PRB Resources

Petroleum
The Powder River Basin also contains major deposits of petroleum. The oil and gas are produced from rocks ranging from Pennsylvanian to Tertiary, but most comes from sandstones in the thick section of Cretaceous rocks.
Comparison of Results of 1995 and 2005 Assessments
A comparison between the 1995 and 2006 USGS resource estimates for the Powder River Basin Province shows an appreciable change in the estimated size of the undiscov- ered oil and gas resource. In 1995, Dolton and Fox (1995), using a play concept, estimated a total mean undiscovered oil and gas resource of 1,131 MMBO and 983 BCFG for 11 conventional and 1 continuous play in the PRB Province. In 2006, for the assessment discussed in this report using the total petroleum system concept, a mean resource of 639 MMBO and 2,368 BCFG (excluding coalbed gas) was calculated for the 11 assessment units in 6 TPSs. It should be noted that in the 1995 assessment the Mowry and Niobrara continuous AUs were not assessed. Considering differences in methodology, the 2006 estimates reflect a notable decrease in oil resource estimates, the difference being in the respective assessed value for the Minnelusa-Tensleep-Leo s AU. The 2006 assessed value had only a mean of 60 MMBO, whereas the 1995 assessment of the same units calculated a much larger com- bined value of 604 MMBO. The 1995 assessment speculated that the vast untested acreage in the western and southern parts of the basin where Minnelusa-Tensleep-Leo are present would eventually produce significant amounts of oil. However, in the present assessment, much less was estimated for the same untested area because of a perceived lack of potential traps.
Gas resource for this assessment was significantly higher than the 1995 assessment—2,368 BCFG compared to 938 BCFG— mainly due to an increase in estimated volumes of gas in the continuous Mowry and Niobrara reservoir systems, as well as biogenic gas (excluding CBM reservoirs). Conven- tional gas was assessed at 1,156 BCFG compared with the 1995 assessment of 1,011 BCFG.
How Much Oil?
Oil Well in the Florence Field
People have long known that the Niobrara is thick, rich in organics and thermally mature. Oil has flowed from the Niobrara since the dawn of the industry: Florence Field, near Canon City, Colorado, was discovered in 1876 near an oil seep. Florence produces from fractured Pierre shale, and part of the Niobrara formation. Oil pioneers also found the Niobrara productive at Salt Creek, Teapot Dome, Tow Creek and Rangely fields.
These fields were anomalous “Sweet Spots” due to the local geology and geologic structures that allowed the oil to flow freely with vintage vertical drilling technologies. In most fields the Niobrara section of the well was usually completed since it was above the more productive target reservoirs such as the Dakota “J” Sand in the Denver Basin.
Niobrara Total Petroleum System as a Continuous Reservoir
The Niobrara Formation is in part a self-contained petroleum system in that it is a hydrocarbon source rock as well as also containing reservoir rocks, a relation that is typical of a continuous petroleum system. In the PRB, Niobrara thicknesses range from 50 ft near the Black Hills to about
450 ft thick in the deepest parts of the basin, to a maximum of 600 ft along the west flank of the basin; basinwide average is about 400 ft (Fox and Higley, 1996b, map J).
Niobrara production is delivered through a network of fractures and faults, although the true nature of the networks
is as yet not well known in detail, such as fracture intensity
or connectivity, which control rates and distribution of fluids. Connectivity is best defined by fracture and fault orientation, length (or size in three dimensions), and intensity. Numerous studies (for example, Slack, 1981; Anna, 1986a, 1986b; Marrs and others, 1984; Martinsen and Marrs, 1985; Maughan and Perry, 1986; Mitchell and Rogers, 1993) have shown that
the pervasive regional structural orientations in the PRB
are northwest-southeast and northeast-southwest. Different orientations may exist, especially when associated with
local stress systems, but they are minor contributors to the regional fracture and fault connectivity patterns. Fracture and fault lengths are difficult to measure, although partial length distributions can be expanded through statistical methods
and used to eliminate censoring and bias from mapping. Conventional wisdom associates high fracture density with an increase in reservoir permeability, which may be true locally, but only if fracture length improves the connectivity of a given area (commonly called percolation theory).
Most locally generated fractures are connected by a regional system that enhances reservoir permeability (except possibly in coals). Geologic sweet spots in the Niobrara, therefore, should be determined first by mapping regional structural trends and secondly, by mapping local structural features such as fractures related to folding. For example, outcrop maps and horizontal well formation microimager (FMI) well log images of Austin Chalk in south Texas reveal that fracture spacing ranges from several fractures to only a single fracture per foot for distances of hundreds of feet; the several fractures per foot could be considered a sweet spot (Fett, 1991). Sweet spots are not necessarily fault related but
commonly are part of one structural event (Fett, 1991). Rates and cumulative production in the Austin Chalk point to large rock volumes being drained, indicating that 3-dimensional flow is probably taking place in large fractures connected to small but numerous fractures.
There appears to be no correlation, however, when comparing sweet spot zones (mapped as lineaments) and current Niobrara Formation production in the PRB (fig. 36). This discrepancy may be due to several factors: (1) Niobrara production rates are not dependent on fractures and faults;
(2) “sweet spot” areas are incorrectly mapped; (3) there is
not sufficient control to make a valid comparison; (4) there
is a bias in targeting other reservoirs as the primary objective rather than the Niobrara; therefore, its potential has not
been established; (5) the Niobrara is used as a bailout zone, independent of fracture potential; and (6) increased shale content in the western part of the basin may increase fracture length but decrease spacing compared with the chalky and brittle intervals of the Niobrara. Therefore, “sweet spots” may have different characteristics in shale intervals than in chalk
intervals.
Production data (IHS Energy Group, 2006) indicate that
the Niobrara Formation from 34 wells has cumulative produc- tion of almost 600,000 barrels of oil (BO), 1.9 billion cubic feet of gas (BCFG) over a 30-year reporting period. How- ever, few individual Niobrara wells have estimated ultimate recoveries (EUR) of over 100 MBO, with most accumulations of less than 50 MBO. Individual well-production plots indicate that most Niobrara wells produce little if any water from either oil or gas wells. Most operators target mid- to upper Niobrara strata. Lower zones are also a target but are not as laterally persistent as other zones, a condition that may form potential stratigraphic traps (Mitchell and Rogers, 1993).
Water saturations (Sw) in chalk reservoirs that produce commercial quantities of oil are commonly less than 50 percent (for example, the mean Sw for deep Denver Basin Niobrara is 0.39 ± 0.1). Intervals with water saturations above 50 percent are generally marginal or noneconomic. However, chalky intervals with high pore surface area may produce eco- nomic quantities of oil at saturations greater than 50 percent.
Campbell County Wyoming

  While the hunt for oil in the Niobrara Shale play is getting all the attention, other areas in Eastern Wyoming are getting a new look from energy companies for the first time in decades. In recent months, companies including Chesapeake Energy Corp. and EOG Resources Inc. are pursuing new permits for horizontal wells in Converse County, southern Campbell County and Natrona County. And while some of that activity is related to the Niobrara Shale, other drilling targets new formations and the edges of old oil fields. “That’s kind of an untold story,” said Tom Doll, superintendent of the Wyoming Oil and Gas Conservation Commission.
  The commission has issued 124 permits for Converse, Campbell and Natrona counties so far in 2011, compared to just 87 for Platte, Laramie and Goshen counties. The difference in permitting is likely partly due to a slowdown in applications in the southeast as a number of companies conduct seismic testing to see what lies underneath the area’s surface before drilling.
  Permits are being issued for several old oil fields and geologic formations known as tight oil sands, or somewhat porous sandstone that contains oil. Those formations, whose swaths cross the area both above and under the Niobrara formation, include the Parkman, Sussex, Shannon, Teapot, Frontier and Turner sandstone formations, among others.
  It’s all fairly new work by the companies, and that means there’s not a lot of desire by those involved to talk about the exploratory stage of what they’re doing. “We are actively evaluating several geologic formations in the area,” said Kelsey Campbell of Oklahoma City-based Chesapeake Energy.
  As in the Niobrara Shale play, its technology that’s driving the new exploration, including newly refined ways to drill deep, then turn the corner to drill sideways. “Some of these are old fields and some of them never got drilled as deep as they have before, and some of the formations haven’t gotten looked at before,” said Bruce Hinchey, president of the Petroleum Association of Wyoming.
  While drilling down and then laterally isn’t a new concept, drillers are drilling deeper and farther than ever — and faster, say Jimmy Goolsby, geologist for Casper-based Goolsby, Finley & Associates. He says the development of the technology will make the Powder River Basin a big player in the future of Wyoming oil. “We have so many potential targets there because of this new technology,” he said.
  Hydraulic fracturing, or fracking, has gotten credit for opening up shale plays across the U.S. With fracking, energy companies pump water, sand and chemical additives underground under pressure, which fractures barriers that hinder the flow of oil and gas.
  The new drillings may use fracking, but won’t necessarily depend on the underlying geology, Dolls said. While fracking has recently made its name in natural gas plays, the same practice — aided by the advances in drilling — is breathing new life into otherwise marginal sources of oil, Goolsby said. “You can go back into these fields and extend them quite a lot,” he said.
  The potential of the areas under consideration may not be as attention-grabbing as the Niobrara at the moment, but that doesn’t mean companies are shying away from a chance to make money from oil fields with marginally producing wells as the price of oil continues to climb.
  They’re “not as prolific a well as the potential for oil production in the Niobrara, but they’re commercial wells,” said Doll. For now, the new drilling in old and new areas is just getting started. “We’ll know more in a few months, as we start drilling,” said Hinchey.
  It is an enhanced oil recovery (EOR) or gas recovery method that is becoming more and more popular as the price per barrel of oil gets higher.
  Unlike a directional well that is drilled to position a reservoir entry point, a horizontal well is commonly defined as any well in which the lower part of the well bore parallels the oil zone. The angle of inclination used to drill the well does not have to reach 90° for the well to be considered a horizontal well. Applications for horizontal wells include the exploitation of thin oil-rim reservoirs, avoidance of drawdown-related problems such as water/gas coning, and extension of wells by means of multiple drain holes.
  Cost experts have agreed that horizontal wells have become a preferred method of recovering oil and gas from reservoirs in which these fluids occupy strata that are horizontal, or nearly so, because they offer greater contact area with the productive layer than vertical wells. While the cost factor for a horizontal well may be as much as two or three times that of a vertical well, the production factor can be enhanced as much as 15 or 20 times, making it very attractive.
  To give an idea of the effectiveness of horizontal drilling, the U.S. Department of Energy indicates that using horizontal drilling can lead to an increase in reserves in place by 2% of the original oil in place. The production ratio for horizontal wells versus vertical wells is 3.2 to 1,
Cody Shale
Shannon Sandstone Member
The Shannon Sandstone Member of the Upper Cretaceous Cody Shale was deposited as clean to argillaceous sand during early Campanian time in southeastern Montana, northeastern Wyoming, and northwestern South Dakota. Shannon Sandstones form conspicuous northwest-southeast- trending linear sand ridges; individual units are as much as
50 ft thick, thousands of feet in width, and tens of miles in length. Both the Shannon and the overlying Sussex Sandstone Member represent distal ends of a transgressive-regressive wedge of a deltaic system to the north and northwest along
the west margin of the Cretaceous seaway. One interpretation is that they were deposited as shelf sands or offshore bars, encased in marine shales, because of their classic upward coarsening grain size from a muddy shelf base, to fine- to medium-grained, well-sorted, clean and porous, cross- to planar-bedded sandstone at the top. Other interpretations include their being reworked delta systems, or they are incised nearshore and valley complexes, both of which require progradation events from a sea-level lowstand that created a variety of disconformities at the top and base (Bergman and Walker, 1995). An alternative interpretation for the origin of the Shannon might be similar to that of the Turner—that is,
the depositional processes involved a transgressive ravinement surface upon which sand was preserved in bathymetric lows but eroded sediment over highs, the pattern of which may have been structurally controlled in part.
Shannon Sandstone Member porosity ranges from near zero in argillaceous and bioturbated silt and sandy layers to over 20 percent in clean, well-sorted, medium-grained sand- stone. Permeability ranges from less than 1 mD to more than 100 mD, with a mean of 20 mD.
Sussex Sandstone Member
The Sussex Sandstone Member of the Cody Shale was deposited during early Campanian time and was separated from the underlying Shannon Sandstone Member by tens of feet of marine shale. The member is informally subdivided into three units (Anderman, 1976): a lower B sandstone, a middle marine shale, and an upper A sandstone. Similar to the Shannon, the Sussex was originally interpreted to be depos- ited as a middle shelf bar in moderate to deep water, with the sand being transported across the shelf bottom from nearshore sand accumulations. Sandstone body geometry similar to the Shannon, is dominated by northwest-southeast-trending linear sandstone units, tens of miles long, 2–3 miles wide, and tens of feet thick. Sussex production tends to cluster about two areas, one along the House Creek–Porcupine field trend and the other farther west along the Spearhead Ranch–Scott field trend (fig. 32). Production tends to cluster along a single trend represented by the Hartzog Draw, Pine Tree, and Jepson fields (fig. 33), with most production being west and north of Sussex Sandstone Member production.
The top of the reservoir B sandstone is approximately 20 to 60 ft below the Ardmore Bentonite Bed of the Steele Shale, based on correlation of well logs and core studies. Higley and others (1997) interpreted the B sandstone to have originated as a series of probable midshelf sand-ridge deposits in the Cretaceous epicontinental seaway (fig. 34). At House Creek field, for example, there are such units composing B sand- stone. Higley and others (1997) inferred that a transgression during deposition created the westward (landward) backstep- ping stacked sand ridges, followed by a regression marked by a disconformity at the top of the sandstone identified by thin chert-pebble sandstone (Higley, 1992).
Interridge lithologies consist mainly of burrowed and intact mudstone laminae, interbedded mudstone, and bur- rowed, fine-grained sandstone. These lithologies are effective permeability barriers, resulting in small reservoir compart- ments; this may be a cause for low production volumes.
Thicknesses of the Sussex B sandstone vary from a few feet to more than 50 ft depending on the number of stacked ridges and the amount of erosion that occurred both internally and at the top of the sequence. The Sussex A sandstone has a similar depositional history but is thinner and more discon- tinuous except at the Triangle U field where it is thicker and more continuous than the underlying Sussex B sandstone. At the Triangle U field, the A sandstone has permeability ranging from 2.5 to 77 mD, with an average porosity of 13.5 percent, whereas the B sand has both lower permeability (0.01 to
5.4 mD) and a porosity average less than 10 percent (Smith and Larsen, 1997).
Mesaverde Formation
Parkman Sandstone Member
The Parkman Sandstone Member of the Upper Creta- ceous Mesaverde Formation (fig. 27) is the oldest sandstone member in a widespread cycle of Late Cretaceous regression and transgression following the long period of predominantly marine deposition represented by the thick Steele Shale (or Cody Shale to the west of the PRB). The member consists
of a progradational delta complex that overlies the extensive marine shelf deposits of the Steele Shale. Lithologies include (1) prodelta shale and siltstone interbedded locally with very fine grained, well-sorted sandstone; (2) nearshore deposits of coarsening-upward successions of medium-grained sandstone with interbedded siltstone; and (3) terrigenous deposits of carbonaceous to lignitic silt and mudstone. Depth to Parkman reservoirs range from 5,000 ft to more than 9,500 ft near the Basin axis (Dolton and Fox, 1995).
Van Wagoner and others (1990) divided the Parkman Sandstone Member into one progradational parasequence and
the overlying Teapot Sandstone Member into two sequences. The lower Parkman appears to step basinward to the east, producing in the subsurface a well-log pattern characteristic of a progradational succession. Based on faunal zones, the member’s basinward time equivalent is the Red Bird Silty Member of the Pierre Shale. The top of the Parkman interval is bounded by a flooding surface caused by an abrupt increase in water depth recognized in well-log correlations as a planar surface (Van Wagoner and others (1990). Within each succes- sion are minor flooding surfaces that create laterally variable units of interbedded mudstones and siltstones.
Teapot Sandstone Member
The Teapot Sandstone Member was named after Teapot Rock, a prominent cliff-forming feature north of Casper, Wyoming. The nearby type section (Curry, 1976a) includes both marine and nonmarine sandstones, coals, and other associated lithologies. Curry (1976a) described the Teapot, from base to top, as 255–275 ft of lower prodelta shale, 55–70 ft of delta front strata, and 40–50 ft of nonmarine delta plain strata.
The prodelta section is dark-colored shale, with a regional unconformity at the base (Gill and Cobban, 1973; Krystinik and DeJarnett, 1995). The delta front strata consist of coars- ening upward, lightly burrowed, thin sandstone laminations with low to medium cross stratification in places; fine-grained intervals are interpreted as lower shoreface. Geophysical logs indicate that if the contact with the underlying prodelta shale is sharp, as in WC and Mikes Draw fields, the unit is generally a thick sandstone (average thickness 30 ft) with good log- calculated porosity. If the contact is gradational, only the top few feet of the delta-front strata are sand rich, with variable log-calculated porosity. This interval is overlain by horizontal laminated and oxidized medium-grained sandstone interpreted as nearshore to beach with exposed root zones at the top. The delta-front facies contributes most of the oil production.
The delta plain deposits consist of a variety of lithologies including distributary and overbank sandstone and siltstone, carbonaceous material including plant impressions, and thin discontinuous lignitic zones.
The Teapot Sandstone Member is composed of two progradational intervals (Van Wagoner and others, 1990). The upper boundary of the lower interval is terminated by a major erosional event and a slight basinward shift in facies. The overlying set is composed of two intervals separated
by a marine-flooding surface—shallow-marine sandstones below the boundary and deeper water mudstones above. The member’s basinward time equivalent is an unnamed shale of the Pierre Shale.
Frontier-Turner Sandstones AU (50330301)
The Frontier-Turner Sandstones AU (about 4.8 million acres) covers most of the south-central part of the PRB, and its outline is based on the distribution of reservoirs in the Frontier Formation and the Turner Sandy Member of the Carlile Shale that are currently producing oil and gas and have the potential for future production. Frontier production is located in the west side of the basin but does not include production from basin margin fields such as Salt Creek and Teapot Dome fields. Most Frontier production since the last USGS assessment of the PRB (Dolton and Fox, 1995) is from infield completions and from two new field discoveries with marginal Frontier production. Turner production is located in the east-central part of the basin (fig. 41) with new production from infield drilling and field extension. The K-bar field is a new field discovery since the last USGS assessment (Dolton and Fox, 1995), and Brooks Draw field has limited Turner production.
As explained in the Niobrara TPS section of this report, Frontier Formation and Turner Sandy Member (of the Carlile Shale) nomenclature is commonly used interchangeably for the same lithostratigraphic interval. In this report a distinction is made between the Turner and the Frontier, in that the Turner is treated as a time equivalent of the Wall Creek Member of the Frontier (fig. 27) having been deposited in a lowstand setting east of the Wall Creek highstand location. In places, the Wall Creek and the Turner are separated physically and hydraulically by a ravinement surface of erosion (fig. 31).
Frontier Formation and Turner Sandy Member reservoirs in this AU have produced some 74 MMBO and 289 BCFG from approximately 1,100 producing wells in 13 oil fields, 11 oil and gas fields, and 1 gas field. In addition, more than 4,500 wells have penetrated all or part of the Frontier-Turner section in this AU (IHS Energy Group, 2006), which includes some 1,500 new field wildcats (NRG Associates, 2006).
Most oil production from Frontier-Turner reservoirs is produced from one field size class, that of 16 to 32 MMBO with a total volume of 44 MMBO. Smaller field size classes produce the remaining oil of 30 MMBO (NRG Associates, 2006). Gas production is from one field, Porcupine, which has produced 39 BCFG; all other gas production is from associ- ated gas (NRG Associates, 2006).
Since the discovery of Frontier-Turner production in the early 1900s, production depth from new field discoveries in the 1960s averaged 4,500 ft; but since the 1970s depths have ranged from about 6,000 ft to more than 12,000 ft. Wells in the most recent discovery K-Bar field in 1997 have an average depth exceeding10,000 ft (NRG Associates, 2006). Oil gravity ranges from 30o to 52o API with a mean of 40o API. GORs range from less than 500 cfg/bo to more than 29,000 cfg/bo with a mean of 5,000 cfg/bo.
Input values for the Assessment Data Form to assess this AU are shown in Appendix D. Estimated number of undis- covered oil accumulations are a minimum of 1, a maximum of 20, and a mode of 3. There have been 24 new oil field discov- eries and, although there has not been a new field discovery (above the minimum size) since 1997 (NRG Associates, 2006), it is considered a likely possibility that at least 1 new oil field above the minimum of 0.5 MMBO will be discovered. The maximum estimate of 20 undiscovered fields is a reflec- tion of some areas with few wells that could have tested the Frontier and Turner reservoirs in combination structural and stratigraphic traps. New Frontier-Turner oil discoveries will
be in the deeper parts of the basin in overpressured reservoirs; the biggest challenge is searching out porous and permeable sandstone in overpressured compartments.
Estimated sizes of undiscovered oil accumulations are a minimum of 0.5 MMBO, a median of 1 MMBO, and a maxi- mum of 10 MMBO. The minimum size of 0.5 MMBO reflects what is considered to be the potential for discovering one field greater than the minimum size; however, most new fields are thought to be small. A median size of 1 MMBO, which is an average volume for new field size for the most recent discov- eries, was used although the range of most recent discoveries is between 3 and 0.5 MMBO. A maximum size of 10 MMBO is established as the upside potential of the AU, but there is considerable uncertainty as to the discovery of a large field.
There has been only one new gas field discovered in this AU, and the probability of new gas fields being discovered is limited because the potential gas generation volume in Nio- brara source rocks is areally restricted. Therefore, the number of undiscovered gas accumulations greater than the minimum is estimated as 0. Mean estimates of undiscovered resources for the Frontier-Turner Sandstones AU are 10.2 MMBO,
40.5 BCFG, and 2.9 MMBNGL (table 1). Table 1 also shows a resource breakdown into the F95, F50, and F5 fractiles.
Sussex-Shannon Sandstones AU (50330302)
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.
Sussex and Shannon reservoirs have produced some
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
500 cfg/bo.
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
900 cfg/bo.
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.