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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 198192, “Production Performance Evaluation From Stimulation and Completion Parameters in the Permian Basin: Data-Mining Approach,” by Mustafa A. Al-Alwani, SPE, and Shari Dunn-Norman, SPE, Missouri University of Science and Technology, and Larry K. Britt, SPE, NSI Fracturing, et al., prepared for the 2019 SPE/AAPG/SEG Asia Pacific Unconventional Resources Technology Conference, 18–19 November, Brisbane, Australia. The paper has not been peer reviewed. The complete paper uses 3,782 unconventional horizontal wells to analyze the effect of proppant volume and the length of the perforated lateral on short- and long-term well productivity across the Permian Basin. Tying cumulative production to completion and stimulation practices showed that increasing pumped proppant per well from 5 million to less than 10 million lbm yielded a 34% increase in 5-year cumulative average barrels of oil equivalent (BOE). Raising the pumped proppant per well to 10 million-15 million lbm and 15 million-20 million lbm increased 5-year cumulative BOE from the previous proppant range group to 27% and 18.5%, respectively. Introduction For this study, stimulation chemical data from Permian (Midland) Basin wells were downloaded from FracFocus for all horizontal wells completed and stimulated between 2012 and 2018. The data were then subjected to rigorous cleaning and processing, a process detailed in the complete paper, and then combined with DrillingInfo completion and production parameters. Combining these data provided ample parameters for stimulation, completion, and production data. The objective of the study was to investigate the production performance of Permian Basin wells as a result of different ranges of stimulation and completion parameters. Fig. 1 shows a database representation of the major counties in the Permian Basin with the number of wells in each county. Results and Discussion To substitute for any quantities of produced gas, all production data have been converted to BOE by using the conversion factor of 1 BOE=6 Mcf. The amount of proppant being pumped and the length of the perforated lateral length have been selected to represent the stimulation size and the completion magnitude, respectively.
This paper (SPE 52017) was revised for publication from paper SPE 49178, prepared for the 1998 SPE Annual Technical Conference and Exhibition, New Orleans, 27 30 September. Original manuscript received 17 June 1998. This paper has not been peer reviewed. Summary Hydrocarbon reserves and the ability to produce them profitably are the lifeblood of the upstream petroleum industry. Aggressive competition, ever-sharpening scrutiny by the investment community, and volatile product prices drive companies to search for attractive new E&P venture opportunities that will add the greatest value for a given investment. Production-sharing and other related nontraditional agreement types have become popular because they provide host countries with the flexibility to tailor fiscal terms to fit their sovereign needs. However, actual agreement terms, including those that relate to royalty payments, cost recovery, profit sharing, and taxes, can have a significant impact on the statistics that the investment community uses to access and rank the performance of a petroleum company. This paper examines the impact of these terms and of product-price volatility on investment-community performance statistics, such as reserves replacement; unit exploration, development, and operating costs; and earnings. Representative examples demonstrate the variation in these performance statistics with variations in product price. Limitations in the various indicators are highlighted. P. 50
Abstract The paper evaluates the economic and financial viability gy of flaring reduction options in a selected field in Nigeria. ia. Consequently, this research will focus on Identifications of current options in gas utilization. Factors affecting the selection of a particular option. Nigeria flares 17.2 billion m3 of natural gas per year in i the Niger Delta. The natural gas flared is more than any ther country in the world. Nigeria has reserves of about 187 trillion cubic feet of natural gas, and 3.5 billion cubic feet (1,000,000,000.m3) of Associated Gas (AG) produced ann annually, 2.5 billion cubic feet (70,000,000m3), or about 70% is wasted as a result of flaring. This equals about 25% of UK's total natural gas consumption and it's the equivalent of about 40% of the entire African continents gas consumption in 2001. The annual gas wasted due to flaring g is estimated to cost the country about $2.5 billion annually. This gas flaring expends huge amount of energy and causes environmental degradation and this paper focuses on the benefits that can be derived from gas and its impact on the local economy and the environment. Global Gas Flaring Reduction (GGFR) initiative was used to perform an economic and financial analysis. Using inputs like, daily gas production, price of diesel and fuel, distance to power grid amongst others. This paper therefore concludes that the local livelihood in the Niger Delta will be significantly improved by promoting a shift from gas flaring to gas gathering for use as a gaseous fuel and for electricity generation. Also, environmental prone diseases will be reduced and agriculture will be enhanced in the Niger delta area. Although there is a great technical and cost involvement, this project is a worthy investment. The gas flare-down will also help to combat Global climate change which United Nations Environment programme (UNEP) is advocating throughout the world in Copenhagen in December 2009 which is mostly caused by global warming.
Abstract Gas-to-power electricity generation is an effective means by which oil and gas companies can move natural gas from both onshore and offshore reserves to the market. But due to the peculiar risks in developing regions like Nigeria, very little progress has been made in project capitalization in this energy sector. In this paper, an integrated economic model, made up of the basic cash flow, scenario, and risk simulation analyses has been developed. Authors of similar works stopped at this level. But here, based on projects' risk profile, companies equipped with their risk aversion levels (1/investment capital initially) can obtain their risk-discounted profits and hence able to decide whether to invest or not. Decisions on best shares for capitalization can also be obtained in real time. A gas-to-power System of 5 MMscfd gas supply generating 14.4MW electricity was used as the test project. A 20-year project life was assumed. The results show that the natural gas supply aspect of the project is more profitable, earning US$1.84 per US$1.00 investment as against US$1.29 for the power generation. Profits of gas-to-power projects are mostly affected by changes in gas and electricity prices and supply reliabilities. For capitalization, investor A, an independent oil company with US$10 million investment capital can capitalize this project all alone (100% best share) obtaining a risk-discounted profit of US$4.34million. But investors B and C with US$2million and US$1.33million capital would have to share in 60%:40% project participation ratio earning US$1.55million and US$1.03million respectively to profitably capitalize the project. With this model, gas-to-power risks are proactively identified, evaluated and communicated for effective decision-making. Best shares for profitable project capitalization even in a developing economy like Nigeria are easily determined. INTRODUCTION Olukoga has reported that Nigeria, the most populous and petroleum-rich West African nation has massive gas reserves currently estimated at 161 trillion cubic feet. For example, as at 1997, the Liquefied Natural Gas (LNG) project proposed for export over a 20 year-period constitutes only about 12 percent of the available natural gas. He also showed the extent to which this valuable resource has been wasted over the years. As at 2002, 2,100mmscf (or 60%) of the over 4,000mmscf daily production was being flared. In addition to the pollution of the environment this has caused, such gas could have been harnessed for a profit to the nation.
Abstract Enhanced oil recovery (EOR) schemes have been slow to evolve in the exploitation of hydrocarbons from the UK Continental Shelf. They are generally much more expensive to execute offshore than in onshore USA where they are relatively common. This paper provides a detailed analysis of the economic aspects of several EOR projects namely low salinity waterflood, polymer flood, and miscible gas injection. Detailed economic modelling of example schemes finds that, in current circumstances in the UKCS, prospective returns, while worthwhile in undiscounted cash flow terms, are only very modest at discount rates reflecting the cost of capital. It is also noted that there are several significant investment risks. Further tax incentives relating to the purchase of polymer and miscible gas could enhance returns to these EOR projects without introducing any distortions.