“Resource plays could help refill trans-Alaska pipeline”
Is Alaska Next?
Alaska the Forgotten Frontier” of Resource Plays
In the hunt for resource plays – geologists go to where the oil is. They target source rocks of the conventional oil and gas fields, which produced the hydrocarbons we have been consuming over the past hundred years. In general, the larger the conventional accumulation is, the larger the source rock’s potential for yielding more oil and gas unconventionally. In both the U.S. and worldwide, energy companies have been sifting through the list of conventional plays to come up with ideas for new resource plays that are yet to be exploited. Obviously, identifying the target source rocks just comprises the very first step in the search. The suitability of the geo-mechanical properties of these rocks to hydraulic frocking (Young’s Modulus and Poisson’s ratio) comes in as a close second.
Most geologists in this country are familiar with the stratigraphy of onshore plays in Texas and Louisiana, where the majority of domestic oil and gas production has occurred. Consequently, it is not surprising some of the first significant and productive unconventional oil and gas plays were identified in those states. Exploration and Production activities in Alaska, on the other hand, have been limited to a few companies. This relative unfamiliarity, among geologists, with the North Slope’s stratigraphy and oil plays may have been a contributing factor that made Alaska a forgotten frontier when it came to resource plays.
Resource Plays Revolution
In the early1990’s Mitchell Energy Corporation made a very significant contribution to the oil and gas industry that is having a profound worldwide impact on oil production. They were first to prove that commercial production of hydrocarbons can be achieved by creating artificial fractures in the Barnett Shale in Texas. Their methodologies were later adopted, refined, expanded and applied by others. Large water fracture stimulations, often in multi stages, long reach horizontal wells and multi-laterals have become the techniques of choice when unlocking the potential of resource plays. Perfection in the application of these techniques and the popularity of resource plays in general, have dramatically altered the outlook of the US oil and gas production for many years to come (Fig.1). It is commonly stated, by those who work on multiple resource plays, that there are no two identical shale plays. Each play usually has its own set of well completion challenges. Operators typically work diligently to address these challenges in multidisciplinary approaches until production optimization is achieved.
Despite their technological arsenal and financial means, many of the Majors and large independents have taken a backseat; allowing smaller independents to spearhead refinement, experimentation and the application of various completion technologies to unproven resource plays. Those smaller companies are the ones who have been proving the concept in most new resource plays. Since small companies’ financial resources are usually limited they typically seek venture capital funding. Once shale productivity is confirmed and the specifics of fracture stimulation and completion parameters have been worked out, the Majors and large independents would typically come in and buy their way into the plays. Surprisingly, financially capable oil and gas companies have been more risk averse when it came to experimenting with “out of the norm” completion concepts. This seems to be a clear contrast to their willingness to taking on huge risks in speculative frontier exploration plays at a cost of hundreds of millions of dollars (offshore US Atlantic, as an example).
Impact of shale oil on national production
The U.S. monthly oil production has been on a steady decline since November 1978 when it peaked at 301,320 thousand barrels. By September 2008 it reached a low at 119,477 thousand barrels. The last 4 years, however, witnessed a reversal of that decline and by March 2012 the U.S. monthly production had increased by 63% to 195,219 thousand barrels (Fig. 1) thanks mainly to the contribution of the numerous resource plays.
Shale oil development using horizontal wells and hydraulic frocking has resulted in the reversal of production decline in most major petroleum regions in the country (Fig.2) and is about to be attempted, for the very first time, in Alaska’s North Slope.
Geochemical Analysis of Source Rocks
As organic matter (kerogen) is thermally cracked - oil and gas is generated – volume increases – oil and gas get expelled and migrate through a carrier bed to reside in the ultimate conventional traps. Not all generated oil is expelled outside of the source rock. A big portion of it remains in the source rock as unconventional resource and will require fracking to improve host rock’s permeability to allow it to flow and be recovered. This is akin to S1 in Rock - Eval Pyrolysis.
Pyrolysis is probably the best routine tool for determining the type and thermal maturity of the organic matter at the same time. Rock - Eval Pyrolysis is also typically used by explorers to analyze and understand the generative potential of the source rocks. Organic matter present in the source rock samples that converts to oil through heating in the laboratory by pyrolysis is called (S2) . Organic matter that was naturally converted to hydrocarbons but locked within the matrix framework of the rock is released in the lab at the initial heating and is called S1. Explorers, myself included, who were after conventional plays have typically ignored S1. For resource plays, however, S1 is more relevant at assessing the volume of hydrocarbons present in the source rock that have not been expelled whereas S2 measures the capacity of the source rock to generate when subjected to the optimum thermal regime.
Gas Chromatography (GC) and Mass Spectrometry (MS) are common methods of characterizing the chemical makeup of the crude oil and provide a finger print that can be used when correlating crude oils to source rocks or in comparing one crude oil to another. Mixing of crudes, however, presents somewhat of a challenge for this methodology.
Alaska North Slope Source rocks and their potential
Can Alaska match some of the other emerging oil plays in the lower 48, namely the Eagle Ford and the Bakken Shales? Alaska’s Department of Natural Resources (Decker, 2011) has compiled source rock and thermal maturity data of the most prominent non-Alaskan source rocks and found that they compared favorably to the known Alaska source rocks that sourced Prudhoe Bay, Kuparuk, Alpine, Endicott, Point Thompson, Tarn and Badami fields. These Alaskan source rocks belong to three distinct chronostratigraphic units (Fig. 3) that span approximately 150 million years (Permo-Triassic Shublik to Upper Cretaceous Brookian).
Needing to fill the pipeline
In June 2012, Alaska’s monthly contribution to the U.S. total oil production has plummeted to 7.9% (14,790 thousand barrels as compared to a U.S. total of 187,803 thousand barrels) from a March 1988 peak of 24.91% (64,668 thousand barrels as compared to a U.S. total of 259,587 thousand barrels). To the surprise of many, North Dakota’s oil production recently surpassed that of Alaska for the first time.
Alaska’s economy is heavily dependent on its oil and gas revenue. Currently Alaska’s production is at all time lows (Fig. 2) and less than 25% of the Trans-Alaska pipeline maximum daily capacity of 2.1 million barrels is being utilized. Since shale production is typically characterized by steep rate decline over the first year or two and flattens to a steady low rate for many years, the available spare capacity in the pipeline (which is equivalent to twice the amount of the current Bakken production) is probably more than sufficient to accommodate any and all shale oil production on the North Slope for the foreseeable future.
Stratigraphic relationships of North Slope Oil
Magoon and Claypool (1981) among others, identified two families of the North Slope oils. The Triassic Shublik oils tend to have notable sulfur content and be of lower API gravity mostly due to the presence of asphaltenes. The other family (non-Shublik) corresponds to all other oils that tend to have no sulfur, be of higher API and low asphaltenes.
The most notable non-Shublik source rocks (Fig.3) are comprised of the Pebble Shale, Hue Shale, GRZ (gamma ray zone)/ HRZ (highly radioactive zone), Lower Kingak and Upper Kingak. Although these oils are distinguishable on the Gas Chromatographs GC and the GC-MS when mixed, they cannot be reliably traced back to their original make up components. Because of the prevalence of oil mixing on the North Slope and the likely lateral and vertical changes in litho and organo facies over long distances, they are all lumped here under non-shublik sources following Magoon and Claypool’s (1981) classification.
No matter what geochemical parameters are used to classify North Slope oils, there are clear indications of notable mixing of crudes in various percentages in various strata. Different authors, invariably, arrive at different ratios using different parameters. The only time when there is consistency of opinions’ as to the ratios that are being mixed is when non-shublik and shublik oils are mixed, as is the case in Prudhoe Bay Field. There is a common agreement that approximately 70 % of Prudhoe oil is Shublik sourced and the remainder is a non-Shublik mix of Lower Kingak and Brookian (Pebble Shale/ Hue Shale/ HRZ/GRZ)
For the Ivishak sandstone, the main reservoir at Prudhoe Bay Field to contain oil that came from such mixing makes sense because of the stratigraphic position of the reservoir being relatively adjacent to the Shublik and Lower Kingak sources. To the contrary, the Kuparuk Oil Field with its 2.9 billion bbl of recoverable reserves is somewhat of an oddity in terms of the location of the reservoir in relation to the source. Kuparuk A and C sands (Fig.3) are the reservoir sands of the Field and stratigraphically are located very close to the top of Lower Cretaceous and, therefore, to the LCU (Lower Cretaceous Unconformity). Kuparuk A sands lie below the unconformity whereas Kuparuk C sands represent a post unconformity transgressive facies. The Kuparuk oil is a Shublik oil despite the fact that the Kuparuk reservoirs are surrounded by non-Shublik source rocks. North of Kuparuk lies the tested Ivishak trap of the Mukluk structure that appears to be breached by the LCU which is directly overlain by the Foran sand that is age equivalent to Kuparuk C sand. The Mukluk structure was full with Shublik oil before it migrated from its Ivishak south along the LCU and its transgressive Foran sands in response to a significant Tertiary uplift that was more pronounced at the Kuparuk area. The Mukluk oil as it migrated to Kaparuk left behind a 200 ft section of stained Ivishak reservoir with asphaltene rich tar/ heavy residual oil that is typically present near the bottom of the oil column (as in Prudhoe), whereas at Mukluk it was present near the top of the breached reservoir.
Another oil to stratigraphy misfit is the Ugnu and West Sak heavy oil deposits that are reservoired in the Upper Cretaceous rocks of the Brookian sequence, yet they contain Shublik oil that must have migrated upwards from Prudhoe through faulting.
Source rock facies
Clastics input results in the dilution of organic matter creating a less favorable source rock facies with lower generative potential. Many authors have documented areal variations in the source rock richness throughout the North Slope of Alaska. For example: the Shublik and Lower Kingak are richest to the south, the Pebble Shale to the east and the Hue shale to the northeast (Houseknecht and Bird, 2004 )
The present day East-West trending Barrow Arch (Fig.4) represented the proximal local for sediment provenance during the Elsemerian sequence deposition. Proximal facies with high terrigenous component are deposited to the north at or near the present day Barrow Arch. Distal marine facies of shale, limestone, marls and phosphorites, were deposited further south in anoxic conditions. It is therefore expected that organic richness of the Shublik increases the further south from the present day Barrow Arch it is deposited. The lithological variations of the Shublik could be a contributing factor to developing sweet spots within the Shublik for higher brittleness and fracture propagation (optimum Young’s modulus and Poisson’s ratio). The lithological heterogeneity will also cause areal variations in thermal conductivity and therefore in the intricate details of the thermal maturity regime.
The non-Shublik sources
It was noted that organic contents of the various shales change over large areas in response to their depositional settings (for example, Houseknecht and Bird, 2004) and vertically within the same formation (Lower Kingak has higher TOC and hydrogen Index than Upper Kingak). Throughout the area between Colville River and Canning River variations in the thickness and organic richness of the Pebble Shale, GRR /HRZ and Hue Shales have also been addressed and documented by many authors. Apline field, Tan field, Point Thomson and Point McIntyre have all been attributed to charges from non-Shublik sources.
Thermal Maturity of Source Rocks
Bird (2001) and Peters et al. (2006) have published a comprehensive summary of Alaska North Slope source rocks. According to their work the most prospective parts of the shale play area is located on the central North Slope which falls on State land. It is bound to the east by the Canning River and to the west by the Colville River. The Shublik and Lower Kingak account for the vast majority of the North Alaska oils discovered to date. The Pebble Shale, HGZ /HRZ and Hue Shale are responsible for sourcing the remainder of the oils.
Peters and others (2006) published their oil window maps across the entire North Slope. Figure (4) is a modification of a part of their map that was altered to focus only on the Central North Slope. The modifications also include depicting a volatiles/ condensates and low maturity categories. To schematically represent the uncertainties inherent in the map, the transitions from one zone to another is represented by jagged edges since detailed lithological composition , when it becomes available, will play an important role in outlining the thermal zones’ boundaries. As Figure (4) indicates, to date there are only two penetrations in the entire Central North Slope within the Shublik kitchen.
Different types of organic matter have different kinetics of transformation to oil and gas and the boundaries of oil and gas generations are not fixed but differ according to the type of kerogen. Typically oil generation start within the range of Ro of 0.5-0.7% and reaches a peak between Ro of 0.8 – 1.1% (Tissot, et.al.1978)
If the Shublik / Lower Kingak shales behave like the Eagle Ford, the entire maturation windows for oil and gas could be productive. Dry gas window will develop in the south near and at the Brooks Range foothills and oil window further north. Wet gas and condensate window would develop in between and could prove to be the most lucrative, where the hydrocarbons are in the gas state in the reservoir but condensate when brought up to the surface forming light/condensate oil. This is also sometimes referred to as the volatiles zone which, in the Eagle Ford, appears to enjoy enhanced production characteristics and better pricing.
In partnership with Halliburton, Great Bear Petroleum made history. On their North Slope of Alaska acreage , Great Bear drilled and cored the first well (Alcor # 1) to be purely planned and designed to test and quantify production characteristics of the North Slope source rocks.
Great Bear’s drilling rig has already moved into their second well location (Fig.4). According to a Duncan (2012), their third well location will be south of the second and the fourth will be south of the third but remaining on the west side of the Dalton Highway. Information on the results of these wells, according to the State of Alaska, can be kept confidential for at least 25 months. East and west of Great Bear’s 500,000 acres lies Royale Energy’s 100,000 acres which are situated within the peak oil generating and the volatiles windows of the Shublik and Lower Kingak shales.
The size of the Resource
There are many wells drilled on the North Slope but most of which are located on or near the Barrow Arch outside the thermal maturity windows of all shale. Any oil observed in shale near the Barrow arch is probably either migrated oil or very early generated oil. The vast majority of traps in the conventional pools are exploiting migrated oils in a structural or combination structural / stratigraphic traps. Shale source rocks sampled in these wells provide good approximation to the geochemical parameters before thermal maturity is reached. Thus TOC original and HI original can be approximated from immature source rocks found in those drilled wells and therefore, extrapolation into the deeper parts of the basin have to rely heavily on basin modeling. Thermal maturity zones (Fig.4) can be detailed and refined once several wells have penetrated the thermally mature Shublik and the exploration has progressed sufficiently. There are sufficient uncertainties when predicting the thermal maturity of rocks at any one specific location without knowing its detailed lithological make up (since lithology affects the thermal conducitivity and heat flow), as compared to thermal maturity that is measured directly from source rock samples by either Tmax or vitrinite reflectance.
Discovered oil in place volumes typically represent only a fraction of the oil volume that was generated from its source rock and the North Slope is no different. According to Peters et al (2006), all calculations of volumes of expelled oil from each of the various sources far exceed estimates of the in –place oil of the North Slope. Magoon et al, 2003, estimated that the in place discovered Shublik oil amounts to 57 billion bbls. Estimating the amount of generated oil, Peters et. al. 2006 using Rock - Eval and hydrous pyrolysis calculated a range of 783-1181 billion bbls (Rock - Eval) and 578 billion bbls (using hydrous pyrolysis). Referring to the huge gap between the proven oil in place that has Shublik signature and those calculated by using Rock - Eval or hydrous pyrolysis as having been generated, Peter concluded that “losses of expelled petroleum by dispersion, leakage and adsorption during migration through carrier beds and other processes, such as biodegradation, must be enormous”. A significant portion of that un-accounted for oil still resides, no doubt in the source rocks themselves waiting to be exploited.
2012 USGS Resource estimate
Based on estimates of the ultimate recovery per well, cell size and success ratios derived from the Lower 48 shale oil and shale gas analogs, the USGS (Houseknecht et.al., 2012) published an assessment of the technically recoverable shale oil and shale gas resources of the North Slope. Their estimates are 0-2.0 billion bbls of oil and 0-80 TCF of gas. Their modeling acknowledges the large range of uncertainty, particularly in view of the fact that there were no attempts made in the past to produce hydrocarbons from the shale. Once true shale oil production values are established these modeled estimates would move significantly to the upside.
Risk factors, challenges and considerations in establishing a working resource play in the North Slope.
· The Shublik is not known to be over pressured like the Bakken and Eagle Ford shale. This introduces an element of risk related to the productivity of the unconventional Shublik wells. In order to mitigate this potential shortcoming, Royale Energy selected their acreage at the peak oil to the condensate range of thermal maturities expecting that the presence of some gas will improve the reservoir energy and well productivities.
· A characteristic of the oil generated from the Shublik is that it is asphaltene rich and contains sulfur. Asphaltenes can possibly clog pore spaces and impact the productivity of this shale even after fracking. Sulfur can cause the thermal maturity to occur earlier and thus early mature oil may result. And therefore, a modeled thermal maturity window can be less accurate than otherwise expected.
· Oil production from a single resource play typically varies considerably from one location to another. Sweet spots might not be identified by the first few wells and industry should not jump into early conclusions.
· Tertiary uplift might have caused dormancy in the oil generation, capping or reducing reservoir energy.
· Existing Shublik well penetrations within the thermal maturity window are limited. Most of the penetrations are at or near the Barrow Arch where thermal maturity is lower. Therefore, the thermal modeling of oil generation is much less calibrated to the south than it is to the north.
· Planning shale developments on the North Slope that adheres to the existing guidelines and complies with all permitting and environmental demands will require timely cooperative efforts from the State and local authorities within the realms of lease duration.
· Only Great Bear Petroleum and Royale Energy pursued acreage that mainly focused on shale plays. All others were after conventional reservoirs although some of their acreage might also be prospective for shale.
· Leftover resources: Is now a window of opportunity for Alaska shale development to proceed while the oil price is high? Continually improving technology and the sheer magnitude of shale oil developments worldwide could cause the long term price of oil to stabilize or even decline, particularly in view of the world’s relative political stability and economic slowdown. As a chorally, one would have to question whether all the existing coal reserves will ever get mined? Has a large portion of the remaining coal reserves missed the boat? Any chance, with the fast paced developments of green energy, oil will become no longer fashionable on the long term? What would the Saudis do if they feel that oil is going out of favor while they are sitting on a huge pile of reserves? Would they panic, and sell more and more only to further depress prices.
· Shale development in Alaska is likely to be price sensitive. Future prices and fiscal terms may not support delaying its economic development. Timing is everything, this is the time to exploit and develop this shale oil resource.
· The State of Alaska offers generous credits for certain exploration activities but legislators are yet to finalize a plan that could make oil production on the slope more lucrative to producers.
Bird, K.J., “Alaska: A twenty-first-century petroleum province” in M.W.Downey, J.C.Threet, and W.A. Morgan, eds., Petroleum provinces of the twenty-first century: AAPG memoir 74, 2001, p.137-165.
Decker, P.L., “Source - reservoired oil resources, Alaskan North Slope”, Alaska Department of Natural Resources, Division of Oil and Gas presentation, Sept.15,2011.
Duncan, E., “Update from the field – Great Bear Petroleum’s Drilling Program and Upcoming Activities” a presentation at the K&L Gates shale conference, Anchorage, July 31, 2012.
Houseknecht, D. W. and K.J. Bird “Sequence stratigraphy of the Kingak Shale (Jurassic-Lower Cretaceous) National Petroleum Reserve in Alaska”, AAPG Bull., 2004, v. 88, p279-302.
Houseknecht D.W., W. A. Rouse, C. P. Garrity, K. J. Whidden, J.A. Dumoulin, C. J. Schenk, R. R. Charpentier, T. A. Cook, S. B. Gaswirth, M. A. Kirschbaum, and R. M. Pollastro, “Assessment of potential oil and gas resources in source rocks of the Alaska North Slope” U.S. Geological Survey Fact Sheet 2012–3013, 2 p., 2012.
Magoon, L.B., and G.E. Claypool, “Two oil types on the North Slope of Alaska – Implications for future exploration”, AAPG Bull., 1981, v.65, p644-652.
Magoon, L.B., and G.E. Claypool,“Alaskan North Slope petroleum systems. USGS open file report 03-324, 2003.
Peters, K.E., L.B.Magoon, K.J.Bird, Z.C.Valin, and M.A.Keller, “North Slope, Alaska: Source rock distribution, richness, thermal maturity, and petroleum charge”, AAPG Bull., 2006, v.90, pp.261-292.
Tissot, B.P. and Welte, D.H., “Petroleum formation and occurrence – A new approach to oil and gas exploration,” Springer-Verlag, Berlin Heidelberg, Germany, 1978, 538 p.