In these days when the oil and gas industry is looking for untapped resources overseas, a significant domestic resource is owned and managed by the Native American Tribes and Native Corporations of Alaska.
The US Bureau of Indian Affairs (BIA) published a report in 1994 that identified 950 million bbl of oil and 5.6 tcf of natural gas reserves on Native American held lands (BIA General Publication G-94-3).
In response to presidential direction the US Department of Energy (DOE) embarked on a program to encourage the managing tribes to develop this resource. A successful program would not only add to the domestic oil supply but enable the tribes to increase income and self-determination with regard to their jointly owned lands.
The programs supported by the DOE provide the tribal managers state-of-the art information and technology to evaluate the potential of tribal lands and manage them for maximum use and protection. The program encourages dialogue between tribes, industry, and researchers through meetings and technology transfer workshops. Projects have been selected in various areas of the country.
Advanced Resources International (ARI) and the Jicarilla Apache Indian Nation (JAIN) joined in 2000 with funding from the DOE to develop an exploration strategy suitable for identifying the oil potential of the Mancos formation on tribal land. This article describes that effort and its results.
Play overview
The Mancos in the San Juan basin is a thick, organic-rich, Upper Cretaceous marine shale. It is a confirmed, unconventional, continuous-type oil play as established by the US Geological Survey, being play 2208 in the 1995 National Assessment of United States Oil and Gas Resources.1
It is a dual-porosity, naturally fractured play, and due to the tight nature of the shale matrix, reservoir development depends on extensive natural fracturing. The USGS has estimated that 189 million bbl of technically recoverable resource remains to be discovered and produced from the play.
The JAIN is located largely in Rio Arriba County, north-central New Mexico, on the eastern margin of the San Juan basin (Fig. 1). Four oil fields have been discovered and developed in the Mancos in the vicinity: East Puerto Chiquito, West Puerto Chiquito, and Gavilan fields just south of the northern nation lands, and Boulder field within the nation boundary (Fig. 2).
These four fields have produced 27 million bbl of oil and 85 bcf of gas since 1960 and account for approximately three-quarters of all production from this formation in the San Juan basin (Table 1).
Due to the continuous nature of the play and the obvious potential for continued natural fracture (reservoir) development northward along the basin margin onto JAIN lands, an opportunity exists to extend the productive Mancos trend in this direction. The challenge is to understand the geologic mechanisms underlying natural fracture development in the Mancos, calibrate that understanding with the existing fields, and to then extrapolate the resulting model along strike to identify new exploration leads to the north.
Geologic setting
The San Juan basin is a broad, topographic basin with a pronounced structural asymmetry to the north and northeast. Cretaceous strata dip gently to the northeast along the southern flank and quite steeply to the south and west in a prominent monocline that bounds the basin along the northern and eastern flanks.
The productive areas in and adjacent to the Jicarilla lands lie at the base of the monocline (locally known as the Hogback) where strata of Upper Cretaceous age have been deformed by impingement of the Nacimiento uplift along the eastern flank of the basin during Laramide tectonic activity.
The primary reservoir objective is the Niobrara member of the Upper Cretaceous Mancos shale. The Niobrara is 800 ft thick across the area and contains three (possibly more) silty, dolomitic intervals that form fractured reservoirs as a result of fault and fold related deformation along the west dipping, monoclinal, basin margin.
Ridgley3 performed a thorough stratigraphic review of the Jicarilla lands and concluded the majority of the area contained silty facies similar in nature (although in some cases, younger) to the productive areas along the southern margin of the lands.
Source rock studies undertaken as part of the overall evaluation indicated most of the lands lie within an interpreted oil window and should have charge readily available for local fractured reservoir development, negating the need for long-distance migration through extremely tight host rock.
The structural geology of the area is complex (Fig. 3). Outcrop patterns of en echelon appearing folds and faults along the front of the Nacimiento uplift gave rise to the transpressive margin hypothesis of Baltz.4 Lorenz,5 using citations from several authors, recounted a complex history for the Nacimiento uplift involving initial strike slip and later compression to form a slight overhang.
Available seismic from previous operators was reprocessed and interpreted by Taylor6 to improve resolution and understanding of the structure along the eastern margin of the JAIN lands. Coverage is sparse and ambiguous. Westward verging thrusting is visible on some lines, as is eastward backthrusting.
Using Fig. 4 as the basis for a working hypothesis, the surface anticlines and synclines can be visualized as of subtle backthrusts related to deeper basinward thrusting and can be expected to die out basinward.
As mentioned previously, the oil reservoirs are contained within three fractured dolomitic siltstone beds within the Niobrara member. Specifically, these reservoirs are called the "A," "B," and "C" zones, each 5-20 ft thick. These more brittle rocks fracture more easily when bended, folded, or faulted to create the permeability conduits needed for commercial production than the more plastic encasing shales.
Core tests suggest that the Mancos exhibits almost no matrix porosity (<1%), with high irreducible water saturations (>90%).7 Matrix permeability is also low (0.05 to 0.1 microdarcies). Hence, all reservoir porosity and permeability are associated with natural fracturing.
Natural fracture systems typically exhibit low bulk porosities (<1%) and high reservoir permeability (tens to hundreds of millidarcies). Wide well spacing is logical in such environments; large spacing provides the pore volumes needed to store commercial quantities of oil in the low-porosity reservoir, and high permeabilities suggest these porosities can be drained from a considerable distance.
Reservoir depths range from 2,000-3,000 ft in the east (towards the basin margin) to around 7,000 ft in the west (Fig. 5). Approximate depths to the producing horizons for each field and implied original reservoir pressures based on a 0.33 psi/ft gradient are provided in Table 2. Reservoir temperatures are 150-170° F.
The reservoir oil has an API gravity of 33-43°, a viscosity of about 0.6 cp at reservoir temperature, and is considered a sweet, low-sulfur, paraffin-base crude. Importantly, the bubble point pressure is estimated at 1,535 psi.
Since Mancos reservoirs do not have water drives or gas caps, the primary drive mechanisms are pressure depletion and solution gas drive, both of which are relatively inefficient. Along the flank of the monocline, however, gravity drainage has also been proven effective, and pressure maintenance appears to be an essential practice for successful field development.
Development history
For the most part, the four Mancos fields were developed using vertical wells that were cased, perforated, and hydraulically fractured in the Niobrara (reservoir) zones.
In some cases the wells were pumped later in life. The approved and actual well spacings adopted for each field are presented in Table 3, as determined by Sage.8 The three easternmost fields, East Puerto Chiquito, Boulder, and West Puerto Chiquito, being on the flank of the monocline, probably benefited from gravity drainage. The Canada Ojitos Unit (in West Puerto Chiquito field) was formed almost immediately after field discovery, and an active program of pressure maintenance via produced gas re-injection was immediately implemented.
Significant difference in performance is apparent from estimated ultimate recoveries (EURs) for each of the fields (Table 4). Work by Greer7 sheds some light into the performance differences.
While there does not appear to be a significant variation in pore-volume density across the play, there can be two orders of magnitude in difference in per-well recoveries (Table 5). One reason for this difference, however, can be attributed to the various well spacings employed. This might account for one order of magnitude difference in well performance.
However, as also noted by Greer, gravity drainage (and more importantly pressure maintenance), can account for another order of magnitude improvement in field performance (Table 6). Hence a combination of wide well spacing, being on the flank of the monocline to take advantage of gravity drainage, and a proactive pressure maintenance program via produced gas re-injection, appear critical to maximize production from these Mancos reservoirs.
The average Mancos shale well has an EUR of 164,000 bbl of oil. Some 87% of all wells have an EUR of less than 300,000 bbl (Fig. 6).
However, similar to many naturally fractured plays, the remaining 13% of the wells, that have an EUR greater than 300,000 bbl each, account for two-thirds of total Mancos reserves. In fact, the top 20% of wells accounts for 75% of total Mancos reserves in the eastern San Juan basin.
The best well in the play, the Canada Ojitos Unit 11, has an EUR approaching 3 million bbl; the best five wells in the play are in the Canada Ojitos Unit and suggest that the development/operating practices there have had a direct influence on well performance.
Time-zero production plots for each field (Fig. 7) again make it clear that Puerto Chiquito West is the most prolific field in the play, followed by Gavilan, and finally Puerto Chiquito East.
New exploration leads
Assembly of reservoir characterization information, regional geology, and theoretical understanding of fracture systems in faulted terranes indicates exploration efforts in the JAIN lands area should focus on the downdip tips of synclinal areas near the base of steep dip as they die out basinward or synclinal areas off the flank of intrabasinal highs.
These areas are interpreted as the most likely places to encounter multiple fracture directions (good permeability), strong extensional fracturing (better storage potential), and better reservoir energy (low in the gravity well).
Based on these criteria, four lead areas on the JAIN lands have been identified. These four leads fall into two general analog types, Gavilan1 and West Puerto Chiquito.3
The imagery from which the Gavilan-type lead was identified is presented in Fig. 8.
The high productivity synclinal area of Gavilan, located in the northeast quarter of 26n-2w, underlies a pronounced dendritic drainage anomaly indicating a subtle syncline plunging to the NW (red circle). The lead, green circle, shows a similar, but larger, surface anomaly. Shape contouring of sparse Mancos top data for the area seems to confirm the potential presence of a synclinal area.
As stated previously, exploration targets for oil in the Mancos of this area should target synclinal features near the base of the monocline to maximize reservoir energy and potential for fracturing in the reservoir. This lead lies in a similar position with respect to the monocline as Gavilan and seems to show similar surface expression, justifying its lead status and further investigation.
The three lead areas identified on the eastern portion of the JAIN lands (West Puerto Chiquito analogs) all lie on or near the base of the monocline. Fig. 9 shows the imagery of the eastern flank area where the backthrusts and their associated synclines (blue circles) have expression at the surface. These subtle structures have been used in the past to justify the left lateral sense of shear along this margin.
Another possible interpretation, favored here, would make the reverse faults and synclines backthrust systems forming, fan-like, off the north flank of the Nacimiento uplift. Under this scenario, the exploration target would be the leading edges of the backthrusts where Coulomb shear fractures associated with the fault propagation would provide the multiple directions of fracturing necessary for high permeability and low structural position along the monocline would provide reservoir energy.
Pro-forma economics
Production forecasts for Lead I (Gavilan) and Lead II/III/IV (West Puerto Chiquito) were based on the time-zero plots for the fields. Curve-fits for each are provided in Figs. 10 and 11.
The average Lead I well yields an EUR of 81,000 bbl; however, this estimate has been increased by a factor of two, to 162,000 bbl, to account for assumed implementation of improved development practices than actually used at Gavilan–specifically the wider well spacing and the implementation of pressure maintenance.
Note that this value is about average for the play. The average Lead II/III/IV well yields an EUR of 343,000 bbl, similar to that at West Puerto Chiquito.
Note that no value was assigned to gas production as it was assumed that all produced gas was reinjected (Table 7).
The results of the analysis based on the previously-stated assumptions are presented in Table 8. For Lead I, a total exploration cost of $1.9 million is estimated, and a total capital investment of $22 million to yield an oil reserve of 16 million bbl of oil and a net present value (NPV) of $57 million (15% discount rate). The profitability ratio for this case is 2.6.
For Lead II/III/IV, a total exploration cost of $900,000 is estimated each, and a total capital investment of $7 million to yield an oil reserve of 9 million bbl and NPV of $34 million. The profitability ratio for this case is 4.8.
Note that if all four leads were developed (and each was successful), these economic results could be scaled up accordingly (see total column).
Acknowledgments
This work was performed under sponsorship of the US Department of Energy National Petroleum Technology Office contract (DE-FG26-00BC15194). The authors also acknowledge the Bureau of Indian Affairs (Oil and Gas Division), and the US Geological Survey, for technical contributions and support of this work.
References
- "1995 National Assessment of United Sates Oil and Gas Resources – Results, Methodology, and Supporting Data", USGS Digital Data Series DDS-30, 1996.
- Bureau of Indian Affairs, "Atlas of Oil & Gas Plays on American Indian Lands; Jicarilla Apache Indian Reservation, New Mexico."
- Ridgley, J., "Sequence Stratigraphic Analysis and Facies Architecture of the Cretaceous Mancos Shale on or Near the Jicarilla Apache Indian Reservation, New Mexico-Their Relation to Sites of Oil Accumulation," USGS Final Technical Report on Mancos Shale, Phase 1 and Phase 2, Mar. 31, 2000.
- Baltz, E.H., "Stratigraphy and Regional Tectonic Implications of Part of Upper Cretaceous and Tertiary Rocks, East-Central San Juan Basin, New Mexico," Geological Survey Prof. Paper 552, 1967.
- Lorenz, John C., and Cooper, Scott, P., "Tectonic Setting and Characteristics of Natural Fractures in Mesaverde and Dakota Reservoirs of the San Juan Basin, New Mexico and Colorado," Sandia Report, SAND2001-0054, January 2001.
- Taylor, D.J., and Huffman, A.C., Jr., "Location, Reprocessing, and Analysis of Two Dimensional Seismic Reflection Data on the Jicarilla Apache Indian Reservation, New Mexico," USGS Topical Phase 1 Report, Mar. 30, 2000.
- Greer, A.R., and Ellis, R.K., "West Puerto Chiquito-USA, San Juan Basin, New Mexico," in Foster, N.H., Beaumont, E.A., "Structural Traps V, Treatise of Petroleum Geology, Atlas of Oil and Gas Fields," AAPG, 1991.
- Sage Energy Resources Inc., "Geologic Assessment of Oil & Gas Resources in the Mancos & Mesaverde Formations (Township 27 North, Ranges 1 East-2 West), Jicarilla Apache Indian Reservation, New Mexico," Aug. 31, 1993.
The authors
Scott R. Reeves ([email protected]) is executive vice-president of Advanced Resources International Inc. in Houston. He has over 18 years of experience in reservoir and production engineering for emerging and nonconventional oil and gas resources. He holds a BS in petroleum engineering from Texas A&M University and an MBA from Duke University.
Randal L. Billingsley is senior project manager for ARI in Denver. He is a petroleum geologist with over 25 years of industry experience. Since 1999 he has been involved with ARI's fractured reservoir technology development efforts, including the Multisite Geomechanical Technology Demonstration Program, Next Generation Fractured Reservoir Tools Program, and the practical application of advanced rock fracture concepts to exploration. He holds a BA and MS in geology from the University of Wisconsin.
Greg Embery is senior petroleum geologist with the Jicarilla Apache Oil & Gas Administration and has more than 24 years' experience. He has concentrated on the Midcontinent and Rocky Mountain regions. His background includes lease evaluation, prospect development, and sales in the exploration and exploitation fields, operations, and administration. He has a BS in geology from Western State College of Colorado.
Rhonda Lindsey ([email protected]) is a senior project manager for the US Department of Energy National Energy Technology Laboratory. Formerly with ARCO, she now oversees the NPTO drilling, completion, and stimulation and field demonstration and independent producer programs and assists in new program development. She has geology degrees from Slippery Rock University and Ohio State University.