Matthew J. Pranter

Analysis and modeling of intermediate-scale reservoir heterogeneity based on a fluvial point-bar outcrop analog, Williams Fork Formation, Piceance Basin, Colorado

This study presents results of outcrop characterization and modeling of lithologic heterogeneity within a well-exposed point bar of the Williams Fork Formation in Coal Canyon, Piceance Basin, Colorado. This deposit represents an intermediate-scale depositional element that developed from a single meandering channel within a low net-to-gross ratio fluvial system. Williams Fork outcrops are analogs to petroleum reservoirs in the Piceance Basin and elsewhere. Analysis and modeling of the point bar involved outcrop measurements and ground-based high-resolution light detection and ranging data; thus, the stratigraphic frameworks accurately represent the channel-fill architecture. Two- and three-dimensional (2-D and 3-D) outcrop models and streamline simulations compare scenarios based on different lithologies, shale drapes, observed grain-size trends, petrophysical properties, and modeling methods. For 2-D models, continuous and discontinuous shale drapes on lateral-accretion surfaces result in a 79% increase and 24% decrease in breakthrough time (BTT), respectively, compared to models without shale drapes. The discontinuous shale drapes in the 2-D and 3-D models cause a 30% and 107% decrease, respectively, in sweep efficiency because they focus fluid flow downward to the base of the point bar. For similar reasons, 2-D models based on grain size exhibit 67–267% shorter BTT and 44–57% lower sweep efficiency compared to other model scenarios. Unlike the 2-D models, the continuous shale drapes in the 3-D models cause the fluid front to spread out and contact more of the reservoir, resulting in 42–53% longer BTT and 41–52% higher sweep efficiency compared to the other models. These results provide additional insight into the significance of intermediate-scale heterogeneity of fluvial reservoirs.

Sandstone-body dimensions in a lower coastal-plain depositional setting: Lower Williams Fork Formation, Coal Canyon, Piceance Basin, Colorado

This study addresses the field-scale architecture and dimensions of fluvial deposits of the lower Williams Fork Formation through analysis of outcrops in Coal Canyon, Piceance Basin, Colorado. The lower Williams Fork Formation primarily consists of mud rock with numerous isolated, lenticular to channel-form sandstone bodies that were deposited by meandering river systems within a coastal-plain setting. Field descriptions, global positioning system traverses, and a combination of high-resolution aerial light detection and ranging data, digital orthophotography, and ground-based photomosaics were used to map and document the abundance, stratigraphic position, and dimensions of single-story and multistory channel bodies and crevasse splays. The mean thickness and apparent width of the 688 measured sandstone bodies are 12.1 ft (3.7 m) and 364.9 ft (111.2 m), respectively. Single-story sandstone bodies (N = 116) range in thickness from 3.9 to 29.9 ft (1.2 to 9.1 m) and from 44.1 to 1699.8 ft (13.4 to 518.1 m) in apparent width. Multistory sandstone bodies (N = 273) range in thickness from 5.0 to 47.1 ft (1.5 to 14.4 m) and from 53.2 to 2791.1 ft (16.2 to 850.7 m) in apparent width. Crevasse splays (N = 279) range in thickness from 0.5 to 15.0 ft (0.2 to 4.6 m) and from 40.1 to 843.3 ft (12.2 to 257.0 m) in apparent width. These data show that most sandstone bodies are smaller than the distance between wells at 10-ac spacing (660 ft [201 m]). Analyses of interwell sandstone-body connectivity suggest that even at 10-ac spacing, only half of the sandstone bodies are intersected and few are intersected by more than one well.

Scales of lateral petrophysical heterogeneity in dolomite lithofacies as determined from outcrop analogs: Implications for 3-D reservoir modeling

Petrophysical data from dolomite outcrops of the Mississippian Madison Formation at Sheep Canyon, Wyoming, exhibit three scales of lateral variability in single rock fabric units. These include a near-random component (nugget effect), a short-range structure, and a long-range cyclic trend (hole effect). The nugget effect is high and accounts for 31–39 and 48–50% of the variance in porosity and permeability, respectively. Short-range lateral variability is reflected by correlation lengths of 6.5–16 ft (2–5.5 m). Laterally, long-range periodicities are equivalent to approximately 10% of the petrophysical variance and have wavelengths of 31 and 140 ft (9.5 and 42.6 m) for porosity and permeability (55 ft [16.8 m] for log10 permeability), respectively. Cross sectional and plan-view petrophysical models and streamline simulations explore the effects of these scales of heterogeneity on fluid flow. Although short-range variability accounts for most of the petrophysical heterogeneity, the longer range trends can significantly affect fluid-flow behavior. Results indicate that breakthrough time and sweep efficiency vary depending on the magnitude of the lateral, long-range, petrophysical variability that exists in a dolomite reservoir. As the component of the long-range periodicity (hole effect) increases from approximately 0 to 25% of the total petrophysical variability, a corresponding increase in breakthrough time and sweep efficiency occurs. However, as the magnitude of the lateral, long-range, petrophysical variability increases beyond 25% of the total petrophysical variability (e.g., from 25 to 50%), a corresponding reduction in breakthrough time occurs because the spatial continuity of permeability is greater. Results indicate that heterogeneity caused by lateral petrophysical cyclicity should be incorporated into dolomite reservoir models for hole effect magnitudes that are greater than 10% of the petrophysical variance. To properly characterize and model these scales of variability in a petroleum reservoir, outcrop analogs are essential to provide accurate quantitative descriptions of lateral variability in dolomite rock fabrics.

Characterization and 3D reservoir modelling of fluvial sandstones of the Williams Fork Formation, Rulison Field, Piceance Basin, Colorado, USA

This study describes the stratigraphic characteristics and distribution of fluvial deposits of the Upper Cretaceous Williams Fork Formation in a portion of Rulison Field and addresses 3D geologic modelling of reservoir sand bodies and their associated connectivity. Fluvial deposits include isolated and stacked point-bar deposits, crevasse splays and overbank (floodplain) mudrock. Within the Williams Fork Formation, the distribution and connectivity of fluvial sandstones significantly impact reservoir productivity and ultimate recovery. The reservoir sandstones are primarily fluvial point-bar deposits interbedded with shales and coals. Because of the lenticular geometry and limited lateral extent of the reservoir sandstones (common apparent widths of ∼500–1000 ft; ∼150–300 m), relatively high well densities (e.g. 10 acre (660 ft; 200 m) spacing) are often required to deplete the reservoir. Heterogeneity of these fluvial deposits includes larger scale stratigraphic variability associated with vertical stacking patterns and structural heterogeneities associated with faults that exhibit lateral and reverse offsets. The discontinuous character of the fluvial sandstones and lack of distinct marker beds in the middle and upper parts of the Williams Fork Formation make correlation between wells tenuous, even at a 10 acre well spacing. Some intervals of thicker and amalgamated sandstones within the middle and upper Williams Fork Formation can be correlated across greater distances. To aid correlation and for 3D reservoir modelling, vertical lithology proportion curves were used to estimate stratigraphic trends and define the stratigraphic zonation within the reservoir interval. Object-based and indicator-based modelling methods have been applied to the same data and results from the models were compared. Results from the 3D modelling indicate that sandstone connectivity increases with net-to-gross ratio and, at lower net-to-gross ratios (<30%), differences exist in the cumulative volume of connected sandstone bodies between the indicator- and object-based lithology models. Therefore, the types of lithology-modelling methods used for lower net-to-gross ratio reservoir intervals are important.

Lateral periodic variations in the petrophysical and geochemical properties of dolomite

Mississippian dolowackestones contain periodic oscillations in the lateral distribution of trace-element concentrations, porosity, and permeability. Random variations at #30 cm spacing account for 50%-70% of the total variability. The remainder of the variability occurs in short- and long-range oscillatory patterns with periods of 1.2-7.6 m, which can only be resolved by high-resolution sampling of an ;150 m lateral transect. Possible origins for these patterns are: (1) inheritance from the depositional precursor, (2) for- mation by self-organizing processes during dolomitization, or (3) overprinting by late dia- genesis. These oscillatory patterns have up to now been unrecognized, and addressing their origin and meaning(s) represents a new approach to the study of dolomites. Under- standing the lateral distribution of petrophysical properties can also improve models of fluid flow in dolomite petroleum reservoirs and contaminant transport between matrix and conduits in dolomite aquifers. Further, if 30%-50% of the variability in a geochemical attribute in any bed is due to lateral periodicity, one must ask if that variability is too great to assume a spot sample will be a suitable proxy for ancient geologic processes and conditions.

Reservoir-scale characterization and multiphase fluid-flow modelling of lateral petrophysical heterogeneity within dolomite facies of the Madison Formation, Sheep Canyon and Lysite Mountain, Wyoming, USA

Carbonate reservoirs often exhibit complex pore networks and various scales of petrophysical heterogeneity associated with stratigraphic cyclicity, facies distribution and diagenesis. In addition, petrophysical variability also exists within distinct rock fabrics at the interwell scale. Data from lateral transects through dolomitized carbonates of the Mississippian Madison Formation in north and central Wyoming exhibit three scales of lateral petrophysical variability. These include a near-random component (nugget effect), short-range variability and a long-range periodic trend (hole effect) that is observed in both dolowackestone (Sheep Canyon) and dolograinstone (Lysite Mountain) facies. The dolowackestone represents outer and middle ramp mud-supported fabrics, while the dolograinstone represents amalgamated skeletal and oolitic shoals. Detailed 3D petrophysical models of the dolomite facies and 2D multiphase waterflood simulations explore the effects of this heterogeneity on reservoir performance through several model scenarios. Fingering of the injected fluid front, sweep-efficiency, breakthrough time and bottom-hole well pressures are sensitive to lateral reservoir heterogeneity and rock fabric. Models with greater short-scale continuity of petrophysical properties have higher degrees of large-scale fingering, higher sweep efficiency and shorter breakthrough times. The reservoir performance of the dolowackestone differs from the dolograinstone for those models that exhibit a specific range of short-scale heterogeneity. In general, the dolowackestone has a higher degree of both small- and large-scale fingering, lower sweep efficiency and longer breakthrough time compared with the dolograinstone. Intra-facies scale variability is significant in regard to reservoir performance and is often difficult or impossible to determine from typical subsurface datasets. Information from outcrop analogues is necessary to create conceptual 3D geological models and to begin to quantify interwell heterogeneity within dolomite reservoirs.

Fluvial architecture and connectivity of the Williams Fork Formation: use of outcrop analogues for stratigraphic characterization and reservoir modelling

Abstract This study addresses the stratigraphic architecture and connectivity of fluvial sandstones of the Williams Fork Formation through outcrop analysis, and static and dynamic modelling of equivalent reservoirs in the Piceance Basin, Colorado. The Williams Fork Formation is a succession of fluvial channel sandstones, crevasse splays, floodplain mudstones and paludal coals that were deposited by meandering- and braided-river systems within coastal- and alluvial-plain settings. Three-dimensional (3D) static and dynamic reservoir models that are constrained to both outcrop-derived and subsurface data show how static connectivity is sensitive to sandstone-body type and width, and varies with net to gross ratio. Connectivity analyses of 3D outcrop-based architectural-element models show how relatively wide sandstone bodies enhance connectivity. At Mamm Creek Field, connectivity of sandstones that are pay within the middle Williams Fork Formation is 12–18% higher than for the lower Williams Fork Formation. For highly constrained 3D object-based models of architectural elements, connectivity is only 4% higher when crevasse splays are included as reservoir-quality sandstones. Dynamic simulation results also suggest that the best history match is possible by considering only point bars and channel bars (reservoir-quality sandstones) as pay. Additional research is necessary to determine the impact of crevasse splays on reservoir connectivity.

Fault and fracture distribution within a tight-gas sandstone reservoir: Mesaverde Group, Mamm Creek Field, Piceance Basin, Colorado, USA

The distribution and orientation of faults, fracture intensity and seismic-reflection characteristics of the Mesaverde Group (Williams Fork and Iles formations) at Mamm Creek Field vary stratigraphically, and with lithology and depositional setting. For the Mesaverde Group, the occurrence of faults and natural fractures is important as they provide conduits for gas migration, and enhance the permeability and productivity of the tight-gas sandstones. The Upper Cretaceous Mesaverde Group represents fluvial, alluvial-plain, coastal-plain and shallow-marine depositional environments. Structural interpretations based on three-dimensional (3D) seismic-amplitude data, ant-track (algorithm that enhances seismic discontinuities) seismic attributes and curvature attributes are utilized jointly to understand the complex fault characteristics of the Williams Fork Formation. This study reveals that the lowermost lower Williams Fork Formation is characterized by NNW- and east–west-trending small-scale thrust and normal faults. Study suggests that the uppermost lower Williams Fork Formation, and the middle and upper Williams Fork formations, exhibit NNE- and east–west-trending arrays of fault splays that terminate upwards and do not appear to displace the upper Williams Fork Formation. In the uppermost Williams Fork Formation and Ohio Creek Member, NNE-trending discontinuities are displaced by east–west-trending events and the east–west-trending events dominate. Fracture analysis, based on borehole-image logs, together with ant-track and attenuation-related seismic attributes, illustrates the spatial variability of fracture intensity and lithological controls on fracture distribution. In general, higher fracture intensity occurs within the southern, southwestern and western portions of the field, and fracture intensity is greater within the fluvial sandstone deposits of the middle and upper Williams Fork formations. More than 90% of natural fractures occur in sandstones and siltstones. In situ stress analysis, based on induced-tensile fractures and borehole breakouts, indicates a NNW orientation of present-day maximum horizontal stress ( S H max ), an approximate 20° rotation (in a clockwise direction) in the orientation of S H max with depth and an abrupt stress shift below the Williams Fork Formation within the Rollins Sandstone Member.

Stratigraphic architecture of fluvial deposits from borehole images, spectral-gamma-ray response, and outcrop analogs, Piceance Basin, Colorado

Lithofacies, architectural-element abundance, and estimates of dune-bedform height and channel sinuosity from borehole images (BHIs) and well-exposed outcrops allow for an expanded interpretation of the fluvial stratigraphic architecture of the Upper Cretaceous Williams Fork Formation. Sedimentologic and stratigraphic data from outcrops and detailed core descriptions of the Williams Fork Formation, Piceance Basin, Colorado, were used to compare attributes of fluvial architectural elements to BHI characteristics and spectral-gamma-ray (SGR) log motifs. Results show a distinct set of criteria based on BHIs that aid in the interpretation of lithofacies and fluvial reservoir architecture. In contrast, a practical correlation does not exist between outcrop- and core-derived SGR log motifs or thorium and potassium abundances and fluvial lithofacies or architectural elements. Four electrofacies based on BHI characteristics (e.g., dip type, dip pattern, and color scheme) represent the most common fluvial lithofacies and are identified through comparison of paired, calibrated BHIs and core. Cross-bed-set thickness values from BHIs are used to calculate dune height as a proxy for flow energy. The lower and middle Williams Fork Formation represent low-energy meandering and higher energy braided systems, respectively, as evident by changes in channel sinuosity and architectural-element type. The upper Williams Fork Formation is divided into two intervals based on lithofacies, architectural elements, channel sinuosity, and net-to-gross ratio. The subdivision for the upper Williams Fork Formation represents a change from a lower energy, meandering fluvial system to a higher energy, lower sinuosity braided system as related to changes in accommodation through time.

Dual-lateral horizontal wells successfully target bypassed pay in the San Andres Formation, Vacuum field, New Mexico

This case study of the San Andres Formation in the mature Vacuum field, New Mexico, shows how seismic data can be used to target bypassed pay with horizontal wells. These dual-lateral wells were the first attempt at horizontal development in the Vacuum San Andres field and in the San Andres Formation in New Mexico. The primary reservoir facies consist of ramp crest and outer ramp dolomitized peloidal packstones, skeletal and ooid grainstones, and fusulinid packstones. Vertical facies successions form numerous high-frequency carbonate depositional cycles and cycle sets that create distinct reservoir zones. Structural blocks created by small-scale faults (25 ft [8 m] vertical displacement) and bypassed pay located in thin depositional cycles were identified with three-dimensional compressional-wave seismic amplitude and coherency volumes and well data and targeted using medium-radius horizontal wells. Horizontal wells penetrated fault blocks and depositional cycles that were not adequately drained by existing vertical wells.Production curves show a significant increase in production from the horizontal wells and no interference with production from offset vertical wells. This suggests that the faults are partially sealing.