ALBERT

Description: Terrestrial light detection and ranging (LIDAR) surveys offer potential enrichment of outcrop-based research efforts to characterize fracture networks and assess their impact on subsurface fluid flow. Here, we explore two methods to extract the three-dimensional (3-D) positions of natural fractures from a LIDAR survey collected at a roadcut through the Cretaceous Austin Chalk: (1) a manual method using the University of California, Davis, Keck Center for Active Visualization in the Earth Sciences and (2) a semiautomated method based on mean normal and Gaussian curvature surface classification. Each extraction method captures the characteristic frequencies and orientations of the primary fracture sets that we identified in the field, yet they extract secondary fracture sets with varying ability. After making assumptions regarding fracture lengths and apertures, the extracted fractures served as a basis to construct a discrete fracture network (DFN) that agrees with field observations and a priori knowledge of fracture network systems. Using this DFN, we performed flow simulations for two hypothetical scenarios: with and without secondary fracture sets. The results of these two scenarios indicate that for this particular fracture network, secondary fracture sets marginally impact ([~]10% change) the breakthrough time of water injected into an oil-filled reservoir. Our work provides a prototype workflow that links outcrop fracture observations to 3-D DFN model flow simulations using LIDAR data, an approach that offers some improvement over traditional field-based DFN constructions. In addition, the techniques we used to extract fractures may prove applicable to other outcrop studies with different research goals.

Description: We undertake a multidisciplinary investigation into the distribution of asphalt in the Anacacho Limestone in an effort to decipher the potential roles of fractures and faults on secondary hydrocarbon migration. Field relationships between fractures, faults, and asphalt are evaluated at an asphaltic limestone mine near Uvalde, Texas. Based on their distributions, geometries, and structural relationships, we infer that normal faults provided vertical flow paths through the Anacacho Limestone, whereas strata-bound fractures enhanced lateral permeability. Variograms calculated from 75 subsurface measurements indicate that the asphalt concentration is anisotropically correlated and that the longest correlation length points in the mean strike direction of fractures and faults. A globally positioned laser rangefinder is used to measure faults and stratigraphic contacts within the mine. That data are then combined with lithologic descriptions from surrounding subsurface wells to construct a three-dimensional (3-D) model of the Anacacho Limestone. When an ordinary block-kriging algorithm populates the model with asphalt concentration estimates, the high values align along a trend that connects the two largest normal fault zones at the mine. The 3-D model provides a framework to numerically simulate secondary hydrocarbon migration. We test numerous hydrocarbon migration scenarios by adjusting simulation parameters within physically realistic ranges until producing an oil saturation field that agrees with asphalt concentration estimates. Our best match simulation indicates that oil entered the Anacacho Limestone through normal faults, that regional aquifer flow impacted oil flow, and that fractures increased the horizontal permeability of the formation by an order of magnitude along their strike direction.

Description: The origin of thermogenic natural gas in the shallow stratigraphy of northeastern Pennsylvania is associated, in part, with interbedded coal identified in numerous outcrops of the Upper Devonian Catskill and Lock Haven Formations. Historically documented and newly identified locations of Upper Devonian coal stringers are shown to be widespread, both laterally across the region and vertically throughout the stratigraphic section of the Catskill and Lock Haven Formations. Coal samples exhibited considerable gas source potential with total organic carbon as high as 44.40% by weight, with a mean of 13.66% for 23 sample locations analyzed. Upper Devonian coal is thermogenically mature; calculated vitrinite reflectances range from 1.25% to 2.89%, with most samples falling within the dry-gas window. Source potential is further supported by gas shows observed while drilling through shallow, identifiable coal horizons, which are at times located within fresh groundwater aquifers. Thermogenic gas detected in area water wells during predrill baseline sampling is determined not only to be naturally occurring, but also common in the region.

Description: In this study, we develop a model discrete fracture network (DFN) for the unconventional, naturally fractured Tensleep Sandstone oil reservoir at Teapot Dome, Wyoming. Reservoir characterization is based on three-dimensional (3D) seismic data, fracture image logs from Teapot Dome, and field observations of the Tensleep exposure in the Alcova anticline and Fremont Canyon areas. Image logs reveal that the dominant reservoir fracture set trends parallel to the present-day maximum horizontal compressive stress ( $${S}_{\mathrm{Hmax}}$$ ) inferred from drilling induced fractures. Analog field studies of the Alcova anticline and Fremont Canyon suggest fracture heights and lengths are power-law distributed, while the fracture spacing distribution is best described as log-normal. Image-log–derived fracture apertures are also log-normally distributed. These properties are incorporated into a model DFN. We assume subseismic folds, faults, and fracture zones control fracture intensity distribution and use composite 3D seismic attributes to locate subtle changes in seismic response interpreted to result from subseismic structure. Directional curvature defines aperture-opening strain normal to the dominant reservoir fracture set. Seismic attributes are scaled and combined to control fracture intensity variations in the model. Grid-cell porosity and permeability distributions derived from the DFN suggest the presence of northeast–southwest-trending reservoir compartments. We suggest that enhanced oil recovery operations may be optimized using lateral $${\mathrm{CO}}_{2}$$ injection and production wells oriented along interpreted compartment boundaries at high angles to $${S}_{\mathrm{Hmax}}$$ . This combination of $${\mathrm{CO}}_{2}$$ injection and production laterals could help maximize $${\mathrm{CO}}_{2}$$ storage and hydrocarbon recovery in depleted reservoirs and in down-dip residual oil zones.

Description: Changes in elemental chemistry have been used to define stratigraphic correlations between wellbores in petroleum basins. Few publications, however, relate defined chemical stratigraphy to physical correlations, and none have been found that do so in fluvial systems. Here, chemostratigraphy is applied to Permian fluvial sediments within the Beaufort Group of the Karoo Basin in South Africa, and a correlation between three logged sections is defined. This correlation is tested against physically determined chronostratigraphic correlations achieved using Heli-LIDAR data to provide a high-resolution correlation between two sections 7 km (4.4 mi) apart, and mapping of strata using Google Earth to produce a correlation between sections 25.5 km (15.8 mi) apart. The chemostratigraphic characterization that is defined using data from fine-grained lithologies resulted in the recognition of eight chemostratigraphic packages, with thicknesses between 50 and 250 m (164 and 820 ft) over a stratigraphic interval of approximately 900 m (2953 ft). Two distinctive changes in geochemical composition of the coarser lithologies (fluvial channel belts) were seen over this interval. In the two sections that are 7 km (4.4 mi) apart, higher resolution subdivision of chemostratigraphic packages was achieved to produce four correlative geochemical units (30–60 m [98–197 ft] in thickness) that provide a high-resolution correlation. The chemostratigraphic and chronostratigraphic correlations are in close agreement in both the 7-km- (4.4-mi) and the 25.5-km- (15.8 mi) spaced sections. The thickness of the study interval and spacing of sections is analogous to published chemostratigraphy studies on subsurface sequences; thereby, ground truthing the use of chemostratigraphy for correlation in subsurface fluvial systems that are, to some degree, analogous to the Beaufort Group sediments of this paper.

Description: This study assesses the feasibility of using offshore freshwater for improved oil recovery in passive-margin marine environments. Low-salinity waterflooding (〈5) has recently been shown, on average, to improve oil recovery by 14%. Hydrogeologists estimate that up to 3 x 10 5 km 3 (1.89 x 10 11 bbl) of fresh (〈1) water are sequestered in shallow (〈500 m [1640 ft] depth), permeable, poorly lithified sand, sandstone, and carbonate aquifers along passive margins, within 100 km (60 mi) of the present-day coastline in ocean-water depths up to approximately 50 m (164 ft). The offshore distribution of fresh–brackish water is analyzed for five vertical cross sections from offshore Australia, Suriname, Indonesia, and the United States. The distribution of offshore freshwater is compared with offshore platform locations in three oil-producing marine basins, including the North Sea, the Gulf of Mexico, and the Niger Delta. The continental-shelf cross sections host between 0.8 and 8.6 km 3 of fresh–brackish water (〈5) per kilometer of shoreline (8 x 10 9 to 8.7 x 10 10 bbl/mi of shoreline), most within 20 to 100 km (12 to 60 mi) from the coast in water depths of 10 to 50 m (33 to 164 ft). Because the majority of the offshore oil platforms are located less than 100 km (60 mi) from the shore, these resources could be used for low-salinity recovery. Cross sectional aquifer models of offshore fresh–brackish production indicate that a single, 1000-m (3280-ft)-long horizontal well could produce 19,200 m 3 /day (120,764 bbl/day) from a relatively permeable aquifer (10 –11 to 10 –12 m 2 [10,000 to 1000 md]) overlain by a moderately tight (~10 –15 m 2 [1 md]), confining unit for the typical life span of a well (30 yr).