A Multi-Scale Approach to Characterizing Reservoir Quality of the Wolfcamp A, Texas Delaware Basin: Insight into Potential Implications Related to Landing Zones, Variable Rock Behavior and Pore Size Distributions Jacqueline Colborne*1, Stephen Sonnenberg1 1. Colorado School of Mines

Abstract A multi-scale reservoir characterization study of the oil-prone mudrock-siltstone reservoir rocks of the Wolfcamp A in the Delaware Basin aligns with industry’s interest in Pecos, Reeves and Ward counties in west Texas. This research is partitioned into three parts: 1) sub-regional reservoir characterization, 2) a pore network investigation of the identified reservoir quality facies, and 3) an investigation into the impact of microcrystalline quartz cement on reservoir quality. Seven cores (1, 370’) with variable stratigraphic interval coverage of the Wolfcamp A provided the foundation for this study. Facies analysis was based on cores, XRD, thin-section petrography and XRF analyses, overall nine mudstone and siltstone facies and four carbonate facies were identified over the study area. These facies are thinly interbedded and predominantly occur below well-log resolution.These facies have been associated with different depositional process that include: carbonate debris flow deposits, high and low-density carbonate and siliciclastic turbidites, hybrid event beds, dilute turbulent wake and hemipelagic facies. Dependent on thickness, the carbonate facies have the potential to pose significant challenges to fracture stimulation. Additional reservoir complexity is highlighted by the eight of the mudstone-siltstone facies, which have the potential to be both organic-rich reservoir quality facies (> 2 wt.%) and organic-lean facies (< 2wt.%), the result of heterogeneity both vertically within a single core and laterally between cores. A reservoir quality facies hierarchy was created to manage this variability, and was defined on two critical parameters: average TOC content and mineralogical composition and consistency. Due to the extensive heterogeneity and variability of the different depositional processes and diagenetic impact, it was a significant challenge to evaluate the pore microstructures and determine the compositional controls on pore size distribution and petrophysical properties. Nitrogen and carbon dioxide gas adsorption analyses were performed on 54 samples from six wells. Preliminary results suggest that quartz, which occurs as authigenic and detrital in the Wolfcamp A reservoir facies has a significant influence on pore size distribution and mechanical rock behavior. The extent of matrix-dispersed microcrystalline quartz cement and its potential impact on permeability with changes in effective stress and compressibility is also a research topic being explored.

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Background This research focuses on the Wolfcamp A and aligns with industry interest in locality, focusing on Pecos, Reeves and Ward counties in the Texas portion of the Delaware Basin (Figures 1, 2). Despite immense drilling activity and the resulting prolific production, the geologic complexities of the Wolfcamp succession have posed significant challenges to reservoir characterization across the Delaware Basin, as well as the ability to high-grade areas for exploration and development purposes. The feverish drilling activity has largely outpaced understanding of the various pore to basin-scale complexities of the Wolfcamp A. Reservoir characterization of the Wolfcamp A across the Delaware Basin, ultimately requires an integrated approach that details the sedimentological and reservoir quality complexities on both the temporal and lateral scales. It is critical for well performance to highlight stratigraphic intervals that are unfavorable landing zones and discern reservoir facies with compositional properties that are attractive targets.

Research Objectives The principle objective of this research is to highlight the different levels of sedimentological, stratigraphic, and reservoir quality complexities that occur in the Wolfcamp A, with a multi-scale pore to basin scale reservoir evaluation. To address the complexity at various scales in the Wolfcamp A, the sub-regional basin-scale part of the study entailed: 1) facies description, 2) tied rock properties to the defined facies to highlight a suite of reservoir quality facies, 3) assessed the impact of different depositional processes on reservoir quality, specifically the influence of carbonate debris flows and turbidites as hydraulic fracture barriers, 4) evaluated the regional distribution of facies and depositional processes to assert that the geological complexity of the Wolfcamp A requires a novel reservoir characterization approach. The prolific oil production from the Wolfcamp Formation across parts of the Delaware Basin strongly suggests that the nano- to micron scale pore network systems have enhanced storage capacity and connectivity that controls the overall significant producibility of hydrocarbons. The pore-scale investigation included: 1) Identification of the variable control of mineralogy, organic matter content, texture, diagenetic mineral phases and thermal maturity on the pore microstructure of each Wolfcamp A reservoir facies, and 2) how these controls may vary and the reservoir quality implications, and 3) to provide context for the distribution of pore sizes measured in the Wolfcamp A reservoir facies, a direct comparison to other economic oil -prone fine-grained lithologies was made.

Materials and Methods This study used a robust dataset that included: well logs, core, petrographic examination, X-ray diffraction, geochemical and source rock analyses. Facies descriptions were completed on 1,370 feet from seven cores with comparable stratigraphic coverage of the Wolfcamp A. A supplementary 367 foot Wolfcamp A core from Culberson county was used to compare the sedimentological and depositional processes in the northern Delaware Basin to the main study area. The facies determined from core were subsequently refined by 209 bulk mineralogical analyses and 168 petrographic thin-sections. A suite of measured rock properties from six wells in the main study area were assigned to the defined facies. Porosity and permeability measurements were completed on 148 samples, and Rock-Eval source rock analysis was completed on 154 samples. Geochemical proxies obtained from hand-held X-ray fluorescence were used to assess rock properties that have an impact on reservoir quality, the mode of silica and the impact of clastic input on TOC content. The data set for the pore-scale analysis included: 54 samples that were run on LPGS (Low pressure gas sorption) with N2 and CO2, to characterize the micro and mesopore size fractions (<2 nm, 2-50 nm). Cathodoluminescence was performed on 12 ultra-thin thin sections (<25 microns) to elucidate detrital from authigenic silica.

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Results and Discussion Reservoir Facies Hierarchy Nine mudrock and siltstone facies and four carbonate facies were identified in the Wolfcamp A (Figure 3). The facies often occur below well-log resolution with vertical stacking patterns that are not predictive. A hierarchal approach was used to define reservoir quality facies by two identified rock property parameters, average TOC values and mineralogical composition and consistency (Figure 7). These two parameters were identified as imposing critical controls on reservoir quality, as TOC-rich intervals may be strongly correlated to hydrocarbons in place and both TOC and mineralogy impact mechanical properties and therefore fracture stimulation (Akrad et al., 2011; Gamero and Diaz et al., 2012). From this approach, the facies of the Wolfcamp A were divided into primary, secondary and tertiary reservoir quality facies. Three primary reservoir quality facies were identified: siliceous mudstones (avg. TOC: 3.5 wt.%, n=50), silty mudstones (avg. TOC: 3.2 wt.%, n=24) and the calcareous silty mudstones (avg. TOC: 2.9 wt.%, n=24). These facies are mineralogically dominated by quartz (53-59%, n=98), display moderate clay content (26-32%) and low total carbonate contents (0-15%). The argillaceous calcareous siltstones (avg. TOC: 2.4 wt.%, n=18) is the only secondary reservoir quality facies, which displays significantly variable mineralogical composition. Increased reservoir quality and TOC content (>2.0 wt.%) occurs in the argillaceous calcareous siltstones when total carbonate content is (~<40%), and clay is (~ >20%). The four facies that were identified as tertiary reservoir quality facies include the burrowed mudstones-siltstones and the bioturbated mudstones-siltstones. These facies have the lowest averages and statistical variance of TOC values than the other reservoir facies, with variable mineralogy between the four facies. The variability in TOC and mineralogy of each of these facies is the direct result of the different depositional processes that transported the sediment into the deep basin. Basin-Scale Variability The sub-regional distribution of facies and depositional processes for each of the cored intervals is shown in (Figure 4). This map highlights the extensive variability of the Wolfcamp A that occurs in the Delaware Basin. From the facies distribution map it is clear that the increase in carbonate facies correlates to a decrease in reservoir facies. Completed in this study (not shown here) were detailed facies logs for each of the cores which highlighted the remarkable interbedded character of the Wolfcamp A. The facies were up-scaled to mudstone-siltstone and carbonate packages to assess the cored intervals at a more favorable resolution, and when combined with the reservoir quality facies logs emphasizes the expansive variability in reservoir quality and potential vertical targets. The up-scaled facies logs also accentuate the occurrence of thick carbonate intervals that would adversely impact hydraulic fracturing. Pore Network Investigation From the preliminary pore network investigation, the primary reservoir siliceous and silty mudstones, that were both interpreted to be deposited by hemipelagic settling, reveal a distinct difference in the volume of mesopores (Figure 5). Both the silty and siliceous mudstones have a unimodal pore size distribution in the mesopore range, however the silty mudstones have a higher volume of pores than the siliceous mudstones. The difference in volume of mesopores between these two facies is thought to be attributed to the predominate mode of silica. The siliceous mudstones are comprised of biosiliceous microorganisms (foraminifera, radiolarian, sponge spicules) which undergo early dissolution and then the silica reprecipitates into different types of authigenic quartz. The type of authigenic quartz that is most common in the siliceous mudstones is matrix-dispersed microcrystalline quartz cement, which is interpreted here to have precipitated into a significant volume of the mesopores (Figure 6). In contrast, the silica in the silty mudstones are largely clay-sized detrital quartz grains that may have preserved some of the primary interparticle pore space during compaction, by the rigidity of the grain. When the pore size distribution of the Wolfcamp A primary reservoir facies is compared to the pore size distributions of other commercial resource plays in North America, the Wolfcamp A has significantly greater volumes of meso-macropores (Figure 7). In contrast, the pore size distribution of other formations

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are found in the fine mesopores and micropores. The discrete differences in pore size distribution may be an indication as to why the Wolfcamp A is such a prolific producer of hydrocarbons.

Conclusions The complexity of the Wolfcamp A is detailed in the significant sedimentologic, stratigraphic and reservoir quality variability that often occur below well-log resolution. The most significant challenge to reservoir characterization of the Wolfcamp A in the Delaware Basin is the inability to take these complexities that are identified at the temporal scale (core) and laterally extrapolate. Prediction of greater reservoir quality intervals and problematic carbonate barriers and baffles requires a novel reservoir characterization approach.

The preliminary pore network investigation revealed that the primary grain assemblage is a critical control on the resulting pore sizes, as biogenic grains are highly susceptible to dissolution and will imprint the microfabric. Even with the diagenetic impact of microcrystalline quartz cement, the siliceous mudstones have greater volumes of mesopores than other commercial fine-grained lithologies. Further investigation into the other reservoir facies may reveal that higher mesopore volumes are ubiquitous in the Wolfcamp A, which has resulted in the prolific hydrocarbon production in the Delaware Basin.

Figure 1. The focused study area encompasses

Reeves, Ward and Pecos counties in the Delaware Basin. Five cores with adequate interval coverage of the Wolfcamp A (black circles) are supplemented by two cores with minor coverage (purple circles). An additional core from Culberson county (blue circle) was used throughout the study for sedimentological and reservoir quality comparisons.

Figure 2. Informal stratigraphic divisions of the

Wolfcamp Formation in the Delaware Basin as used in this study.

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Figure 3. Nine mudstone-siltstone facies and four carbonate Wolfcamp A facies were identified from core, thin-sections and bulk mineralogical analyses.

Figure 4. Distribution of facies and depositional processes for each Wolfcamp A core.

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Authigenic Quartz

Figure 5. Pore size distribution of the primary reservoir siliceous and silty mudstones using nitrogen gas adsorption.

Figure 6. Combined CL-BSE image (left). The red luminescence distinguishes detrital grains from dark authigenic

quartz. EDS image (right) is used to confirm the occurrence of these authigenic and detrital grains.

Figure 7. Comparison of N2 pore size

distributions between two Wolfcamp A facies and other commercial fine-grained lithologies.

Qu

artz

(%)

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References Akrad, O., Miskimins, J. and Prasad, M. .2011. The Effects of Fracturing Fluids on Shale Rock Mechanical Properties and Proppant Embeddment. Paper SPE 146658, p.1-12. Gamero-Diaz, H.; Miller, C.; Lewis, R. .2012. , sCore: A Classification Scheme for Organic Mudstones Based on Bulk Mineralogy. Presentation, Adapted from Oral Presentation given at AAPG 2012 Southwest Section Meeting, Ft. Worth, TX, May 19–22, 2012; American Association of Petroleum Geologists (AAPG): Tulsa, OK, 2012. p. 1-18.