How fractured reservoirs and a tectonic province boundary relate: clues to possible giant fields

Jan. 11, 1999
The western portion of the Williston basin is an attractive exploration target for fractured carbonate reservoirs and large reserves. A Proterozoic tectonic boundary formed by the juxtaposition of the Wyoming and the Trans-Hudson Provinces has formed a suture zone that could contain very large oil and gas reserves. Many large oil and gas fields have been discovered within the area that overlies the suture zone ( Fig. 1 [228,009 bytes]
Timothy J. Petta
Gemstone Consulting Inc.
Houston
The western portion of the Williston basin is an attractive exploration target for fractured carbonate reservoirs and large reserves. A Proterozoic tectonic boundary formed by the juxtaposition of the Wyoming and the Trans-Hudson Provinces has formed a suture zone that could contain very large oil and gas reserves.

Many large oil and gas fields have been discovered within the area that overlies the suture zone (Fig. 1 [228,009 bytes]), including the complex of fields over the Cedar Creek anticline and Poplar field. Reservoirs within these and other fields in this area often contain fractures. The suture zone contains numerous structural blocks defined by gravity data, aeromagnetic data, surface geology, and, to a lesser extent, by seismic data.

During times of high tectonic stress, displacement of these structural blocks could have caused fractures to be developed in brittle carbonate rocks. Large petroleum reserves could be undiscovered within Mississippian carbonate mounds that accreted on the seaward margins of the structural blocks in an area 20 miles wide. When concentrated over a structural block boundary, a group of mounds could contain over 100 million bbl of oil.

Cabarett Coulee oil field is an example of the type of trap and reservoir that might be encountered during further exploration of the area. Regional mapping and examination of seismic data indicates the productive Lower Mission Canyon and untested Lodgepole formation contain carbonate mounds throughout this area. These mounds are often associated with faults that can be observed to extend into the basement.

Failure to recognize the indications of fractures and overbalanced mud weights normally used while drilling in the area are some reasons why this play has not been recognized and exploited. Cabarett Coulee field is located directly over the westernmost boundary of the suture zone and basinward of the Devonian salt solution edge.

Stratigraphy

Approximately 1,500 ft of Mississippian carbonate and evaporite rocks were deposited in a deep marine seaway that connected the cratonic Williston basin with central Montana. These rocks are part of a shoaling upward sequence that begins with relatively deep water deposits of the Lodgepole formation and culminates with shallow water and sabkha evaporites of the Charles formation (Fig. 2 [56,165 bytes]).

The deepwater rocks are typically composed of lime mudstones and cherty and spiculitic lime mudstones and wackestones that have little or no effective porosity.1 These rocks rarely produce hydrocarbons.

Waulsortian-type mounds, described from central Montana, are present in the Lodgepole and the lower part of the Mission Canyon formations.2 These mounds have a mudstone to wackestone fabric and are often flanked by detrital beds comprised of interbedded wackestones and packstones.

Carbonate mounds are recognized throughout the area by their thick isopach values, cleaner gamma ray log signature, lighter color, and less chert.3 When productive, the mounds and associated higher energy rocks are often fractured.4

The Charles salt is the regional top seal for oil accumulations in this area. Both the Bakken shale and the Lodgepole formations are within the oil generation window and are probably the source of oil contained in Mississippian reservoirs.5 Regional dissolution of Devonian salt and periodic readjustment of basement blocks since the Proterozoic probably caused fractures to be concentrated along structural block boundaries within the suture zone.

Fractures should be concentrated in the cleaner, more brittle carbonate rocks such as mounds and their associated facies. The relatively brittle Mississippian carbonate rocks, sandwiched between the ductile Charles and Bakken intervals, are excellent candidates to contain fractures.

Fractures

Cabarett Coulee oil field, discovered in 1990, has produced 421,418 bbl of oil and 193,660 bbl of water from fractured reservoirs in the Lower Mission Canyon formation and the McGowan zone of the Charles formation. The field is located directly over the western boundary of the suture zone (Fig. 1).

Production from the 1-30 discovery well was begun from perforations between 6,590 and 6,670 ft. The flow test rate from these perforations was 840 b/d of oil at 500 psi through an 18/64 in. choke.

The well was recompleted twice during the next 14 months because of high water cut and was subsequently recompleted in the McGowan zone of the Charles at 6,312-42 ft. The McGowan zone contains lime packstones and grainstones that are locally fractured. The 2-25 well also produced oil from the McGowan.

The Lower Mission Canyon structure map shows that the discovery well produced from 320 acres of closure that has 78 ft of vertical relief (Fig. 3A [182,551 bytes]). The last well drilled on the structure was the 7-30; a crestal penetration that tested water from the Lower Mission Canyon zone that was productive in the 1-30 well.

Oil production is not related to structural position but to the presence of fractures and the fluid saturation of each zone. A separate closure in Sec. 24 has been defined by three wells that all had oil shows in the Mission Canyon but were not productive. Most recently, the 1-24 Gendreau tested this closure and reportedly had pipe set through the Mission Canyon. All wells that penetrated the Lower Mission Canyon had oil shows and contain evidence of fractures, but only the 1-30 has produced oil from this zone.

Fractures within the carbonate mound facies of the Lower Mission Canyon (Fig. 4 [242,677 bytes]) have been detected by several methods including washout through the productive zone, lost circulation while drilling, very high porosity indicated by CNL-FDC logs, and Formation Microscanner Image (FMI) logs. Over 1,200 bbl of drilling fluid were lost while the discovery well was drilled through the productive zones. Pronounced drilling breaks and excellent mud log shows were associated with lost circulation.

Analysis of FMI data indicates there are three sets of fractures present within the field. These fractures trend N-NE/S-SW, N/S, and NW-SE. Dip of the fractures averages 80°, aperture of fractures varies from 0.003 to 0.8 mm, and the fracture density varies from 0.5 to 8.0 fractures/ft.

The Lower Mission Canyon pay section is at the top of a clean, potentially brittle, carbonate interval. Fractures continue downward nearly 600 ft through the Lodgepole carbonate section until they die out in the lower Lodgepole and Bakken shale intervals. Near vertical fractures could be present throughout the entire brittle interval.

The operator attempted to re-complete the 1-30 (two legs) and 4-19 (four legs) wells using horizontal technology during 1991 and 1992, but the six attempts were unsuccessful, largely because of mechanical problems. Some of the attempts penetrated intervals above the pay zone and encountered few fractures. When the attempts penetrated the pay interval, very large oil shows were encountered and the mud weight had to be increased to keep the well from flowing oil to the surface.

The final drain hole produced oil and water but was not truly horizontal; it was approximately 70° from vertical, possibly causing water coning. Although these attempts were largely unsuccessful, they confirmed the presence of near vertical fractures identified on logs and established that each fracture zone contained a variable amount of oil and water and different pressures.

Carbonate mounds

There is evidence of carbonate mounds in the Lower Mission Canyon interval at Cabarett Coulee. Regional cross sections indicate the presence of mounds in the Lodgepole. Regional isopach maps, combined with seismic and other data, indicate that both those intervals can thicken over present-day structures. A less shaly gamma ray log response within either or both intervals is observed to be concomitant with areas where the isopach intervals are thick.

Regional cross sections support the hypothesis that those areas where the Lodgepole and Mission Canyon intervals are thickened and cleaner represent areas where organic mounds accumulated. The mounds should be more brittle than the surrounding carbonate rocks because they contain a lower percentage of shale and organic material.

The Lower Mission Canyon isopach map demonstrates that two mounds have been penetrated (Fig. 3B). Thickness of the productive zone varies from 164 ft off the mounds to nearly 250 ft along the axis of the two mounds. Analysis of CNL-FDC and sonic logs, mud log descriptions, and FMS logs was used to determine that most of the porosity within Lower Mission Canyon carbonates at Cabarett Coulee field is from vugs and fractures.

No whole cores or rotary sidewall cores were obtained while drilling the field wells. The vuggy porosity and some of the fracture porosity might have been caused by meteoric water diagenesis of the carbonates during a period of subaerial exposure. By analogy with Lodgepole mounds in the North Dakota Dickinson area described by Schurr et al.,6 the vugs probably constitute the majority of the porosity whereas the fractures provide the majority of the permeability in the reservoir.

Fig. 5 [43,528 bytes] shows the orientation of fractures in those wells that were logged using FMI. Fracture density increases from west to east through the field. A fracture spacing of one zone/100 ft has been calculated from logs and was confirmed by the horizontal re-completion attempts. Width of individual zones can vary from 2 to 30 ft according to FMI data. This map demonstrates the relationship of the fractures to basement faults and carbonate mounds in this area. The dominant fracture trends are parallel to basement faults recognized from seismic data and to the axis of the carbonate mounds. Increased fracture density towards the basement faults suggests that some of the fractures are the result of tectonic displacement.

Horizontal drilling and completion technology and sound reservoir management are probably required to successfully produce the reserves remaining in this field, which have been estimated to be over 15 million bbl of oil.

Tectonic history

Clement7 demonstrated that the Cedar Creek anticline, located directly over the Trans-Hudson to Wyoming Province boundary, had experienced several episodes of structural rejuvenation during the Paleozoic and Mesozoic. Fields associated with this anticline hold a large portion of the oil and gas reserves produced from the Williston basin.

Gibson8 speculated that Proterozoic structures, tectonic blocks, were probably the focal point for structural rejuvenation. This work, based on an interpretation of regional gravity and aeromagnetic data, proposed that structural rejuvenation had affected facies distribution in Mississippian rocks and could have caused fractures to be developed along the boundaries of basement structures.

Schurr et al.6 demonstrated that the fractured reservoirs in productive Lodgepole mounds in North Dakota were directly related to the position of the mounds directly over relay ramps associated with oblique-slip normal faults. These faults are associated with basement block margins that were subjected to episodic structural displacement since the Proterozoic and are visible using Landsat data.

Monson and others4 used several seismic lines to demonstrate the potential remaining on the Fort Peck Indian Reservation, immediately south of Cabarett Coulee field. These illustrations demonstrate the generally poor imaging of structural and stratigraphic detail within the Mission Canyon and Lodgepole intervals by seismic data.

The surface drainage pattern in the Cabarett Coulee area can be used to delineate the possible location of tectonic block boundaries over the boundary of the tectonic provinces (Fig. 6 [159,345 bytes]). Cabarett Coulee field is interpreted to be on the northeast side of one of the blocks. The positions of possible mounds and oil shows in the area are shown in relationship to other blocks.

Golanka9 indicated that the prevailing wind direction in the Williston basin during the Mississippian was from the northeast. Therefore, it is probable that carbonate mounds began vertical accretion over the northeast margins of the basement structures on the western side of the basin.

Cabarett Coulee field is located on the northeast side of an interpreted block. Shear stress applied to this area during orogenic episodes probably caused fractures to be concentrated along the boundaries of the blocks, particularly in the more brittle carbonate mound sequences. Additional fractures within Mississippian carbonates could have been emplaced as the Devonian Prairie salt was subjected to regional solution.

Conclusion

Several episodes of fracture generation and the relationship of fractures to structural boundaries make the western portion of the Williston basin an attractive exploration area.

Mississippian-age carbonate mounds preferentially accreted on the northeast sides of structural blocks within a suture zone that connects two major tectonic provinces. These mounds were fractured during readjustment of structural blocks and, possibly, regional salt dissolution.

Examination of Cabarett Coulee oil field indicates individual fracture zones are up to 35 ft wide and can be nearly 600 ft high, spanning the Lower Mission Canyon and most of the Lodgepole formations. Complexes of multiple fractured carbonate mounds within the suture zone could contain over 100 million bbl of oil.

Any exploration program in this area should incorporate many sets of data including seismic, aeromagnetic, gravity, surface geochemistry, and subsurface geology. Definition of basement block boundaries is crucial to the accurate prediction of carbonate facies that are prone to be fractured. Once a carbonate mound sequence has been discovered, the use of horizontal drilling technology should be implemented. The reward for a complete program in this area might be a giant field.

References

  • Peterson, J.A., and McCary, L.M. McCary, Regional stratigraphy of the Williston basin, in Longman, M.W., ed., Williston basin: anatomy of a cratonic oil province, Rocky Mountain Association of Geologists, 1987, pp. 9-43.
  • Burke, R.G., and Diehl, P.E., Fracture and vugular porosity in the Dickinson Waulsortian-like mound-potential horizontal drilling target?, in Second International Williston Basin Horizontal Well Workshop, North Dakota Geological Survey and Saskatchewan Energy and Mines, 1994, pp. B3-1-B3-16.
  • Burke, R.G., and Lasemi, Z., A preliminary comparison of Waulsortian mound facies in the Williston and Illinois basins, in Hunter, L.D., and Schalla, R.A., eds., Seventh International Williston Basin Symposium, Montana, North Dakota, and Saskatchewan Geological Societies and the Fort Peck Tribes, 1995, pp. 115-128.
  • Monson, L.M., Ewert, W., and Zeier, R., Fort Peck Reservation Oil Summary, Part II: Exploration opportunities, in Hunter, L.D., and Schalla, R.A., eds., Seventh International Williston Basin Symposium, Montana, North Dakota, and Saskatchewan Geological Societies and the Fort Peck Tribes, 1995, pp. 265-278.
  • Burrus, J., Osadetz, K.G., Wolf. S., Doligez, B., Visser, K., and Dearborn, D., Resolution of Williston basin oil system paradoxes through basin modeling, in Hunter, L.D., and Schalla, R.A., eds., Seventh International Williston Basin Symposium, Montana, North Dakota, and Saskatchewan Geological Societies and the Fort Peck Tribes, 1995, pp. 235-251.
  • Schurr, G.W., Ashworth, A.C., Burke, R.G., and Diehl, P.E., Tectonic controls on the Lodgepole play in Northern Stark County, North Dakota-Perspectives from surface and subsurface studies, in Hunter, L.D., and Schalla, R.A., eds., Seventh International Williston Basin Symposium, Montana, North Dakota, and Saskatchewan Geological Societies and the Fort Peck Tribes, 1995, pp. 203-208.
  • Clement, J.H., Cedar Creek-a significant paleotectonic feature of the Williston basin, in Peterson, J.A., and others, eds., Williston basin-anatomy of a cratonic oil province, Rocky Mountain Association of Geologists, 1987, pp. 323-336.
  • Gibson, Richard I., Basement tectonics and hydrocarbon production in the Williston basin, an interpretive overview, in Hunter, L.D., and Schalla, R.A., eds., Seventh International Williston Basin Symposium, Montana, North Dakota, and Saskatchewan Geological Societies and the Fort Peck Tribes, 1995, pp. 3-10.
  • Golanka, J., Ross, M.I., and Scotese, C.R., Phanerozoic paleogeographic and paleoclimatic modeling maps; in Pangea, Global environments and resources, CSPG Memoir 17, 1992, pp. 1-47.

The Author

Timothy J. Petta is a Houston consulting geologist actively involved with carbonate geology and exploration projects in several U.S. onshore basins. During the 15 years prior to becoming a consulting geologist in 1991, he worked as a senior and senior staff geologist for Shell Oil Co, Supron Energy, and Union Texas Petroleum. He holds a PhD degree in geology from Louisiana State University.

E-mail: [email protected]

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