The cluster of Mississippian Lodgepole reef oil fields around Dickinson, ND, could be an indication of a supergiant Williston basin oil field which, although accidentally tapped in 1993, has remained unrecognized.
In time, the technologies that successfully culled a basin's larger oil fields pick up the smaller and then the smallest ones, thus exhausting their own potential, although not that of the basin. At this mature stage, new oil discoveries require the introduction of new technologies.
Over the years the author and partner Robert J. Angerer have developed four new technologies. We call them A I, A II, A III, and A V; we have used them to find Lodgepole oil in the Williston basin, construct an entirely new model of the production, and provide means to find reliably the otherwise elusive Lodgepole reefs across a broad expanse of the basin.
Reigniting the 1993-98 Lodgepole play in North Dakota in the decade starting in 2000 have been:
• Our discovery, with our partner Petrosearch Energy Corp. in November 2003, of the Gruman 18-1 Lodgepole producer near Dickinson with an 1,800 b/d initial potential;
• Marathon Oil Co.'s Darwin 14-35H Lodgepole discovery in January 2009, IP 160 b/d, as a third producing formation (in addition to the Bakken and Three Forks/Sanish) as a part of the Bakken shale play in North Dakota; and
• The Laurine Engel-1 discovery, IP 463 b/d, by Armstrong Operating Inc. and Continental Resources Inc. near Dickinson in September 2009.
In this two-part article, we describe new technologies that reveal that these discoveries may be part of a supergiant oil field that extends far beyond the Dickinson area.
Lodgepole supergiant
We have delineated a conservative conjectural 25,000 sq mile area for the postulated Dickinson supergiant oil field and have shown the documented reefs and productive reefs in the basin (Fig. 1).
Estimated ultimate recoveries of the Dickinson area Lodgepole formation wells average 800,000 bbl/well when dry holes are included and 1.4 million bbl/well considering only producing wells.
Optimally located and completed wells should have a higher yield still, as much as 4 million bbl. The author knows of no better prospects in North America.
Williston geology
The stratigraphy of the Madison Group is composed of hundreds of feet of limestone including the Lodgepole formation. Evaporites that cap Dickinson oil field prevent the upward escape of its hydrocarbons.
Logs show the stratigraphic position of the basin's Waulsortian mounds that grew to be about 330 ft tall (Fig. 2).
Dickinson field lies in the deepest synclinal part of the Williston basin, which it shares with heavy brines.
Geochemistry demonstrates that the Bakken shale (Fig. 2) did not source Dickinson oil field but that the Lodgepole formation with 13% average total organic carbon did.1
Madison aquifer
The deepest part of the Williston basin retains heavy saturated brines, and the fresh waters that flushed brines and oil out of the Madison aquifer in Montana and North Dakota skirted around postulated Dickinson supergiant oil field, thereby preserving it (Fig. 3).2 3
Ineffectual seismic
Every producer hit a reef, and no dry hole did. Practically all wells were sited on the evidence of seismic.
The industry's discoveries dwindled between 1993 and 1998, after which only dry holes followed (a rumored 130 in the Williston basin away from Dickinson). Clearly, here, seismic is not the answer.
A I analysis
Building on our experience in Texas, as earlier reported here,3 we focused on the Waulsortian mounds in the Williston basin, the Lodgepole reefs.
The rationale of the A I photogeomorphological analysis is that the weight of the overburden compacts the off-reef argillaceous sediments more than it does the reef core; this drapes strata over the buildup.
The differential compaction drape increases upward (Fig. 4) and has disappeared at Level 1; this is why the A I analysis requires uplift and erosion to remove enough of the top section (say, from Ground I down to Ground II) to expose the extremely subtle drape etched in the bedrock down to a level where it may be reliably detected.
Of course, A I is only an innovation in aerial photogeomorphology. The outcome Fig. 5, a scientific epiphany published here for the first time, maps the Waulsortian buildups as if stripped off overburden! Obviously, with such a map in hand, no one should ever miss a reef.
The vector that runs through the centers of forereef and backreef defines the paleocurrent; it varies little locally but swings widely from basin to basin and between various sections of the same basin; Fig. 5 was compiled in Illinois and properly rotated to reflect different paleocurrent directions, and it works for north-central Texas, the Williston, and other basins.
Wherever studied, the Williston basin is found carpeted with mounds (Fig. 1). The mounds mapped by A I in a typical township of Dickinson occur at a density of about 2.5 mounds/sq mile, which explains the likelihood of random hits.
A I constitutes a formidable advance in reef location, but two more technologies are required to properly exploit the postulated supergiant oil field.
A II analysis
Fig. 5 shows two A IIs (gold ellipse with red X), but the two ellipses are not reef cores but rather their "transforms." This raises the question of how does a reef "project" itself vertically some 3 km to the surface and what is its "X"?
Fig. 6 offers a first clue: solution karst of an oil-bearing limestone in the South China Sea2 creates caverns that later collapse under the weight of overlying sediments, causing a chimney.
The change from high velocities at the top of the chimney (gold) to low velocities (blue) in the lower part reflects increasing fracturing.
Collapse chimneys that result from underground nuclear tests further elucidate the anatomy of the phenomenon (Fig. 7).
The spherical detonation cavity quickly collapses under the weight of the overburden, creating a chimney topped by a surface crater.
The regression that tops the Lodgepole caused the Waulsortian mounds to emerge and become karsted by meteoric waters as in the towers of Fig. 8.
After subsidence resumed, the karsted mounds first collapsed, creating chimneys after 1,500-2,500 ft of new strata had been heaped upon them.
Although the stratigraphic correlations between dry holes work perfectly in Dickinson, correlations between dry holes (drilled outside collapse chimneys) and producers (drilled inside collapse chimneys) or between producers drilled in different collapse chimneys are chaotic and invalidate predictions based on formation.
The new reservoir model of Dickinson oil field has fractures surrounding a collapse chimney that drain the encasing rocks—here competent Madison carbonates (Fig. 9). This explains how the puny Waulsortian mounds with 3-5% porosity, negligible nonfracture permeability, and holding a maximum of, say, 120,000 bbl of producible oil, in fact may yield more than 4 million bbl of oil.
The mounds and their collapse chimneys are the outlets of the real reservoir.
Unlike the Bakken shale play in the Williston basin that requires hydraulic fracturing, the collapse of the Lodgepole mounds created a natural vertical fracturing across the entire area that can effectively drain the Madison carbonates if wells are placed within the collapses.
A scaled composite structural profile of all Dickinson wells plotted with (X) as origin shows the reconstructed profile of precollapse mounds and the different amounts of collapse (Fig. 10). Critically, it documents the existence of a central collapse cavity, filled with reef rubble.
The only four wells that found the "central collapse cavity" were sited on the evidence of A II. This central "sinkhole" has been corroborated by seismic elsewhere (Fig. 11).
Next week: Geochemical innovations point to vast Lodgepole oil expanse.
The author
Jamil Azad ([email protected]) worked on various international petroleum exploration assignments for Burmah Oil Co. until 1971, when he took up consulting in geoscience in Calgary. He has been a partner in Oil For America since its inception. He obtained a degree of geologist from Ecole Polytechique Federale in Lausanne, Switzerland.
British Columbia
Husky Energy Inc., Calgary, gauged encouraging flow rates at two vertical exploratory wells in Northeast British Columbia's Montney and Doig shales and plans to drill its first horizontal well there in 2010.
The company said it expanded its land position to 24,000 net acres from 11,500 acres in the play.
The Graham b-10-D/94-B-9 well flowed at a rate of 2.9 MMcfd of gas from the Doig formation. The Cypress a-31-B/94-B-15 well flowed 5.4 MMcfd from the Montney and 2.9 MMcfd from the Doig.
Recovery potential from the wells is among the best vertical tests from the Doig/Montney play, Husky said without giving figures.
New Mexico
The Cave Pool Unit in the Eddy County portion of New Mexico's giant Grayburg-Jackson field could be redeveloped under an agreement between Doral Energy Corp., Midland, Tex., and Blugrass Energy Inc.
Doral Energy acquired from Blugrass a 40% working interest in and is operator of the 2,800-acre Cave Pool Unit 5 miles northwest of Loco Hills. Blugrass Energy owns the other 60%.
The unit is adjacent to three leases owned and operated by Doral that produce from six wells in the Grayburg and San Andres formations and contains nine proved undeveloped drilling locations in Square Lake field.
Cave Pool Unit produces 10 boe/d from 39 Grayburg wells drilled on 40-acre spacing. Doral Energy will rework 10 of the wells.
Redevelopment of the unit as a 20-acre five-spot Grayburg waterflood could add 100 development drilling locations and more than 3 million boe of potential gross reserves.
With the acquisition, Doral Energy owns 8,920 net acres in Eddy County and 186 existing wells in the Artesia-Vacuum Trend.
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