Controls on Petroleum Phase and Water Production in the Wall Creek Resource Play, Powder River Basin, Wyoming

Abstract

The Wall Creek Member of the Frontier Formation, originally developed by vertical wells along NNW‐SSE high phi‐ k sandstone trends, has been the target of horizontal drilling for the past several years in the deepest part of the Powder River Basin. The basin is asymmetric with a gently dipping east limb and steep west flank that is only locally faulted at Wall Creek level. The sands are continuous from outcrop on the west flank into the productive basin center, but transition into mudstone updip toward the east. Oils within the Wall Creek are derived from the Niobrara, which is 250‐700’ above the top of the reservoir. Petroleum properties (phase and GOR) and water production vary within the confines of the play. Vertical wells in the highest quality reservoir trends typically produced with <10% water cut. Horizontal wells drilled into intervening lower quality reservoir areas have water cuts ranging from <10% to >80% that do not vary systematically with calculated pay thickness, PhiH, or SoPhiH. Log calculated water saturations are lowest on the east flank and basin center, but gradually decrease westward up the west flank despite the apparent lack of either a structural or stratigraphic trap in this direction. Variations of petroleum phase and GOR do not conform to a simple depth‐dependent relationship. A temperature map at the top of the Wall Creek, generated from DST temperatures, shows contours that do not parallel structural contours due to regional gradient variations. Temperature and vitrinite reflectance data were used to calibrate 1D burial history models by simultaneously solving for basal heat flow and the amount of erosion since ~40Ma. A relationship between present‐day temperature and vitrinite reflectance derived from the model results was used to convert the temperature map to maturity. Oil maturity data, early‐life GOR values, visual appearance of the oils, and gas isotope values all show clear relationships to this map, with the highest maturity fluids confined to a sub‐circular area located generally east of the basin axis. KINEX modeling of the Niobrara source verifies that the observed range of GOR values can be explained by thermal maturity variation between ~1.1 and 1.4 %Ro at the Wall Creek level. Oils are inferred to have migrated downward into the reservoir and continued maturing in‐situ so that they match present‐day reservoir maturity levels. Sequential flattening of a regional E‐W 2D seismic line across the basin shows that the area that is now the deep basin was on the west flank of a low‐relief paleo‐high in latest Cretaceous to early Tertiary time. Based on the 1D basin models, migration of oil and gas from the Niobrara source occurred in the early Tertiary, coincident with the presence of this paleo‐high. These observations suggest that petroleum in the Wall Creek was originally captured in a regional, westward‐ dipping stratigraphic trap and maintained there through mid‐Tertiary deep burial. Subsequent uplift of the west flank allowed petroleum to leak westward, being replaced by imbibed water. Since reservoir quality had already been degraded by diagenesis during deepest burimbibition curves to varying degrees. Since imbibition curves are steep relative to drainage curves, water influx has a relatively small impact on increasing Sw while having a dramatic impact on phase mobility due to partial or complete ‘snap off’ of the non‐wetting oil phase in pore throats. As a result, production behavior in the domains west of the basin axis are not well predicted based on log calculated parameters.ial, the rate of leakage was probably very slow and may be continuing today. Log‐calculated Sw values and horizontal well water cuts follow a regional pattern consistent with this model. Wells located east of the present‐day basin axis have <20% water cut. An intermediate domain of flat to gentle eastward dip is characterized by 20‐60% water cut, whereas wells on the steeper dipping west flank have water cuts >70%. Although the variation in log calculated Sw values is dominated by reservoir quality, a 20% overall Sw increase in rocks of consistent reservoir quality from east to west is also clearly evident. The observed Sw and production behavior can be understood in terms of a capillary drainage and imbibition curves. Rocks east of the basin axis, which have stayed in closure throughout basin evolution, remain on the drainage curve and produce the most water‐free. Rocks west of the basin axis that are no longer in closure have undergone partial leakage and moved down imbibition curves to varying degrees. Since imbibition curves are steep relative to drainage curves, water influx has a relatively small impact on increasing Sw while having a dramatic impact on phase mobility due to partial or complete ‘snap off’ of the non‐wetting oil phase in pore throats. As a result, production behavior in the domains west of the basin axis are not well predicted based on log calculated parameters.

AAPG Datapages/Search and Discovery Article #90349 © 2019 AAPG Hedberg Conference, The Evolution of Petroleum Systems Analysis: Changing of the Guard from Late Mature Experts to Peak Generating Staff, Houston, Texas, March 4-6, 2019