• A comprehensive analysis of the oil fields of the North Slope of Alaska: their use as analogs, recent exploration, and forecasted royalty and production tax revenue

      Michie, Joshua J.; Patil, Shirish; Dandekar, Abhijit; Khataniar, Santanu; Sonwalker, Vikas (2018)
      Revenues from petroleum production supply most of the revenue for unrestricted general funds for the State of Alaska. As such, variations in the price of oil, decline from existing production and new developments greatly affect the money available for the state to spend on everything from roads to education. This study reviewed all producing oil fields on the North Slope, characterized their reservoir performance and forecasted future production. This was coupled with analysis of recent exploration discoveries and ongoing project developments to forecast future North Slope production and create potential royalty and production tax revenue forecasts. After 40 years of production, Prudhoe Bay remains the dominant field on the North Slope, accounting for 45% of current production. Relatively large changes in the non-anchor field pools are only able to change North Slope production by a couple of percent due to the nature of their size compared to Prudhoe Bay, Kuparuk and Alpine. New developments however, are able to materially contribute to changes in North Slope production if they are large enough. With continued activity in the many fields, creating an accurate forecast is challenging, however, without new developments, the Trans Alaska Pipeline will need to make changes to accommodate low flow rates. Currently identified new developments have the potential to extend current production rates 10-20 years. Some of these announced developments and discoveries have announced productivity rates that are not realistic compared to analog well performance, and will likely require many more wells to achieve the announced rates and volumes.
    • Dying intestate or with a will on toxic estate? an evaluation of petroleum fiscal systems and the economic and policy implications for decommissioning of onshore crude oil fields in Nigeria

      Afieroho, Erovie-Oghene Uyoyou-karo; Patil, Shirish L.; Dandekar, Abhijit; Reynolds, Douglas B.; Perkins, Robert (2018-05)
      Many giant fields in the world like the onshore fields in Nigeria which were initially discovered over half a century ago, have begun to see consistent decline in production and profit, and are gradually entering into the economic end of field life or decommissioning phase. Characteristically, in most regions with mature fields, the large multinational oil companies have begun to sell their oil fields to small indigenous companies who may not be financially robust enough to complete the decommissioning, when it occurs. Because of the pervasive societal impact of the oil industry, if an investor fails to properly decommissioning the infrastructure, a responsible government will have to pay for the proper decommissioning, else society will suffer the socioeconomic, political, health and environmental impact. Therefore, society needs to be effectively engaged in the development of a sustainable decommissioning policy framework, which is hindered if society is uninformed and lacks access to pertinent information. Currently, there is abysmal information in the public space on the cost of decommissioning liabilities of oil fields, especially in developing countries like Nigeria. The public also need simple interpretative ways to determine the vulnerability of a county or entity to decommissioning default risk and the imminence of a default risk. Furthermore, there is currently, no way to benchmark the level of maturity or level of preparedness for decommissioning phase such that countries and entities can identify their gaps to a sustainable decommissioning policy framework and define a roadmap to close the gaps. These are important challenges to vigorous public participation, which is an essential requirement for development and implementation of any sustainable public policy for a public issue like decommissioning of crude oil fields. This study adopted several research methods to develop and introduce a new cost estimating methodology that uses publicly declared cost of asset retirement obligations (ARO) to determine a plausible cost estimate range for decommissioning liabilities. It was demonstrated with Nigeria onshore crude oil fields, which it determined to have a rough order of magnitude cost estimate for decommissioning liabilities that could be as high as $3 billion. Secondly, it also introduced decommissioning coverage ratio (DCR) and decommissioning coverage ratio vector (DCRV) as new metrics to evaluate the vulnerability to and imminence of decommissioning default risk. In demonstrating these new metrics, this study determined that the imminence of and vulnerability to decommissioning default risk for the onshore crude oil fields in Nigeria, with respect to any of the available revenue streams, is high. Thirdly, it developed a graded scale maturity model for sustainable decommissioning of petroleum fields. The model described as Fairbanks maturity model for sustainable decommissioning in the petroleum industry, has five progressive levels of maturity. It leveraged the methodology used for similar maturity models developed in other industries and for business management, and a comparative analysis of level of progress in decommissioning frameworks between some countries with leading decommissioning experience in the petroleum industry, to develop the Fairbanks maturity model. Based on the Fairbanks maturity model, frameworks for sustainable decommissioning of Nigeria onshore crude oil fields were evaluated to be at Level 1, Ad hoc maturity level, which is the lowest maturity level. Recommendations to close the identified gaps were also were made. These methodologies can be applied to any petroleum producing region or entity in the world and are advancements to the frontier of knowledge in the management of decommissioning phase for petroleum fields in general and Nigeria onshore fields in particular.
    • Project to demonstrate feasibility of gas production with sensitivities on production schemes on Sterling B4 sands formation

      Yeager, Ronald J.; Patil, Shirish; Ning, Samson; Khataniar, Santanu (2018-04)
      The Sterling B4 reservoir is a low-relief anticline structure underlain by a weak aquifer located on the Kenai Peninsula of Alaska. This dry gas-on-water reservoir, holding approximately 13.9 BCF, has experienced challenges since its first development in the 1960s. The gas-water contact is very mobile and easily influenced upward by gas production. All four wells, largely producing in succession of one another, have experienced excessive water production which killed gas production. Faulty drilling and completion work exacerbated the challenges associated with bringing the gas to market. This project covers an effort to develop the Sterling B4 and determine feasible alternatives for commercialization. Those alternatives include infill drilling, variable production, and co-production. Co-production is a method by which gas is produced from a single upper perforation and water is produced from a lower perforation; each of the streams are produced independently by mechanical means which utilize packers and tubing. The only feasible alternative found by this study is co-production. Of the two coproduction methods analyzed, the highest ultimate recovery includes the utilization of an existing vertical well perforating the upper portion of the reservoir for gas production and a new lower horizontal well perforating the water zone to control the gas-water contact. Modeled production schemes proved the gas-water contact was able to be controlled from upward mobility by maintaining a threshold pressure delta between the bottom-hole pressures of the two producing wells. Utilizing co-production in this manner yielded incremental benefit of over 2 BCF until shut-in limits were triggered. Economic analysis of the project has proved bringing the gas to sales presents a significant prize able to support production and able to support facility operational expense despite no other revenue streams. Should other nearby formations demonstrate sufficient targets the economic case would be enhanced and present an even greater prize.