The Sussex-Shannon Sandstones AU (about 6.6 million acres) covers most of the central part of the PRB, and its north-south outline is based on the distribution of reservoirs
in the Sussex and Shannon Sandstone Members of the Cody Shale that are currently producing and have potential for future discoveries. Sussex production is located in the eastern and southwestern parts of the AU, whereas Shannon production is in the west-central part. The Sussex and Shannon Sandstone Members are combined in this AU because they have similar reservoir characteristics and production styles and histories.
The Sussex Sandstone Member has been informally subdivided into three units (Anderman, 1976), a lower B sand,
a middle marine shale, and an upper A sand; both the A and B sands are productive. The Shannon Sandstone Member is one unit consisting of a lower silt unit overlain by interbed- ded sandstones that are commonly truncated at the top. The reservoirs are northwest-southeast-trending linear sandstone bodies, tens of miles long, 2–3 miles wide, and tens of feet thick; however, the sandstones thin to the north and east from current production. Sussex production tends to cluster in two areas, one along the House Creek–Porcupine field trend and the other farther west along the Spearhead Ranch–Scott field trend (fig. 32). Shannon production tends to cluster in one trend, including the Hartzog Draw, Pine Tree, and Jepson fields (fig. 33). Most of the Shannon production lies west of the main area of Sussex production to the north but follows along trend of the Sussex to the south.
216 MMBO and 98 BCFG from approximately 1,200 producing wells in 17 oil fields. Only associated gas is produced, with no designated gas fields. In total, more than 5,000 wells have penetrated these sandstone units in this AU (IHS Energy Group, 2006), which includes 3,500 or more new field wildcats (NRG Associates, 2006).
Most oil production from Sussex and Shannon reservoirs is from one field size class, which is in the range of 64 to
128 MMBO, with a total volume of 120 MMBO. Smaller
field size classes produce the remaining 96 MMBO (NRG Associates, 2006). Oil volumes compared to accumulation size classes follow a power law distribution.
Since the early discovery of Sussex and Shannon produc- tion in the late 1960s to the present, production depths from new field discoveries averaged 9,000 ft and ranged from about 7,000 to 10,200 ft. During this period, there has been a general trend toward drilling to greater depths to reach the reservoirs (NRG Associates, 2006). Oil gravity ranges between 30°
and 45° API with a mean of 35°. GOR ranges from less than 200 cfg/bo to more than 2,500 cfg/bo with a mean of
Input values for the Assessment Data Form to assess this AU are shown in Appendix E. Estimated numbers of undis- covered oil accumulations are a minimum of 1, a maximum
of 10, and a mode of 3. There have been 17 new oil field discoveries, and although there has not been a new field dis- covery (above the minimum size) since 1994 (NRG Associ- ates, 2006), it is likely that at least 1 new oil field above the minimum of 0.5 MMBO will be discovered. The maximum estimate of 10 undiscovered fields is a reflection of some areas with few wells that could have tested the Sussex and Shannon in combination stratigraphic traps. Growth in oil reservoirs will be mostly from infield drilling and field extensions. New fields and field growth may be in deeper parts of the basin, but also possibly in shallower parts. The highest potential for new field discoveries is believed to be in exploring for porous and permeable sandstone in overpressured compartments.
Estimated sizes of undiscovered oil accumulations include a minimum of 0.5 MMBO, a median of 1.5 MMBO, and a maximum of 12 MMBO. The default minimum size of 0.5 MMBO reflects that there will be the discovery of one field greater than the minimum size but that most fields will be small. A median size of 1.5 MMBO was used, which is an average volume for field sizes for the most recent discoveries. A maximum size of 12 MMBO reflects some possible upside potential of the AU, but there is much doubt that a large vol- ume field will be discovered.
There have been no new gas fields discovered in this AU, and the probability of new gas fields being discovered is low because gas generation potential in Niobrara source rocks is limited. Therefore, the number of undiscovered gas accumu- lations was estimated to be 0. We estimate that most of the assessed gas will be from associated gas production.
Mean estimates of undiscovered resources for the Sussex- Shannon Sandstones AU are 8.7 MMBO, 8.1 BCFG, and
0.65 MMBNGL (table 1). Table 1 also shows a resource breakdown into the F95, F50, and F5 fractiles.
Mowry Continuous Oil AU (50330261)
The methods used to assess a continuous type play apply a cell-based grid that assigns a probability of ultimate gas recovery in each cell. The size of each cell is based on geologic controls, extent of drainage area, and the production history of analog fields.
Estimated ultimate recovery (EUR) plots for the
Mowry Continuous AU were developed from modeled production decline curves; the production data were taken from Integrated Exploration Systems (2002). Cumulative probability production curves were generated to determine the total possible recovery per cell for untested cells. Data were used from the Upper Cretaceous Mowry Shale producing fields with vertical wells in the PRB and from Devonian- Mississippian Bakken Shale (upper and lower members) fields in the Williston Basin in North Dakota with vertical wells. The cell size applied had a median value of 0.25 MMBO, a minimum value of 0.02 MMBO, and a maximum value of 0.35 MMBO. Production from several fields in the PRB that produce from the Mowry were used in the probability plots including Maysdorf, Krejci, Lonetree Creek, Breen, Am-Kirk, Big Hand, Dillinger Ranch East, and Lightning Creek fields (Wyoming Oil and Gas Conservation Commission, 2003).
The Mowry Continuous Oil AU was characterized as a continuous reservoir with lateral limits confined to geologic sweet spots identified by the location of lineaments and faults (fig. 26). An upper limit of 8,000 ft corresponds to the upper boundary of overpressuring caused by hydrocarbon genera- tion (Surdam and others, 1994). There may have been some migration in the Mowry at depths less than 8,000 ft, but in that
case the reservoir is probably normally pressured to under- pressured, and hydrocarbon extraction may not have occurred. There is no known lower depth limit, but it could be as much as 15,000 ft.
Thousands of wells have been drilled through the Mowry Shale, but only a few have been drill-stem or production tested. The formation commonly has hydrocarbon shows but is commonly considered a secondary option for completion. Because fractured shale reservoirs require special completion techniques that are being improved, the Mowry as a primary objective will probably be more successful than in the past; hence, its past history may not reflect future upside potential.
Of the 6.3 million acres in the AU, 3.2 million acres,
or 50.3 percent, are within zones of high potential or sweet spots. Despite uncertainties in the mapping of lineament sand interpreting the structural forms, the minimum, maximum, and median percentages of untested assessment areas that have
the potential for additions to reserves were calculated (above 0.02 MBO per well minimum cutoff). The minimum value is 8 percent, maximum value is 45 percent, and the median value is 25 percent (see Appendix H). Minimum value was calcu- lated on the basis of the assumption that only 10 percent of the sweet spot area would be productive and have a 90-percent success ratio—that is, the sweet spots would be confined to a small area, but the area would have a high probability of suc- cess. The maximum value was based on similar assumptions, but reversed—that is, 90 percent of sweet spots would be productive, but with only a 10-percent probability of success. The median value was calculated with a 50-percent sweet spot productive area and a 50-percent probability of success. The values were also based on a 270-acre median cell size. Mean estimate of undiscovered resources for the Mowry AU is 198 MMBO, 198 BCFG, and 11.9 MMBNGL (table 1).
Mesaverde-Lewis Sandstones AU (50330303)
The Mesaverde-Lewis Sandstones AU (about 6.1 million acres) covers most of the central part of the PRB, and its north south outline is based on the distribution of Mesaverde-Lewis Sandstone reservoirs that are currently producing and have the potential for future production. Reservoirs include the Park- man Sandstone and the Teapot Sandstone Members of the Mesaverde Formation and the Teckla Sandstone Member of the Lewis Shale (fig. 27); they are combined in a single AU because they have similar reservoir characteristics, produc- tion style and type, and depositional history. Production of the Teckla and Teapot sandstones is limited to the southern part
of the basin, whereas Parkman production is distributed in the southern and central parts.
In general, most Mesaverde and Lewis fields produce modest volumes of oil from several multipay fields, although a few fields produce large volumes of oil (there are no desig- nated gas fields; NRG Associates, 2006). For example, (1)
the Parkman produces large quantities of oil from the Empire, Dead Horse, and Scott fields; (2) the Teapot has production from Flat Top, Kaye, Mikes Draw, and Well Draw fields; and (3) the Teckla has excellent production from Poison Draw field. Some wells have good initial production but have steep declines. The modest production from these reservoirs is indicative of their high clay content and low permeability. A few wells have low initial production rates with flat declines, although it is unclear if these wells are pressure depleted because of multiple pay zones. Most units within the Teapot, Parkman, and Teckla Sandstones have an average reservoir thickness of 10 to 150 ft, with a porosity and permeability range of 12 to 18 percent and 2 to 34 mD, respectively; some beds may have permeabilities exceeding 100 mD.
Mesaverde-Lewis Sandstone reservoirs in this AU have produced in excess of 126 MMBO and 187 BCFG from some 1,500 producing wells in 19 oil fields. Only oil with associated gas is produced from the 19 oil fields; there are no designated gas fields (NRG Associates, 2006). In addition, more than
5,100 wells have been drilled through the Mesaverde-Lewis interval to reach deeper targets (IHS Energy Group, 2006), which includes 2,100 new field wildcats (NRG Associates, 2006). Most oil production from Mesaverde-Lewis reservoirs is produced from two field size classes—16 to 32 MMBO and 32 to 64 MMBO—with a total volume of 88 MMBO. Five other field size classes from 0.5 to 16 MMBO produce the remaining 38 MMBO (NRG Associates, 2006).
Since the discovery of Mesaverde-Lewis production in the late 1950s at Dead Horse field, production depths from new field discoveries have averaged about 7,300 ft and ranged from about 5,500 to 9,500 ft. The historical trend, although short, is flat (NRG Associates, 2006). Oil gravity ranges from 35° to 47° API gravity per field with a mean of 39°. GOR ranges from less than 10 cfg/bo to more than 11,000 cfg/bo with a mean of 1,200 cfg/bo. Input values for the Assessment Data Form to assess this AU are shown in Appendix F. The number of undiscovered oil accumulations in this assessment unit was estimated to be a minimum of 1, a maximum of 10, and a mode of 2. There have been 19 new oil field discoveries, and although there has not been a new field discovery above the minimum size of 0.5 MMBO since 1980 (NRG Associ- ates, 2006), it is a likely possibility that at least 1 new oil
field above the minimum will be discovered. The maximum estimate of 10 undiscovered fields is a reflection of some areas with wells that could have tested sandstones in the Mesaverde- Lewis interval in combination stratigraphic traps, but failed to do so. New Mesaverde-Lewis oil discoveries will probably be mostly small fields in deeper parts of the basin, although the potential in shallower parts of the basin should not be over- looked. Exploration efforts should focus on finding porous and permeable sandstones with updip pinchouts.
Estimated sizes of undiscovered oil accumulations are
a minimum of 0.5 MMBO, a median of 1.5 MMBO, and a maximum of 10 MMBO. The default minimum size of 0.5 MMBO reflects a potential for one field to be discovered that is greater than the minimum size, but most discovered fields are expected to be small. A median size of 1.5 MMBO was used, which is an average volume for a new field size based on the most recent discoveries in the AU. A maximum size of 10 MMBO reflects some upside potential of the AU, especially because there are three fields that have produced more than
20 MMBO; but there is large uncertainty in discovering a new large-volume field.
There have been no new gas fields discovered in this AU, and the probability of new gas fields being discovered
in limited because gas generation in Niobrara source rocks is limited. Therefore, the number of undiscovered gas accumula- tions was a minimum of 0, a maximum of 7, and a mode of
1. Estimated sizes of undiscovered gas accumulations are 3 BCFG (the minimum field size to assess), a maximum of 10 BCFG, and a median of 3.5 BCFG. There is a potential for
at least one new gas field to be discovered equal to or greater than the minimum size of 3 BCFG because a large area in the northern part of the basin remains to be tested. The assigned numbers reflect the probability that future discoveries will be relatively small. Most of the assessed gas will be from gas associated with oil production.
Mean estimates of undiscovered resources for the Mesaverde-Lewis Sandstones Assessment Unit are 6.0 MMBO, 8.4 BCFG, and 0.6 MMBNGL (table 1). Table 1 also shows a resource breakdown into the F95, F50, and F5 fractiles.
Basin Margin AU (50330601)
The Basin Margin AU (about 5.45 million acres) includes the structurally upthrown parts of the western and southern rims of the PRB. Reservoirs include the same Paleozoic and Mesozoic strata that produce in the central part of the basin and are described in previous sections.
The production history of most Basin Margin fields show relatively small declines over decades of production, although some low-volume fields show some erratic production histo- ries, and others show modest production increases over short time intervals due to secondary recovery. Most fields have a strong water drive, whereas some have solution gas drives, and a few have only solution gas drives.
Basin margin fields have produced the greatest volumes of oil in the PRB, owing to stacked pay zones trapped in struc- tural closures; cumulative production exceeds 1,300 MMBO and 1,050 BCFG from more than 2 wells in 45 oil fields. Only associated gas is produced, and there are no designated gas fields. In addition, some 2,000 new-field wildcats have been drilled in this AU (NRG Associates, 2006).
Most oil production is from a field size class of 512
to 1,024 MMBO with a total volume of more than 700 MMBO. The giant Salt Creek field has produced more than 735 MMBO (NRG Associates, 2006), which is more than 6 times as much oil as the next largest producer, the Meadow Creek–Sussex field complex. Five other field size classes, ranging from 0.5 to 128 MMBO, produce the remaining oil of 590 MMBO (NRG Associates, 2006).
Since the early discovery of production in the early 1900s at Salt Creek field, depths of new field discoveries ranged from 150 to 10,000 ft and averaged 4,500 ft. In addition, there is a slight trend toward deeper field depths over time (NRG Associates, 2006). Oil gravity ranges from 15° to 50° API gravity per field with a mean of 33°. GOR ranges from less than 10 cfg/bo to more than 16,000 cfg/bo with a mean of
Input values for the Assessment Data Form to assess this AU are shown in Appendix G. Estimated numbers of undis- covered oil accumulations are a minimum of 1, a maximum of 20, and a mode of 5. Although there has not been a new field discovery (above the minimum size) since 1998 (NRG Associ- ates, 2006), it is estimated that at least 1 new oil field above the minimum of 0.5 MMBO will be discovered. The maxi- mum estimate of 20 undiscovered fields reflects the potential for new discoveries in stratigraphic traps and combinations of structural and stratigraphic traps, especially through the testing of new pay zones in some of the more recent discoveries, and
additional exploration that helps to define such structural and stratigraphic traps.
Estimated sizes of undiscovered oil accumulations are
a minimum of 0.5 MMBO, a median of 1.5 MMBO, and a maximum of 20 MMBO. The default minimum size of 0.5 MMBO reflects the potential for one field to be discovered that is greater than the minimum size; however, most new fields probably will be small. A median size of 1.5 MMBO was used, based on an average volume of the most recent discoveries. Although the potential is low for discovering a new large- volume field, a maximum size of 20 MMBO reflects at least some potential, especially because 20 MMBO is an average field for this AU.
There have been no new gas fields discovered in this AU, and the probability of new gas fields being discovered is low because gas generation or gas migration potential is limited. Therefore, the number of undiscovered gas accumulations was estimated to be 0. Most of the assessed gas will be from gas associated with oil production.
Mean estimates of undiscovered resources for the Basin Margin Assessment Unit are 17.9 MMBO, 14.7 BCFG, and 0.53 MMBNGL (table 1). Table 1 also shows a resource breakdown into the F95, F50, and F5 fractiles. The poten-
tial for future oil discoveries is considered to be limited but uncertain because a large area in the northern part of the basin remains to be evaluated.