Assessing the Mesaverde Basin-Center Gas Play, Piceance Basin

Ken Hood and Don Yurewicz
ExxonMobil Exploration Company, Houston, Texas

Basin-center gas systems are regionally extensive, or continuous, gas accumulations situated in the central, deeper parts of basins. These systems typically lack any demonstrable relationship to structural closures or stratigraphic traps with downdip water contacts. Instead, the gas appears to have been generated in situ and trapped in low permeability reservoirs, reportedly by capillary seals. Traditional resource assessment methods that rely on estimating the number and size of undiscovered fields or pools, as delineated by downdip water contacts, cannot be easily applied to continuous gas accumulations. A basin-centered gas accumulation is, in effect, a single large “field” in which the resource density and producibility may vary both laterally and stratigraphically. This variability may leave portions of the inplace gas volumes uneconomical or unattainable. Attempting to identify the sweet spots within the play pre-drill is an important part of the evaluation process. Many named fields that produce from basin-centered gas accumulations are actually indistinctly bounded areas of better production, or areas in which development is limited by surface topography or culture.

Assessment of basin-centered gas resources requires a non-traditional approach. Ultimately an assessment based on well performance will provide the clearest indication of the recoverable resource and economic viability of the play. However, such performance-based approaches cannot be effectively utilized until the number of wells with production histories is sufficient to elucidate primary stratigraphic and lateral controls. We have utilized a staged approach that starts with volumetric assessment and allows systematic transition into performance-based assessment as data permit. Initially the play is assessed as one or a few large “tanks”. As the level of geologic understanding increases, the play is subdivided into progressively smaller lateral and stratigraphic packages to better honor the geologic variability. Ultimately the play is subdivided into a framework, or grid, of well drainage areas that provides a direct link between well performance and volumetric calculations.

Several major findings from regional studies of the Piceance Basin have been incorporated into the assessment. First, sand geometry plays a critical role in the production of gas and water within the basin. Accordingly, the stratigraphic section has been subdivided in six stratigraphic intervals (Figure 1), largely based on depositional facies and resultant sand geometry. Laterally continuous sandstones, including the amalgamated proximal braided-stream and marine shoreface, tend to have more extensive fracture development that creates a higher risk for significant water production with gas. While these sands may contain gas, high water production makes them less favorable targets and they are excluded from our most-likely assessment scenario. Second, the top of continuous gas within the basin appears to cut across stratigraphic boundaries. Although sands above this surface may contain some gas, they tend to produce large volumes of water. We have utilized several alternate approaches to best map this effective limit on the play. In our most-likely interpretation, the top of gas surface mapped from mudlog show data was used to truncate the top of the assessed interval within the Mesaverde Group (Figure 2).

Volumetric assessments of total and recoverable gas for the play were generated using a GIS-based work process. For each of the six subdivisions within the Mesaverde Group (Figure 1), maps of gross interval isopach, interval net-to-gross ratio, porosity, and formation volume factor were created as grids in Arc/GIS. Data constraints were variable, but included approximately 400 key wells from across the basin and limited 2D seismic coverage. For some analyses, maps of the gross interval isopach and net sand were truncated with the top of gas surface. Geographically, the basin was divided into 13 subregional polygons based on height of the gas column, reservoir depositional environment, structural dip (areas of high risk for water production), and formation pressure gradient. Data for several key assessment parameters, including gas saturation, gas recovery efficiency, and condensate yield, were not sufficient to vary the estimates continuously across the basin using grids. These parameters were assigned by stratigraphic interval for each subregional polygon. The largest uncertainties in assessing gas resources for the Mesaverde Group are gas saturation and recovery efficiency. Accurate determination of gas saturation is hindered by low porosity and permeability of the reservoirs, poor borehole conditions which result in poor log suites, and uncertainty in formation water salinity both across the basin and vertically within different stratigraphic units. Gas recovery efficiency is a complex function of many parameters, including matrix porosity and permeability, extent and connectivity of reservoir sands, natural fractures (orientation, dimensions, connectivity, regional and local variability), pressure compartments, and completion techniques. Completion strategies and techniques have evolved significantly over the course of Mesaverde exploration in the Piceance Basin, and continued progress will undoubtedly improve the overall recovery efficiency.

Based on the input parameters, two types of volumetric assessment results were produced. The first was a Monte Carlo simulation to estimate both the mean potential and the range of possible outcomes. For this evaluation, subregional polygons were used as analysis zones to calculate average values from the parameter grids and to evaluate the amount of dispersion. The second approach interacted the grids directly to calculate a deterministic assessment that captured the geographic variation within each subregional polygon. Deterministic results were scaled in units of gcf/well to facilitate comparison to available well performance data. Such maps are useful in optimizing exploration and development strategies within the basin by identifying areas with the greatest resource potential. For both approaches, scenario analysis was used to evaluate the sensitivity of the results to alternate interpretations, such as different top of gas surfaces, as well as including or excluding various stratigraphic assessment intervals or limiting the total drill depth. Filtering the results by drill depth can be a key factor in economic analysis.

Figure 1. Stratigraphic chart for the northern and southern Piceance Basin showing the breakout of assessment intervals by lithofacies.

Figure 2. East-west cross-section through the northern Piceance Basin showing the six major assessment intervals as well as the mapped top of gas surface.