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Taking a look at NS shale oil potential The possibility of unconventional oil development in the North Slope’s world-class source rocks raises some intriguing questions Alan Bailey Petroleum News
Having purchased about 500,000 acres in leases to the south of Alaska’s Prudhoe Bay field in a 2010 lease sale, Alaska newcomer Great Bear Petroleum is moving forward with plans to drill some wells to test the production of oil direct from the prolific source rocks of the North Slope. This “unconventional” type of oil play, sometimes referred to as shale oil or source reservoired oil, has become a major growth area for the Lower 48 oil industry but is new to Alaska.
At a meeting of the Alaska Geological Society on Sept. 15 geologist Paul Decker from Alaska’s Division of Oil and Gas described the ins and outs of source reservoired oil development, and overviewed the potential for this type of development in northern Alaska.
Unconventional oil resources tend to be distributed continuously across quite wide areas within relatively impermeable rock units that have both generated and trapped the oil, Decker said. This relatively wide, continuous distribution of oil trapped in known oil source rocks renders the geologic risk of finding source oil relatively low compared with the search for oil in the isolated hydrocarbon accumulations of conventional oil reservoirs and traps.
But an unconventional play usually entails a higher engineering risk than a conventional play, because the feasibility of stimulating the rock into releasing oil in viable quantities and at viable rates is often unknown until the play is tested, Decker said. The stimulation of the rock, done using hydraulic fracturing, or fracing, has to be both massive and successful, he said.
Three source rocks There are three primary oil source rocks on Alaska’s North Slope, each of which may have potential for exploitation in a source reservoired oil play. The oldest and deepest of these, the Shublik formation, is of late Triassic age and consists of interlayered limestones, shales, sandstones and siltstones. Deposited on an ancient marine shelf in a situation where the upwelling of seawater caused an influx of rich organic nutrients, the rock contains large quantities of organic material appropriate to the generation of oil when heated. The Shublik is the presumed source of the oil in the huge Kuparuk River field, Decker said.
The second prime source rock is the slightly younger and shallower lower Kingak formation of lower Jurassic age. This rock consists essentially of shale, formed from clay and deposited on a marine platform in a situation where oxygen depletion in the water enabled the preservation and accumulation of large quantities of organic material. The Kingak sourced the relatively light oil of the Alpine field, Decker said.
Toward the eastern end of the North Slope the Shublik and lower Kingak tend to be absent, where they have been eroded out at a major discontinuity in the stratigraphic sequence known as the lower Cretaceous unconformity.
Above the lower Cretaceous unconformity lies the third primary oil source, the Cretaceous Hue shale, containing a distinctive oil source zone referred to as the GRZ. The Hue shale/GRZ was deposited in deep water at the toes of west-to-east sloping lenses of sediment in what used to be an oxygen-starved marine basin to the north of the emerging Brooks Range. The Hue shale/GRZ sourced the high-quality light oil of the Tarn field.
Great Bear has expressed a particular interest in investigating the production potential of the Shublik, but with an intent to also investigate the potential of the lower Kingak and the Hue shale/GRZ.
Key factors The productivity of any of these source rocks in a source reservoired oil play will depend on four key factors: the rock’s organic content; the manner in which the rock has been heated, stressed and deformed at depth; the physical properties of the rock, in terms of the rock’s ability to hold and flow fluids; and the ease with which the rock tends to fracture under stress, rather than bend or flow, Decker explained.
Assessing these four factors in any particular oil play can involve the use of several techniques, including rock sampling and testing from surface exposures and subsurface well cores; the chemical analysis of rock samples; testing the desorption of oil or gas from rock samples; using well log data to obtain information about rock fracture systems and areas likely to be rich in organic material; and the use of sophisticated seismic data analysis techniques to assess how brittle the subsurface rocks are, and the likely orientations of natural fracture patterns, Decker said.
And although the North Slope source rocks have promise as targets for source reservoired oil development, understanding their true potential will depend on drilling and testing, to tease out information about those four key oil productivity factors.
The Shublik The Shublik, for example, is seen in surface outcrop in the western part of the North Slope and in the Brooks Range foothills but has been penetrated by just two wells on Great Bear’s acreage, in the area thought to be prospective for a source reservoired oil play. However, some years ago a well test in the undeveloped Kemik gas field, in the foothills immediately west of the Arctic National Wildlife Refuge, showed a natural gas flow rate of about 12 million cubic feet per day from the Shublik, a promising indication of the Shublik’s potential. And two wells on the northern side of the Prudhoe Bay field exhibited oil flow rates of 1,100 to 2,500 barrels per day from the Shublik, although that oil had probably migrated into those locations from elsewhere, Decker said.
Studies of various indicators of the thermal history of the North Slope rocks point to a zone in which the rocks have at some point been heated sufficiently to generate oil without being heated to the point where all the hydrocarbons would have been baked into natural gas. A plot of this zone indicates that the Shublik would have reached temperatures conducive to oil formation along a swath of territory running west to east under the Slope, a few miles inland, and right under the locations of Great Bear’s leases to the south of Prudhoe Bay. And a plot of what is known as the “hydrogen index,” an indicator of the oil potential of the rock, also suggests that Great Bear’s leases are well located, Decker said.
Eagle Ford analogy There are also some quite close analogies between the rock characteristics of the Shublik and those of the Eagle Ford shale, a rock unit that has been the successful target of shale oil development in Texas: Both rocks contain similar quantities of organic carbon; both contain organic material appropriate for oil formation; and both contain abundant limestone, brittle enough to readily fractured. The Eagle Ford does contain some regions of relatively high fluid pressure that help push oil into production wells, but if the Shublik has an analogous zone of high subsurface pressure, it has not yet been drilled.
North Slope well log data indicate that zones containing differing rock types within the Shublik are fairly continuous and consistent across wide areas of the North Slope, a feature that should aid with development predictability, as new wells are drilled, Decker said.
Very little is known about the source reservoir characteristics of the lower Kingak formation, above the Shublik, Decker said. However, as with the Shublik, the Great Bear leases appear to be well located, over the fairway where the Kingak has reached subsurface temperatures that are appropriate for oil formation. And there may be potential for the simultaneous development of the closely spaced Shublik and Kingak, as a kind of “shale sandwich.”
The carbon content, temperature and rock thickness distributions of the Hue shale/GRZ also point to the Great Bear leases being in a favorable position for that oil source, Decker said.
Development challenges However, assuming that northern Alaska source rocks have the appropriate properties for shale oil production, there will be some significant technical and economic challenges along the route to viable development.
In essence, hydraulic fracturing involves pumping huge volumes of a slurry of water and sand down a well bore that penetrates horizontally through the target source rock, Decker said. The well is stimulated in a series of isolated sections, in a process known as multistage fracing. The fluid pressure is progressively increased in each section until the pressure exceeds the surrounding rock strength, causing fractures to propagate outwards from the well bore. The slurry flows into the fractures, with the water subsequently flowing back out, but with the sand remaining in the fractures to keep the fractures open and allow oil to flow from the surrounding rock into the well.
Although there has been controversy about the use of hydraulic fracturing, with questions raised over the potential contamination of subsurface aquifers, it is important to take a factual perspective of any risks associated with the technique — there are no documented cases of proven groundwater contamination from fracing operations, Decker said. In fact, it is possible to use seismic detectors to determine the distances that the stimulated fractures extend from the wells, with those distances typically ranging up to a maximum of around 750 feet. By comparison, North Slope source rocks are about a mile below the closest aquifer, Decker said.
96 percent water The fracing fluid itself consists mostly of water. Decker cited a representative example from a frac job in a West Virginia shale gas play in which the frac fluid consisted of about 96 percent water, 3.8 percent sand and 0.2 percent chemical additives, such as biocides, scale inhibitors and gel breaking agents. Many of the chemicals additives are present in common household products, he said.
One challenge for North Slope unconventional oil production will be obtaining water for the fracing operations. The multistage fracing of a typical well requires 1 million to 6 million gallons of water — that compares with the 1 million to 1.5 million gallons of water used per mile to construct a typical winter ice road on the North Slope, Decker said.
Given the paucity of lakes in some parts of the North Slope and the need to avoid the complete draining of lakes, it will be necessary to find sources of water other than surface water, with treated seawater or water from underground aquifers being possible alternative sources. And although it is possible to recycle fracing fluids from one well to another, injection wells for the disposal of some used fluid will eventually be necessary, Decker said.
Finding a suitable source of sand for the fracing fluid will be another issue.
Many wells A critical issue in the economics of unconventional oil production is the area of subsurface source rock that each production well can access through the fractures propagating from the well bore, with the size of that area determining the total number of wells required in a particular play — typical unconventional oil developments require a relatively large number of wells, although directional and horizontal drilling techniques reduce the surface footprint of the wellheads. Using a comparison with developments in the Eagle Ford shale, Great Bear has speculated that each North Slope unconventional oil well may access somewhere between 120 and 160 acres of source rock, Decker said.
The typical production profile for a shale oil or shale gas well involves an initial rapid decline in the production rate, followed by a period of slow decline that can last for many years and that appears somewhat similar to the production decline of a conventional well. Oil production from the Bakken formation in North Dakota, another successful Lower 48 unconventional oil play, appears viable, even for the wells with low production rates — the presence of 150 operational drilling rigs in the region attests to the economic success of the play. However, North Dakota drilling costs are lower than those in Alaska, perhaps by a factor of two or three, while well operating costs are also relatively low in North Dakota, Decker said. Reduced drilling and operating costs may be necessary for successful unconventional oil development in Alaska, he said.
So, what may be the way forward for source reservoired oil production on the North Slope?
Great Bear plans to start drilling in its leases this coming winter to investigate and test its target source rocks. If that testing proves successful, the next step would be some small-scale pilot oil production, to test the production characteristics of the rocks over time. A subsequent transition into full scale development and production would require a major ramp up in operations, with more drilling and frac crews, and with all-season roads for year-round drilling access, Decker said.
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