Mohabbat Ahmadi

Integrated reservoir characterization and simulation of a shallow, light-oil, low-temperature reservoir: Umiat field, National Petroleum Reserve, Alaska

Umiat field in northern Alaska is a shallow, light-oil accumulation with an estimated original oil in place of more than 1.5 billion bbl and 99 bcf associated gas. The field, discovered in 1946, was never considered viable because it is shallow, in permafrost, and far from any infrastructure. Modern drilling and production techniques now make Umiat a more attractive target if the behavior of a rock, ice, and light oil system at low pressure can be understood and simulated. The Umiat reservoir consists of shoreface and deltaic sandstones of the Cretaceous Nanushuk Formation deformed by a thrust-related anticline. Depositional environment imparts a strong vertical and horizontal permeability anisotropy to the reservoir that may be further complicated by diagenesis and open natural fractures. Experimental and theoretical studies indicate that there is a significant reduction in the relative permeability of oil in the presence of ice, with a maximum reduction when connate water is fresh and less reduction when water is saline. A representative Umiat oil sample was reconstituted by comparing the composition of a severely weathered Umiat fluid to a theoretical Umiat fluid composition derived using the Pedersen method. This sample was then used to determine fluid properties at reservoir conditions such as bubble point pressure, viscosity, and density. These geologic and engineering data were integrated into a simulation model that indicate recoveries of 12%–15% can be achieved over a 50-yr production period using cold gas injection from five well pads with a wagon-wheel configuration of multilateral wells.

Preliminary Study of the Carbon Sequestration and Enhanced Coal Bed Methane Production Potential of Subbituminous to High-Volatile Bituminous Coals of the Healy Creek Formation, Nenana Basin, Interior Alaska

Naturally fractured, unmineable coal seam reservoirs are attractive targets for geological sequestration of carbon dioxide (CO2) because of their high CO2 adsorption capacity and possible cost offsets from enhanced coal bed methane production. In this study, we have investigated the CO2 sequestration and coal bed methane (CH4) production potential of the subbituminous to high-volatile C bituminous Healy Creek Formation coals through preliminary sensitivity analyses, experimental design methods, and fluid flow simulations. The sensitivity analyses indicate that the total volumes of CO2 sequestered and CH4 produced from the Healy Creek coals are mostly sensitive to bottom-hole injection pressure, coal matrix porosity, fracture porosity, fracture permeability, coal compressibility, and coal volumetric strain. The results of the Plackett–Burman experimental design were used to further generate proxy models for probabilistic reservoir forecasts. The probabilistic estimates for the mature, subbituminous to high-volatile C bituminous Healy Creek coals in the entire Nenana Basin indicate that it is possible to sequester between 0.41 trillion cubic feet (TCF) (P10) and 0.05 TCF (P90) of CO2 while producing between 0.36 TCF (P10) and 0.05 TCF (P90) of CH4 at the end of 44-year forecast. Fluid flow scenarios show that CO2 sequestration through a primary reservoir depletion method is the most effective way to inject CO2 in the coals of the Nenana Basin. Including a horizontal well instead of the vertical well resulted in relatively high average gas production rates and subsequent total cumulative gas production. The CO2 buoyancy scenario suggests that the effect of CO2 buoyancy and the nature of caprock should be considered in identifying potential geologic sites for CO2 sequestration.

In situ stress variations associated with regional changes in tectonic setting, northeastern Brooks Range and eastern North Slope of Alaska

ABSTRACT The northeastern Brooks Range of northern Alaska is an active, north-directed fold-and-thrust belt that is advancing on the Barrow arch and the north-facing passive margin of the Arctic Basin. Density logs, leak-off tests, and mud-weight profiles from 57 wells from the northeastern North Slope were used to determine the magnitude of the present-day in situ stresses and document significant regional lateral and vertical variations in relative stress magnitude. Preliminary analysis of the in situ stress magnitudes indicates two distinct stress regimes across this region of Alaska. Areas adjacent to the eastern Barrow arch exhibit both strike-slip and normal stress regimes. This in situ stress regime is consistent with fault patterns in the subsurface and with north–south extension along the Barrow arch and the northern Alaska margin. To the south in and near the northeastern Brooks Range thrust front, in situ stress magnitudes indicate that an active thrust-fault regime is present at depths up to 6000 ft (1829 m). This is consistent with the fold-and-thrust structures in surface exposures and in the subsurface. However, at depths greater than 6000 ft (1829 m), the relative in situ stress magnitudes indicate a change to a strike-slip regime. This observation is consistent with the few earthquake focal mechanisms in the area and suggests deep north-northeast–oriented strike-slip faults may underlie the western margin of the northeastern Brooks Range.

Assessment of Alaska’s North Slope Oil Field Capacity to Sequester CO2

The capacity of 21 major fields containing more than 95% of the North Slope of Alaska’s oil were investigated for CO2 storage by injecting CO2 as an enhanced oil recovery (EOR) agent. These fields meet the criteria for the application of miscible and immiscible CO2-EOR methods and contain about 40 billion barrels of oil after primary and secondary recovery. Volumetric calculations from this study indicate that these fields have a static storage capacity of 3 billion metric tons of CO2, assuming 100% oil recovery, re-pressurizing the fields to pre-fracturing pressure and applying a 50% capacity reduction to compensate for heterogeneity and for water invasion from the underlying aquifer. A ranking produced from this study, mainly controlled by field size and fracture gradient, identifies Prudhoe, Kuparuk, and West Sak as possessing the largest storage capacities under a 20% safety factor on pressures applied during storage to avoid over-pressurization, fracturing, and gas leakage. Simulation studies were conducted using CO2 Prophet to determine the amount of oil technically recoverable and CO2 gas storage possible during this process. Fields were categorized as miscible, partially miscible, and immiscible based on the miscibility of CO2 with their oil. Seven sample fields were selected across these categories for simulation studies comparing pure CO2 and water-alternating-gas injection. Results showed that the top two fields in each category for recovery and CO2 storage were Alpine and Point McIntyre (miscible), Prudhoe and Kuparuk (partially miscible), and West Sak and Lisburne (immiscible). The study concludes that 5 billion metric tons of CO2 can be stored while recovering 14.2 billion barrels of the remaining oil.