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Rui Z.,Independent Project Analysis Inc.
Oil and Gas Journal | Year: 2012

Analysis of Alaska natural gas supply and demand shows an Alaska in-state gas pipeline is critically needed. An LNG plant is also necessary for an Alaska in-state gas pipeline project to accommodate strong seasonal swings in Alaskan natural gas demand. A discussion covers fuel use or loss, which is the amount of natural gas consumed by pipeline transportation, the gas treatment plant, and the LNG plant; pipeline and compressor station costs; three major design modes for building a gas pipeline in Alaska; the NERA model, which provides the basis to develop Alaskan in-state gas pipeline models with Monte Carlo simulations and new assumptions; and capital cost of Alaskan in-state gas pipelines. Source


Rui Z.,Independent Project Analysis Inc.
Oil and Gas Journal | Year: 2012

Construction of an Alaska in-state natural gas pipeline is feasible at any of three flow rate scenarios: 500 MMcfd, 750 MMcfd, and 1,000 MMcfd. Selection of a particular rate depends on specific conditions and perspectives. The lack of sufficient natural gas production from Cook Inlet, however, led to the closure of the Agrium fertilizer plant near Kenai in 2007 and the formal closure of the Kenai LNG export plant in 2011, even though it has continued to lift cargoes on individual contract basis to meet post-earthquake Japanese demand. The shortage of gas in South central Alaska has become a major concern for the state, despite technologically recoverable natural gas reserves of roughly 35 tcf. The most viable solution for continuing to supply Alaska with low-cost gas is to bring future supplies from ANS fields to south central Alaska. Source


Rui Z.,Independent Project Analysis Inc. | Wang X.,University of Alaska Fairbanks
International Journal of Oil, Gas and Coal Technology | Year: 2013

The objective of this paper is to provide a reference database for pipeline companies and/or regulators with an investigation of safety performance of US natural gas distribution pipelines. With a total of 3,679 natural gas distribution pipeline incidents between 1985 and 2010, nine safety indicators are statistically analysed in terms of the year, pipeline length, regions, pipeline diameter, pipeline wall thickness, material, age, incident area and incident cause to identify the relationship between safety indicators and various variables. Overall average frequencies of incidents, injuries and fatalities between 1985 and 2009 are 0.0846/1,000 mile-years, 0.0407/1,000 mile-years, and 0.0094/1,000 mile-years respectively. The analysis shows that the safety performance of US natural gas distribution pipeline is improving over time, and different variables have different impact on safety performances. However, the number of annual incidents does not show a significant decline due to increasing energy demand. Copyright © 2013 Inderscience Enterprises Ltd. Source


Zhao Y.,China University of Geosciences | Rui Z.,Independent Project Analysis Inc.
International Journal of Oil, Gas and Coal Technology | Year: 2014

This study aims to provide a reference for pipeline compressor station construction costs by analysing individual compressor station cost components using historical compressor station cost data between 1992 and 2008. Distribution and share of these pipeline compressor station cost components are assessed based on compressor station capacity, year of completion, and locations. Average unit costs in material, labour, miscellaneous, land, and total costs are $866/hp, $466/hp, $367/hp, $13/hp, and $1,712/hp, respectively. Primary costs for compressor stations are material cost, approximately 50.6% of the total cost. This study conducts a learning curve analysis to investigate the learning rate of material and labour costs for different groups. Results show that learning rates and construction component costs vary by capacity and locations. This study also investigates the causes of pipeline compressor station construction cost differences. [Received: March 25, 2012; Accepted; 20 February 2013]. Copyright © 2014 Inderscience Enterprises Ltd. Source


Zhao X.,China University of Petroleum - Beijing | Rui Z.,Independent Project Analysis Inc. | Liao X.,China University of Petroleum - Beijing | Zhang R.,Colorado School of Mines
Journal of Natural Gas Science and Engineering | Year: 2015

A simulation method to determine shale gas well productivity is developed based on modified isochronal well testing. The method is reliable and accurate and reduces the well testing time. First, the physical properties and wellbore parameters of the reservoir are obtained using the production data analysis method or well testing method. Then the production sequence and time sequence are determined. The production sequence is estimated by the production data analysis method, which can calculate gas well production under different pressures. The testing time interval and duration are determined by using the time value of the inflection points on the curve of the productivity coefficient and the time sequence. A modified isochronal well testing simulation model is developed based on the dynamic change patterns of the reservoir and well tubing, the production sequence, and time sequence. Finally, the simulation model is solved by the conventional production well test regression method, and the well productivity and open flow potential are calculated. Using a shale gas well in the Changqing oilfield, China, as a case study, field test results and simulation result are analyzed and compared. The results confirm the reliability of the new method in a shale gas reservoir; the precision of the shale gas productivity evaluation improved and the cost and duration of the test were reduced. This method can be expanded to other unconventional tight gas reservoirs. © 2015. Source

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