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Chapter CA Model for Determining Potential Areas of Future Oil and Gas Development, Greater Wattenberg Area, Front Range of ColoradoBy Troy Cook |
The potential for oil and gas development in the greater Wattenberg area, which lies near the Front Range between Denver and Greeley, Colorado, in the Denver Basin, is moderate to high for oil-and-gas-producing formations of Cretaceous age. The potential for development was determined by modeling existing production of oil and gas from these Cretaceous formations and evaluating where the remaining volume of hydrocarbons exceeds estimates of ultimate recovery from existing wells producing from these units. Although areas of varying potential exist for all producing formations, the likely areas of future oil and gas development would be where the potential exists for recovery of additional hydrocarbons from more than one producing formation. The recompletion of existing wells to tap into other formations for additional oil and gas production is likely where there is high potential for remaining producible hydrocarbons and especially where a significant number of wells exist. The model reveals that the Front Range project area between Denver and Greeley has a high potential for both the drilling of new wells and recompletions of existing wells. Because this is also an area of rapid and continuing urban growth, decisions regarding future land use will be improved with the understanding of where future oil and gas development could be expected in the Front Range of Colorado.
The greater Wattenberg area (GWA), named by the Colorado Oil and Gas Conservation Commission for regulatory purposes to define the prolific oil and gas producing region adjacent to the northern Front Range of Colorado (fig. 1), contains thousands of oil and gas wells producing from rocks of Cretaceous age. The western part of the GWA lies within the study area of the Front Range Infrastructure Resources Project (fig. 1) and is just north of Denver, Colo. The most prolific producing formations of Cretaceous age include the Muddy (“J”) Sandstone of the Dakota Group, the “D” Sandstone of the Graneros Shale, the Codell Sandstone Member of the Carlile Shale, the Niobrara Formation, and the Terry and Hygiene Sandstone Members of the Pierre Shale. The Cretaceous-age formations that produce in the GWA fall into both the continuous and conventional (see “Glossary of Terms” section) accumulation classifications used to assess the volume of undiscovered resources (Higley and Cox, this volume).
Based on an assumption that future oil and gas development will proceed apace of petroleum prices and decreases in regulatory well-spacing requirements, a model for determining remaining areas with potential for exploration and production was developed for the GWA. Land planners and others interested in determining land-use issues will find it important to understand where these potential areas of oil and gas development are located. Because volumetric calculations are applicable regardless of the type of accumulation involved (Craft and Hawkins, 1959), the model is considered applicable to the formations studied.
All estimated ultimate recoveries for the present study were generated from monthly production volumes contained in the 1999 PI database (PI/Dwights, 1999). These data are stored by lease for large areas of the United States and were the only oil and gas production data used in this study. Because the production database is proprietary, any well locations shown in this chapter for display purposes are from files that are available to the public (Colorado Oil and Gas Conservation Commission, 2001).
The assumptions outlined here were made prior to developing the model that was used to estimate the future petroleum-production potential in the GWA: (1) volumetric calculations could be used to approximate the initial volume of petroleum in any of the reservoirs of interest in the GWA; (2) decline curve analysis could be used to extrapolate well production into the future; (3) sufficient petroleum remains in the various reservoirs to warrant continued exploration for and development of additional resources. The last assumption was made because exploration continues in the GWA, and the rate of drilling new wells or “recompleting” existing wells is one of the highest in Colorado.
An EUR is generated by examining the historical production of a well as a function of time and quantity of production. Figure 2 shows an example of a semilog plot used to display such data, with time (commonly by either month or year) plotted on the X-axis and production volumes (oil, gas, and water) plotted on the Y-axis. The production history of a well generally follows a pattern of decline, which can be described by a hyperbolic or exponential decline equation; figure 2 is an example of hyperbolic decline and figure 3 is an example of exponential decline. A comparison of these two types of declines can be used to determine which one best represents the production decline of a given well. A decline extrapolated into the future can be terminated after a period of time has elapsed or when the production rate has dropped to a specific level.
In this study the EURs were generated using a 40-year extrapolation of production trends. The primary assumption in this type of forecast is that the well will continue to decline at the same rate as in the past. The cumulative production to date added to the 40-year forecast was used as the basis for generating EURs for all leases in the GWA.
The EURs of individual wells were separated out of multiwell leases by assuming that the first API (American Petroleum Institute, a nationwide unique numbering system for wells) number was the first production profile, the second API number was the second production profile, and so on. If it was not possible to determine when a well’s production stream had come online, the EUR for each well on that lease was calculated by dividing the total lease EUR by the number of wells. The EUR for a lease was determined in the same way an individual well EUR was determined. However, because the production stream of a lease consists of multiple wells with different production declines, a single curve to simulate the decline for the lease may not be totally representative.
To calculate the initial in-place volumes of oil and gas in the GWA, rock and reservoir characteristics such as porosity, pay-zone thickness, and water saturation are needed. For this purpose, the mean porosity for each of the intervals of interest was used and water saturations were assumed to range between 20 percent and 45 percent, depending on the formation in question (see Higley and Cox, this volume). To determine the net pay thickness, all wells within the area of interest that had only a single producing formation listed in the PI/Dwights database were identified. The thickness of the perforated interval for the producing formation of each well was then extracted, and this thickness was contoured using standard geographic information system techniques. The entire GWA was subdivided into a total of 30,900 160-acre units. For the purpose of data contouring, each 160-acre unit was evaluated for net perforated thickness and then broken into 160 one-acre subunits. The center of each one-acre subunit was assigned a value based on the surrounding contour lines. An average of these one-acre subunits was then used to estimate the net thickness of petroleum-saturated rock for each main 160-acre unit. The perforated thickness data were then used to calculate the initial in-place volumes of oil and gas for each formation. This procedure was performed for each of the producing formations in the GWA.
A computer program was written to produce a model for determining remaining potential areas for future oil and gas development in the GWA. For each of the approximately 31,000 160-acre units in the GWA, an initial pore volume containing oil, gas, and water was calculated for each stratigraphic interval. The EUR volume for any producing interval was then deducted from the initial pore volume for that stratigraphic interval in a particular 160-acre unit. The remaining volume is that which would be possible to drain by potential future wells or recompletions of existing wells. Because the location of a well inside a 160-acre unit is not used for any purpose other than just placing it in the proper 160-acre unit, it is probable that some wells could actually drain oil and gas from adjoining 160-acre units or be drained by a large EUR or close wells in nearby units. To compensate for this, the remaining oil-and-gas-filled pore volume was calculated for each of the eight surrounding 160-acre units. The pore volume of the central 160-acre unit could then drain additional oil and gas volumes from these surrounding units or contribute oil and gas to the surrounding 160-acre units.
Because the final remaining pore volume value for each 160-acre unit is relative only to a specific producing formation, it was necessary to normalize all of the different producing formations so they could be totaled for a combined analysis. This was done by using a weighted average of each 160-acre unit for each of these formations and then expressing a single value for each 160-acre unit as a percentage of potential of all four formations combined. This percentage of pore-volume potential for each 160-acre unit therefore represents a percentage of remaining potential for all four formations rather than a remaining oil and gas volume.
The remaining oil and gas pore volume of a single 160-acre unit was calculated repeatedly, and the model allowed the basic rock properties and water saturations to change with each repetition. The water saturations were varied by 20 percent from the input values, and the contoured stratigraphic thickness was allowed to vary by 10 percent. This was done to account for the fact that no single set of values could accurately represent the rock and water properties in any given 160-acre unit. The final result was the mean of all of the individual model runs. This process was repeated for each 160-acre unit in the GWA.
Before the model was run, all wells within each 160-acre unit were counted for the purpose of categorizing each 160-acre unit with respect to its recompletion and drill-down potential. Any single 160-acre unit with high potential for remaining oil and gas resources and a relatively high number of existing well bores will have a correspondingly high like- lihood that some or all of the wells being examined could be used for future production from one or more additional formations.
A summary table was then created for each 160-acre unit that contains (1) the well counts, (2) the remaining oil and gas estimate for each formation in the 160-acre unit, and (3) the weighted total potential value of all four formations. The data were then viewed on a base map of the Front Range Infrastructure Resources Project study area to determine where areas of moderate or high potential for remaining oil and gas exist within the Front Range Infrastructure Resources Project study area and where such areas coincide with urban areas.
The results from each formation were divided into low, high, and moderate groups with respect to oil and gas production potential. The first group is the geographic area of lowest potential for remaining producible oil and gas. This area either has less initial potential or the producible oil and gas will be depleted over the life span of past and current producing wells in the area. The second group has the highest potential for producible oil and gas. In these areas, new wells or the recompletion of existing wells would be necessary to remove the remaining oil and gas. The third group includes areas where further production is likely but the potential is less for substantial future development.
Some examples of these three groups are given in figures 4–10. Figure 4 shows the areas of moderate and high potential for the Muddy (“J”) and “D” sandstones in and around the GWA. Two areas considered to have the highest potential are centered around and slightly to the north of Denver International Airport (DIA) and in a larger tract south of Greeley, Colo. Figure 5 shows that the areas of moderate and high potential for the Niobrara Formation are scattered, with the main body of moderate and high potential not extending as far south as DIA but an area of moderate and high potential existing in the same vicinity as the “J” and “D” sandstones in an area south of Greeley. Figure 6 shows that areas of moderate and high potential in the Terry (“Sussex”) and Hygiene (“Shannon”) Sandstones are small, but they are located where potential also exists for the other three formations of interest. Figure 7 shows that areas of high potential in the Codell Sandstone Member exist primarily along the southern and western sides of the GWA, extending in a more northwesterly direction away from DIA and more toward the areas of highest density of wells drilled to the Terry (“Sussex”) and Hygiene (“Shannon”) Sandstones. Few areas of high potential appear to exist south of Greeley where there is high potential for “J” and “D” sandstones and the Niobrara Formation.
As mentioned previously, an important economic consideration in the ongoing development of the GWA is the availability of existing wells that were not originally targeted for what would be considered a “secondary” formation. These wells are available in the future for recompletions and drilldowns into formations other than the original producing formation and are usually less expensive to recomplete and drilldown than drilling a new well from the surface. A
well-density map of the area of interest, which shows a count of the number of existing wells in each 160-acre unit, is shown in figure 8. Well density is highest in the main body of the field, concentrated south of Greeley. This area is also where there is high potential for additional producible oil and gas from the Niobrara Formation and the “J” and “D” sandstones. The Codell Sandstone Member in this area has moderate potential as well.
Figure 9 shows areas where all formations, combined, have either moderate or high potential for production of oil and gas. The area of highest potential is in the area south of Greeley and extends for quite some distance to the east and west. Another large area of high overall potential is in the vicinity of the main concentration of the Terry and Hygiene wells. Although the Terry and Hygiene Sandstones are not completely underlain by high-potential areas of the other three formations, taken in its entirety the area has the highest potential in the GWA for future development based on the total remaining resources. Figure 9 is the best representation of where future drilling of new wells may take place, based on estimates of the remaining resources.
Figure 10 shows the areas within the GWA with the highest density of wells combined with the areas of moderate and high potential resources for all formations. This area represents the area most likely to be subject to future well recompletions and drilldowns.
The presence of multiple petroleum-producing formations in the greater Wattenberg area, including a portion of the Front Range Infrastructure Resources Project area, and calculations of estimated ultimate recovery of oil and gas indicate potential for the development of additional resources through recompletions and drilldowns, as well as the drilling of new wells in some tracts. Because rapid urban expansion is also occurring within the area designated as the GWA, a broader appreciation for the oil and gas resource potential in this region will contribute to more informed land-use planning efforts and decisionmaking.
I would like to thank Mahendra Verma for reviewing the basics of the model and helping me with some of the equations involved and Debra Higley Feldman for sharing her extensive knowledge of the geology of the area with someone who must have tested her patience.
Continuous accumulation An oil or gas accumulation that is pervasive throughout a large area, that is not significantly affected by hydrodynamic influences, and for which the chosen methodology for assessment of sizes and number of discrete accumulations is not appropriate (U.S. Geological Survey, 1995). Continuous-type accumulations lack well-defined downdip water contacts. The terms “continuous-type accumulation” and “continuous accumulation” are used interchangeably.
Conventional accumulation A discrete accumulation, commonly bounded by a downdip water contact, which is significantly affected by the bouyancy of petroleum in water (U.S. Geological Survey, 1995). This geologic definition does not involve factors such as water depth, regulatory status, or engineering techniques.
Drainage area A given geographic area, generally measured in acres, from which oil, gas, and water are withdrawn from a well. Drainage area differs from a government-mandated minimum spacing requirement that regulates the density of drilling to minimize the effects on the environment and optimize withdrawal efficiency. The drainage area can be larger or smaller than a regulated spacing requirement.
Estimated ultimate recovery (EUR) EUR is the expected total production of oil and/or gas from a given stratigraphic interval, in a given wellbore, over the life of the well. This estimate incorporates many variables such as the economics of the well, how long the casing can last within the given operating conditions, the length of production stream forecast that is used, and the historical production-decline history of the well. All of these variables are factored together and a volume is calculated, for both oil and gas, of the EUR of a particular interval in a given well (Seba, 1998).
Lease production A lease is typically a legal document giving an individual or business entity permission to conduct exploration, drilling, and production activities within a specific property. It is possible to have several wells on a given lease, depending on regulatory requirements. The oil and gas production data used for this study were obtained from the Petroleum In formation (PI) Production Database (1999), which stores oil and gas production information by lease. Because the PI database stores its production information by lease, it can be difficult to accurately determine the volume of oil and gas produced by a given well. In cases where production volumes could not be apportioned by well, an average was used as the EUR for each well.
Recompletion A recompletion typically involves a change to the producing formation of an existing well. This change can be accomplished by (1) sealing the existing perforations that were used to extract oil and gas from a formation and perforating another interval from which oil or gas can be removed, (2) perforating another formation while continuing to produce from the original one, or (3) drilling the well deeper to another prospective formation. Because they are generally less expensive than the drilling of new wells and hence are more economically viable, recompletions are common in mature petroleum-producing areas such as the GWA.
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