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Prudhoe Bay Oil Field: Discovery, Formation and Impacts

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The Prudhoe Bay oil field: The largest oil discovery in the USA

The Prudhoe Bay oil field is located in Alaska on the North Slope. The onshore field spans 214,000 acres. Due to the immense size, satellite fields are established within the field. These extract smaller quantities of oil and gas. In total, there are an estimated 24 billion bbls of OOIP and 40 tcf of OGIP (BP, 2006). The National Petroleum Reserve in Alaska (NPRA) is also in the North Slope, which is owned by the federal government.

In 1944 the U.S Geographical Survey conducted an extensive exploration program on behalf of the U.S navy costing over $55 million (Morgridge, 1969). Seismic, gravity and magnetic surveys were completed and 3 oil and 6 gas reservoirs were found. Without this survey, there is little doubt this field would have been discovered so soon by ARCO and Exxon in 1968. This was followed by 8 years of legitimacy issues where surrounding lease owners including BP and Exxon resolved their equity participation for the future oil extractions. Production then began in 1977. Currently, BP is the operator of the Prudhoe Bay field and all satellite fields on the Prudhoe Bay unit. ConocoPhillips and ExxonMobil have the highest joint percentage ownership of 36% each followed by BP (26%) and lastly Chevron (1%) (BP, 2013).

The stratigraphy and structural formations made it possible for the reservoir to form. During rifting, rocks were uplifted which gave rise to an unconformity; these rocks were buried again, giving rise to an unconformity trap. Figure 1 shows the cross section of the field and the most important reservoir is found in the Sadlerochit group. The western boundary of this reservoir is sealed by the structural straddle in the upper surface on the reservoir. A stratigraphic trap seals the reservoir; this is an unconformable layer composed of a cretaceous mudstone. At the start of production the depth of oil bearing sandstone was 600ft, recently the thickness average is 60ft. (Jamison, Brockett and McIntosh, 1983, pp. 279–302)

The deposition of the sadlerochit layer occurred under 2 separate conditions giving rise to an upper and lower sequence, containing different compositions. The main composition of the lower sequence ranges is clastic sediments, such as sandstone. This was derived through a northerly source, and crucially deposition occurred in a shallow-marine environment – the believed source of the petroleum. The sediments from the upper layer were derived from the south where non-marine alluvial complexes were present. Figure 2 shows the age of the reservoir is the Triassic age and visually shows the sadlerochit group and the different rocks present including the dipping that occurs. The Ivishak layer contains sandstone and has a slight dip of 2O south; this layer produces the largest proportion of the oil in the field (Erickson and Sneider, 1997, pp. 18–22).

The permeability varies across the field. The Ivishak layer is subdivided into 8 vertical zones and in descending order these zones are 4B, 4A, 3, 2C, 2B, 2A, 1B, and 1A. Zones are defined by the individual petrophysical properties of each vertical section. The permeability in each individual zone varies considerably, for example in zone 2A there is a 100-fold difference in minimum and maximum values- 25md to 2500md. This difference implies that there is a vast change in the pore system, not the magnitude of porosity (Sneider and Erickson, 1997, pp. 23–30). Figure 4 shows the varying rock type and thickness, as well as the geophysical properties. For example, the low gamma ray count indicates the presence of silt and shale.

Development of the field has been hugely successful. There were 25 billion bbls of oil, of which only 9.6 billion bbls was initially thought to be recoverable. This estimate has increased to 13 billion bbls due to technological advances in enhanced oil recovery (EOR) and through gas reinjection programs (ConocoPhillips, 2006). Of these 13 billion bbls, 11.3 billion bbls of oil has been extracted. Production rates of oil began to exceed one million bbls in 1969 and peaked in 1987 to 1.6 million bbls a day (Alaska Department of Administration, 2013). Since 1991 daily output began to decline annually at a rate of 7-12% a year; this is shown through Figure 5 (Standing, 2000). Nowadays, the Prudhoe Bay field produces 271,000 bbls of oil a day.

Miscible gas injection is a successful EOR method used in Prudhoe Bay. Miscible gas acts as a solvent, vaporizing the oil from the residual oil content, thus more oil reaches the producing wells (BP, 2006). Once miscible gas is injected, water is then pumped into the reservoir. This method increases efficiency by preventing gas channeling within the reservoir. This EOR method is known as water-alternating-gas. In 1983, the Prudhoe Bay miscible gas project began. The project aimed to optimise the oil recovery of the field by carrying out a number of trials where the amount of miscible gas injected was varied. Each trial was ranked in order of efficiency in terms of produced oil and in respect to the amount of solvent retained in the reservoir (Alaska Oil and Gas Conservation Commission, 1983). The most efficient injection ratio remained which is one of the reasons the ultimate recovery is around 60% of the initial reserves. Of this 60%, the miscible gas injection contributes up to 10% of the recovery in certain areas. This project occurred early in the field’s production increasing the oil production from the onset.

Oil extracted from the Prudhoe Bay field is transported along the Trans-Alaska Pipeline System (TAPS). The TAPS spans from the Prudhoe Bay field to the Valdez Marine terminal located 800 miles away; here up to 7.13 million barrels of oil can be stored which can then be loaded on tankers (Alyeska Pipeline Service Company, 2011). Without the pipeline, resources extracted from the North Slope cannot be monetised as the product cannot reach the market for sale due to the field’s location. The TAPS was the largest privately funded construction when built, costing $8 billion; since then, 16 billions barrels of oil has been transport to the Valdez Marine terminal (ConocoPhillips , 2014). However, the decline of oil output is soon to be an issue; with no investment, the minimum flow rate may occur as soon as 2045, which will lead to the shutdown of the TAPS. This is because, if flow rate is not achieved, corrosion and ice will occur to a greater extent causing the pipe to wrinkle and kink.

Gas is just as important a resource as oil. Since a gas pipeline from the North Slope is non-existent; gas is not marketable as it cannot be transported away from the North Slope. Since startup, the majority of the gas extracted with the oil was re-injected into the reservoir to enhance oil recovery while some supports power the production plants. Gas and water are separated from the oil at a separation plant where the gas is then transported to the world largest central gas facility (CGF) that is located in Prudhoe Bay. The CGF can handle 9 bcf of gas daily and has the world largest smokeless flare where excess gas is burnt. The gas in the CGF is cooled and separated according to the size of the gas particles, the cooling facility alone costs $1 billion to build (BP, 2006). Most of the larger natural gas liquids are mixed with the oil and sent along the TAPS. The rest is mixed with methane giving a miscible gas, which is injected into the reservoir as an EOR method. The unused gas is sent to the central compression plant (CCP), where it is compressed and injected into the reservoir to maintain pressure, which aids oil recovery. Consequently, since production the reservoir pressure has only declined by 1000 psi (4300 to 3300psi) (Weaver and Uldrich, 1999).

The future prospects of the field are less promising due to the depletion of the oil. However, these prospects can be restored if the Alaskan gas pipeline is approved. The Alaska liquefied natural gas project (LNG) would be one of the world’s largest construction projects with estimated costs of $45 billion to $65 billion, funded by Exxon, ConocoPhillips and BP (Alaska Natural Gas Transportation Projects, 2014). The project includes an 800-mile pipeline shown in figure 6 spanning from Prudhoe Bay to Nikiski. LNG carriers would then transport the liquefied natural gas (LNG). The project includes a purpose built liquefaction plants and a gas purifying plant to remove carbon dioxide and other impurities. The pipeline will have the capacity to carry up to 3.5 billion cubic feet of gas, while the LNG plant will be capable of making up to 20 million metric tons of LNG a year (processing 2.5 billion cubic feet a day). This project would allow the gas extracted to be monetised and exported to countries with a free trade agreement with the United States. This includes South Korea, which is the second largest LNG importer (Hong, 2013). This project will increase the field’s economic outcome, attracting further investment.

The productivity of the field is improved by establishing satellite fields. Figure 7 illustrates the 5 satellite fields. The Polaris and Orion satellite field produces the viscous oil in the formation that is difficult to extract at a depth of 4000-5000 ft. In comparison Midnight Sun extracts the hydrocarbon from a sandstone formation at a depth of 8000 ft. The Aurora and Borealis fields are established on similar formations. These fields combined contribute to around 30,000 barrels of oil a day (BP,2013). The satellite fields use existing infrastructure, which meant that the field was being optimised further by increase production while the initial costs were kept low.

It is important to consider the impacts of oil and gas production in Prudhoe Bay. Approximately 2% of the land surface in the region has been altered due to the oil industry. Monitoring species diversity in the region has shown that there is little change due to this alteration. In fact, most animals use the oil field for nesting, breeding and summer forage. Some habitat has been lost which has resulted in some species being localised, however, there was no decline in population. This shows that the impacts of the oil industry on the North Slope are negligible showing sustainable development (Maki, 1992, pp. 1691–1707).

Following the decline in production, exploration was renewed, which led to the discovery of two previously unutilised areas. The areas are in the west region of the field and the Sag River formation, which overlies the main Prudhoe Bay reservoir. Due to the potential of these new areas, BP has increased investment in Alaska by 25% to $1.2 billion. Part of this investment will be used to conduct a 190 square mile seismic survey and a new well pad. It is estimated that the investment may increase production by 40,000bpd, thus reduce the likelihood of the TAPS shutdown as minimum flow rate is easily overcome (Platts, 2014). The Sag River formation is a thin unexploited reservoir in which a 15 well test program will be conducted during 2015 and 2016. The success of this could enable a future 200 wells being built, this may yield 200 million barrels of oil once developed. The Western part of the field hasn’t been fully exploited yet with only the Borealis satellite field tapping into a reservoir that is in a lower position than the main reservoir. Continuing west, the oil column reduces in thickness at times being only 30ft, this is in the Northwest Eileen. Horizontal drilling will be needed to maximize extraction of the thin oil column; this comes with the associated risks of water encroachment on top of the increased cost due to horizontal drilling (Bailey, 2013). Due to these issues, the decision to develop the Northwest Eileen is still in the pipeline and if approved would further increase production rates.

To conclude, the possibilities and the history of Prudhoe Bay make it attractable to investors. Prudhoe Bay is a giant field where majority of the oil has been extracted resulting in a decline in production rates. The TAPS is vital for the success of the field and if minimum flow rate is not achieved then the oil can no longer be transported and sold. Investments to the pipeline will mean that minimum flow rate can be lowered extending the life of the TAPS. There are no plans of abandonment due to the likelihood of future proposals being successful. The liquefied natural gas project alone would be highly profitable and successful for investors as around 40 tcf of gas is still present. If the future exploration projects are successful in areas such as the Sag River formation then oil production will begin to increase. A successful future of the field is dependent of these tests but if encouraging, investors will be in a privileged position.


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