate-bearing sand reservoirs and (2) observe reservoir response upon subsequent flowback in order to assess the potential for CO2 exchange for CH4 in naturally occurring gas hydrate reservoirs. Initial modeling determined that no feasible means of injection of pure CO2 was likely, given the presence of free water in the reservoir. Laboratory and numerical modeling studies indicated that the injection of a mixture of CO2 and N2 offered the best potential for gas injection and exchange. The test featured the following primary operational phases: (1) injection of a gaseous phase mixture of CO2, N2, and chemical tracers; (2...

Numerical simulations of depressurization-induced gas production from gas hydrates using 3-D heterogeneous models of L-Pad, Prudhoe Bay Unit, North Slope Alaska

Gas production potential is estimated using a three-dimensional reservoir model based on gas hydrate deposits located in the Prudhoe Bay region of the Alaska's North Slope. The model incorporates two hydrate-bearing sand units using detailed reservoir geological and structural information obtained from past and recent drilling programs. Geostatistical porosity models, conditioned to log data from 78 wells drilled in the vicinity of the Prudhoe Bay “L-Pad,” were developed, providing 3D heterogeneity in porosity, porosity-dependent hydrate saturation, and intrinsic permeability. The simulations utilize both vertical and inclined wellbores to induce depressurization of the reservoir at a constant bottom-hole pressure. The results show the superior performance of the inclined well design. Average gas production rates during the first five years were ∼6.0 × 104 ST m3/day (∼2.1 MMSCF/day) and ∼2.7 × 104 ST m3/day (∼1.0 MMSCF/day) for incline and vertical wells, respectively. After 30 years 5.3 × 108 − 5.7 × 108 ST m3 (18.6–20.2 BSCF) and 6.2 × 108 − 6.4 × 108 ST m3 (22.0–22.7 BSCF) gas were produced using the vertical and inclined well configurations, respectively. The analysis reveals that 2D reservoir models with homogeneous representations for porosity and hydrate saturation significantly underestimate production potential. The heterogeneity implemented in this work provides complex porous network and preferential pathways for mobile phase flow to a producing well. Consequently, no secondary hydrate formation around a wellbore is predicted in contrast to models that utilize uniform porosity and hydrate saturation distributions.

Coupled flow and geomechanical analysis for gas production in the Prudhoe Bay Unit L-106 well Unit C gas hydrate deposit in Alaska

We perform numerical simulation for the gas hydrate reservoir, in the vicinity of Prudhoe Bay Unit L-Pad on the North Slope (i.e., Unit C in the PBU-L 106 site), considering vertical and horizontal well production scenarios. In order to analyze coupled flow and geomechanics more rigorously we employ two-way coupling between fluid flow and geomechanics, and compare the results with those from one-way coupling used in previous studies, where two-way coupling accounts for changes in pore volume induced by geomechanics, while one-way coupling does not. We find clear differences in the variables of flow and geomechanics between one-way and two-way couplings in this field case (e.g., pressure and effective stress). Using geomechanical properties used previously for the PBU-L 106 C unit, we find that the effective stresses are within the elastic region, located away from the Mohr–Coulomb yield function for both vertical and horizontal well production scenarios. This indicates that there is little danger in geomechanical instability and failure. We also investigate vertical displacement to assess well stability, using two-way coupling. The results from the vertical well scenario show small vertical displacement, from which we anticipate that the vertical well will be stable and safe. On the other hand, the horizontal well scenario causes larger subsidence for a given simulation time because of higher production rates. Even in the case that the hydrates are completely dissociated and the aqueous phase pressure is equilibrated with the constant bottom hole pressure, the estimates of the maximum vertical displacement and strain are 73cm and 2%, respectively, which do not appear to be a danger of potential well failure. Based on the results and analyses, the horizontal well production is feasible for gas production from the hydrate layers of Unit C in the PBU-L 106 site. But the reservoir model used in this study is relatively generalized. Thus, a specific reservoir model for the site will be required for higher accuracy in the future, after we obtain accurately measured geomechanical data and failure models.

Alaskan Heavy Oil: First CHOPS at an Untapped Arctic Resource

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 133592, ’Alaskan Heavy Oil: First CHOPS at a Vast, Untapped Arctic Resource,’ by J.P. Young, SPE, W.L. Mathews, SPE, and E.J. Hulm, SPE, BP Exploration Alaska, originally prepared for the 2010 SPE Western Regional Meeting, Anaheim, California, 27-29 May. The paper has not been peer reviewed. Alaska’s North Slope is a world-class petroleum resource basin with two of the largest producing fields in North America, Prudhoe Bay and Kuparuk River unit. What is not widely known is the vast resource of heavy oil above these reservoirs. Although comparable in size to these fields, it remains untapped as a result of the complexity of producing heavy oil in an arctic environment. The keys to commercializing this heavy-oil resource are primarily technology and favorable economics. Introduction The total North Slope heavy-oil resource is defined by approximately 1,500 wells that penetrate the Ugnu sands for deeper targets and multiple high-quality 3D-seismic surveys. Resource size ranges from 18 to 27 billion bbl of oil in place, and the oil is found in multiple reservoir zones extending across the basin. Initial appraisal is focused on the 12 to 18 billion bbl within the Lower Ugnu (M-sand) reservoirs. The Ugnu structure is characterized by a normal-faulted monoclinal dip toward the northeast. The depth of the Ugnu pool varies from 4,500 ft in the east to 3,000 ft in the west. Multiple fault families are present, as indicated by 3D seismic. The faults tend to compartmentalize the Ugnu reservoirs by providing effective updip and lateral seals. Lower Ugnu oil quality improves to the east, corresponding to increased burial depth from west to east. The deeper, less-viscous oil in the east is believed to be suited to simple “cold”-production techniques that exploit solution-gas drive. The shallower, heavier oil in the west is believed to be suited to energy-intensive thermal techniques that heat the oil in situ. Reservoir-Performance Variability Excluding mechanical issues, most variation in well rates and recovery is likely to be associated with changes in key reservoir and fluid properties. The Lower Ugnu reservoir sands are highly unconsolidated, which limits the ability to acquire quality core samples and measure key reservoir parameters accurately. In addition, the sands were deposited as fluvial-deltaic channels, which are among the most heterogeneous reservoir types.

Mount Elbert Gas Hydrate Stratigraphic Test Well, Alaska North Slope: Overview of scientific and technical program

The Mount Elbert Gas Hydrate Stratigraphic Test Well was drilled within the Alaska North Slope (ANS) Milne Point Unit (MPU) from February 3 to 19, 2007. The well was conducted as part of a Cooperative Research Agreement (CRA) project co-sponsored since 2001 by BP Exploration (Alaska), Inc. (BPXA) and the U.S. Department of Energy (DOE) in collaboration with the U.S. Geological Survey (USGS) to help determine whether ANS gas hydrate can become a technically and commercially viable gas resource. Early in the effort, regional reservoir characterization and reservoir simulation modeling studies indicated that up to 0.34 trillion cubic meters (tcm; 12 trillion cubic feet, tcf) gas may be technically recoverable from 0.92 tcm (33 tcf) gas-in-place within the Eileen gas hydrate accumulation near industry infrastructure within ANS MPU, Prudhoe Bay Unit (PBU), and Kuparuk River Unit (KRU) areas. To further constrain these estimates and to enable the selection of a test site for further data acquisition, the USGS reprocessed and interpreted MPU 3D seismic data provided by BPXA to delineate 14 prospects containing significant highly-saturated gas hydrate-bearing sand reservoirs. The “Mount Elbert” site was selected to drill a stratigraphic test well to acquire a full suite of wireline log, core, and formation pressure test data. Drilling results and data interpretation confirmed pre-drill predictions and thus increased confidence in both the prospect interpretation methods and in the wider ANS gas hydrate resource estimates. The interpreted data from the Mount Elbert well provide insight into and reduce uncertainty of key gas hydrate-bearing reservoir properties, enable further refinement and validation of the numerical simulation of the production potential of both MPU and broader ANS gas hydrate resources, and help determine viability of potential field sites for future extended term production testing. Drilling and data acquisition operations demonstrated that gas hydrate scientific research programs can be safely, effectively, and efficiently conducted within ANS infrastructure. The program success resulted in a technical team recommendation to project management to drill and complete a long-term production test within the area of existing ANS infrastructure. If approved by stakeholders, this long-term test would build on prior arctic research efforts to better constrain the potential gas rates and volumes that could be produced from gas hydrate-bearing sand reservoirs.

The self-enforcing provisions of oil and gas unit operating agreements: theory and evidence

This article extends the existing theory and empirical investigation of unitization contracts. It highlights the importance of incentive-compatibility and self-enforcement and the bargaining problems faced in achieving viable, long-term contracts. We argue that only if the parties to a unitization contract have unit production shares that are the same as their cost shares will the contract be incentive compatible. Using a database of 60 unit operating agreements, we measure the industry's actual behavior against the principles of production from a common pool. Our survey of units that have only one production phase and that are relatively homogeneous reveals that such equal sharing rules are always found and they appear to encourage the parties to behave optimally. In more complex units with multiple production phases and/or separate concentrations of oil and gas (gas caps) we find deviations from the theoretical ideal. In the case of multiphase units, we find equal cost and production shares within phases, but not across phases. A preset trigger for shifting from one production phase to the next helps to maintain optimal behavior. For gas cap units, however, we generally do not find the equal sharing rule. Conflicts and rent dissipation follow as illustrated by the case of the Prudhoe Bay Unit. The article describes the desirable contract rules for avoiding moral hazard. It also shows how the effects of those rules can be replicated in difficult situations.

The Self-Enforcing Provisions of Oil and Gas Unit Operating Agreements: Theory and Evidence

This paper extends the existing theory and empirical investigation of unitization contracts. It highlights the importance of incentive-compatibility and self-enforcement and the bargaining problems faced in achieving viable, long-term contracts. We argue that only if the parties to a unitization contract have unit production shares that are the same as their cost shares will the contract be incentive compatible. Using a data base of sixty unit operating agreements, we measure the industry's actual behavior against the principles of production from a common pool. Our survey of units that have only one production phase and that are relatively homogeneous reveals that such equal sharing rules are always found and they appear to encourage the parties to behave optimally. In more complex units with multiple production phases and/or separate concentrations of oil and gas (gas caps) we find deviations from the theoretical ideal. In the case of multi-phase units, we find equal cost and production shares within phases, but not across phases. A pre-set trigger for shifting from one production phase to the next helps to maintain optimal behavior. For gas cap units, however, we generally do not find the equal sharing rule. Conflicts and rent dissipation follow as illustrated by the case of the Prudhoe Bay Unit. The paper describes the desirable contract rules for avoiding moral hazard. It also shows how the effects of those rules can be replicated in difficult situations.

Variations in Multilateral-Well Design and Execution

This article is a synopsis of paper SPE 39388, "Variations in Multilateral-Well Design and Execution in the Prudhoe Bay Unit," by Winton G. Aubert, SPE, Arco Alaska Inc., originally presented at the 1998 SPE/IADC Drilling Conference, Dallas, 3-6 March.