With escalating interest in the potential to produce oil directly from source rocks on Alaska’s North Slope, the U.S. Geological Survey is in the process of conducting an assessment of shale oil resources in northern Alaska. The idea is to use whatever information is available about North Slope geology to estimate ranges of hydrocarbon volumes that might be recovered from the source rocks using the horizontal drilling and fracking techniques that have proven so successful in the Lower 48 states.
On Oct. 25 USGS held a meeting in Anchorage, Alaska, to share its approach to its assessment with Alaska geologists and other specialists, to obtain feedback and comments before determining its resource estimates. USGS anticipates proceeding with the assessment in November, with publication of the results likely in January or February, USGS geologist Dave Houseknecht told the meeting.
Assessment method
The USGS method of estimating the volumes of oil and gas that might be recovered directly from an oil source rock involves mapping the disposition of the source rock in the subsurface; estimating the area of source rock that each production well might be able to access; and estimating the total ultimate recovery of oil from each well. By then calculating the total number of wells needed to access the entire area of the source rock and multiplying the number of wells by the per-well ultimate oil recovery it is possible to estimate of the total quantity of oil that might be produced.
But because none of the numbers involved in the estimating procedure are ever completely certain, the scientists use statistical techniques to factor in the various uncertainties involved, eventually deriving a range of possible total oil volumes that may be recoverable.
Uncertainty arises, for example, from the fact that rock properties and the detailed history of the rocks are never completely uniform across an entire play area: Source rock oil plays have “sweet spots” where oil production is particularly prolific, while other areas may be much less productive. And a key to gaining insights into potential oil production in a source rock play is an understanding of the parameters that can identify where oil and gas can likely be produced and where the sweet spots may be located. Parameters include the brittleness of the rock and indicators of likely oil or gas generation.
Challenges
Houseknecht told the audience at the Oct. 25 meeting that key challenges facing the North Slope assessment include the difficulty of mapping appropriate source rock parameters, given the scarcity of wells penetrating the rocks in areas where source rock oil development might occur. There is also the lack of a history of source rock oil production in the region — ultimate proof of the technical viability of source oil development will depend on drilling some successful production wells.
And, in the absence of any existing North Slope source rock oil development, the USGS assessment depends on identifying shale oil plays elsewhere that can be used as analogues for North Slope source rock plays. Oil productivity from analogues in the Lower 48, for example, can be used for guidance on possible productivity from North Slope source rocks with similar characteristics and geologic histories.
There are three major source rock systems on the North Slope: the late Triassic Shublik, the Jurassic lower Kingak, and an assemblage of rocks of Cretaceous age, including the Hue shale and HRZ or GRZ, within what is known as the Brookian sequence.
Most North Slope source rock oil interest is focused on the Shublik, which has an obvious analogue in the Eagle Ford shale, the rock formation at the center of successful oil shale development in Texas. Both the Shublik and the Eagle Ford have similar organic carbon contents and both are relatively brittle, thanks to an abundant presence of carbonate minerals — rock brittleness is an important factor in the hydraulic fracturing required to induce oil to flow from shale.
Thermal history
However, Houseknecht cautioned about some significant issues relating to the thermal history of North Slope source rocks, when compared with the Eagle Ford and with the Bakken formation, a prolific oil shale in North Dakota.
In a petroleum system such as that on the North Slope, an underground source rock has been heated, progressively passing through temperatures that first generate oil and then natural gas from organic material in the rock. There is a specific temperature window within which oil is generated and a higher temperature window within which gas forms.
As the temperature rises through the gas window, a point is reached at which oil, formed previously at lower temperatures, breaks down to form additional gas. That secondary gas generation from the “cracking” of oil typically leads to elevated fluid pressures within the source rocks, Houseknecht said. And in the Eagle Ford, for example, this “overpressure” from the cracking of oil has driven up the fluid pressure in the petroleum system and has become a factor in oil production, he said.
But, while the oil in the Eagle Ford and the Bakken has formed relatively recently in terms of geologic timescales, most geologists think that the oil in all of source rocks under the North Slope formed much earlier, with generation completed by 50 million to 60 million years ago, Houseknecht said. Thanks to the leakage of fluid from the rocks, the overpressure decays over time thus leading to the probability that overpressures within the North Slope rocks will tend to be lower than in their Lower 48 analogues, Houseknecht said. And the lower overpressures could impact oil production.
The concept that earlier overpressures have decayed seems to be borne out by pressure measurements within wells in the region, with abnormally high pressures limited to rocks in the southern, deeper part of the basin where rapid, deep burial, rather than hydrocarbon production, has likely caused overpressure development.
Thermal measurement
Houseknecht also expressed some caution over the way in which geologists normally assess the thermal history of rocks, and hence determine areas in which oil or gas may have been generated. The standard method of assessing rock temperature histories is the measurement of the reflectivity of vitrinite, a coal component commonly found in rocks containing organic material. According to conventional wisdom, very specific vitrinite reflectance values indicate whether a rock has been heated into the oil or gas generation window. Geologists use the mapping of vitrinite reflectance values from rock samples to delineate areas thought to be prospective for oil or gas, with this technique being used on the North Slope as one of the ways to map potential source rock oil plays.
But recent research has indicated that the vitrinite reflectance boundaries for oil and gas generation are much less clear cut than previously thought, with the reflectance thresholds sometimes varying from one rock formation to another, Houseknecht said. That raises questions over the reliability with which it possible to map areas on the North Slope likely to be conducive for oil or gas generation, especially given the small number of wells penetrating source rocks outside the area of the North Slope oil fields.
Rock variability
Another area of uncertainty when assessing the Shublik is the high level of variability in rock type within the formation. The Shublik consists of various different rock units containing different amounts of materials such as sand, silt and carbonate minerals, University of Alaska Fairbanks scientist Mike Whalen told the Anchorage meeting. And there are three distinct sequences of rock within the Shublik, with the organic carbon content that could generate oil or gas varying from being particularly high in one sequence to being moderate or low in others. The organic carbon content tends to be concentrated into fairly thin rock units, Whalen said.
And depending on exactly which parameters are used to assess the areas of the Shublik likely to have produced oil or gas, the total area of the source rock oil play could range anywhere from 3.7 million to 9.3 million acres for oil, and from 14.9 million acres to 23.6 million acres for gas, Houseknecht said.
The area of a potential source rock play in the Brookian source rocks appears to be smaller than that of the Shublik, but with the Brookian showing overall more potential for oil than for gas. But the rocks in the Brookian do not appear as suitable for hydraulic fracturing as those in the Shublik, thus raising questions over the likely effectiveness of Brookian source oil production. The other North Slope source rock, the lower Kingak, appears to be especially problematic as a target for hydraulic fracturing, since it contains much fairly ductile clay material, Houseknecht said.
