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Cheng L.,China University of Petroleum - Beijing | Jia P.,China University of Petroleum - Beijing | Rui Z.,Independent Project Analysis Inc. | Huang S.,China University of Petroleum - Beijing | Xue Y.,China University of Petroleum - Beijing
Journal of Natural Gas Science and Engineering | Year: 2017

This paper provides a semi-analytical model to analyze the transient responses of multifractured systems with discrete secondary fractures in unconventional reservoirs. The model idealizes the stimulated reservoir volume as two regions: a primary hydraulic-fracture and discrete secondary fractures. Transient pressure and derivative responses are obtained by coupling an analytical model for matrix flow and a numerical model for fracture flow. This approach can consider the fracture characteristics in detail. For example, the discrete secondary fractures may interconnect the primary hydraulic-fracture with different inclination, nonuniform fracture spacing and varying conductivity. The semi-analytical model was verified in comparison with the results of a fully numerical simulation model. Transient flow behavior of the system was analyzed in detail. The study has shown that a multifractured system with discrete secondary fractures may exhibit four flow regimes: bilinear flow, fluid feed flow, matrix linear flow and pseudosteady-state flow. In the fluid feed flow period, the secondary fractures act as supply sources to feed the primary hydraulic-fracture to generate a dip on the type curves. Local solutions for the matrix linear flow are similar to that for a finite conductivity vertical fracture and can be correlated with the ratio of the total length of the secondary fractures to that of the primary hydraulic-fracture and an intercept term. With the increasing of number of secondary fracture, the ending time of the bilinear flow will be advanced and the fluid feed flow period will come earlier. The dimensionless secondary fracture length determines the slope of the straight line of the matrix linear flow on square-root-dimensionless-time plot. As the secondary fracture inclination decreases, the duration of the matrix linear flow period is shortened and the beginning time of the pseudosteady-state flow period is delayed. In addition, the secondary fracture conductivity affects the depth of the dip and the beginning time of the matrix linear flow period. However, the influence is not appreciable on the log/log graph. © 2017 Elsevier B.V.

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.

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

Fracturing has been identified as a key method for unconventional reservoir development, and it enhances single well productivity and ultimate recovery. Most estimations of fracturing effect are limited to draw boxes around micro-seismic event maps, and add up the 3D volume where micro-seismic events are observed. But the observed volume always is larger which brings error for fracture evaluation. Meanwhile, there is lack of evaluation for the effective permeability, the fracture half-length, the effective stimulated reservoir volume, etc. This paper will present a new method to appraise and diagnose the fracture parameters for shale gas reservoirs qualitatively and quantitatively, which not only can determine the fracture geometry and volume but also determine the fracture parameters, such as effective permeability, fracture half-length, etc. The qualitative evaluation method is combined the relationship table between the fracture geometry and rock brittleness with different pressure response characteristics which can be used to determine the fracture geometry. Then the modern well test analysis method is applied to invert complex fracture parameters for realizing the quantitative evaluation. This method is applied in 3 shale gas wells, and the reasonable interpretation results are achieved with comparison and analysis. The field application results proved that it is a great methodology in shale gas reservoirs. It also can be expanded to other unconventional such as shale gas reservoirs. © 2015 Elsevier B.V.

He J.,University of North Dakota | Rui Z.,Independent Project Analysis Inc. | Ling K.,University of North Dakota
Journal of Natural Gas Science and Engineering | Year: 2016

In recent years, the development of oil and gas from shale has proceeded quickly in the world through the use of multistage fracturing technology in horizontal well. However, without the knowledge of rock poroelastic characteristics, the successful rate of hydraulic fracturing will be low. Among those poroelastic characteristics, effective stress is required for creating artificial fractures in the shale formation. In this study a new method is proposed to measure the Biot's coefficient, which is one of the key poroelastic parameters for calculating the effective stress. The Biot's coefficient is obtained after the variations of both the confining and the pore pressures are recorded with a simplified measuring procedures. The Bakken shale samples from Williston Basin are tested. The experiment results show that the Biot's coefficient of Bakken samples obtained from horizontal drilling and vertical drilling are significantly different from each other. This provides a solid base to scientists and engineers for Bakken in-situ stress analysis during multistage hydraulic fracturing and reservoir depletion due to production. © 2016 Elsevier B.V.

Zhao X.,China University of Petroleum - Beijing | Rui Z.,Independent Project Analysis Inc. | Liao X.,China University of Petroleum - Beijing
Journal of Natural Gas Science and Engineering | Year: 2016

The CO2 storage and CO2 enhanced oil recovery (EOR) in reservoirs often face challenges due to a high heterogeneity, high levels of water saturation, or low permeability. Based on the evaluation method of the CO2 storage capacity and EOR, three typical reservoirs representing these challenges are introduced to study their effect on the CO2 EOR potentials and CO2 storage capacities. The properties of these reservoirs were analyzed in detail, and geological models were built. The reservoir simulation method is adopted to analyze and validate the CO2 injection process and the storage effect for different types of reservoirs. From the examples in this paper, the low permeability reservoirs appear to have a higher EOR potential and CO2 storage capacity than highly heterogeneous reservoirs. These results support the premise of injecting CO2 into reservoirs to decrease atmospheric greenhouse gas emissions while enhancing oil recovery. © 2016 Elsevier B.V.

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.

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.

Nandurdikar N.S.,Independent Project Analysis Inc. | Kirkham P.M.,Independent Project Analysis Inc.
SPE Hydrocarbon Economics and Evaluation Symposium | Year: 2012

Most oil and gas executives and financial analysts have long believed that minimizing the time to first oil is one of the most important parameters to maximize the economic value of exploration and production (E&P) projects. This belief has driven project teams and oil company executives to push ever faster schedules. Our data show that chasing fast project schedules inadvertently destroys more value than it creates. We use a detailed database of oil and gas projects to conduct a rigorous statistical analysis, comparing project economics promised at sanction to the actual results achieved. Using performance data from the database, we can statistically quantify the change in expected outcomes (cost, production, reserves), and therefore the net present value (NPV) realized, as a result of different schedule targets. The results show that chasing aggressive first oil dates has a consistent negative effect on NPV because of worse than expected cost and production attainment. These effects are more damaging than the loss of value that occurs if a project is slowed down early in the project cycle to improve the quality of front-end preparation and planning that helps to mitigate cost and production attainment shortfalls. When speed becomes paramount, reservoir appraisal and project definition phases are shortened projects proceed without high-quality basic subsurface data, and often short-cut crucial planning phases. As the quality of data and planning degrades, teams are forced to make more assumptions, which increases uncertainty in cost, production, and reserves estimates. During execution, these major uncertainties, along with incomplete data and planning, drive cost growth, reserves downgrades, production shortfalls and, ironically, schedule slip. The poor than expected outcomes have a negative influence on the project economics, but are often ignored by economic models. In all projects there are choices to be made that lead to trade-offs between cost, schedule and production. Many companies prioritize their focus primarily on meeting their schedule and then, cost targets in order to achieve maximum economic returns. The reason production is often not part of the trade-off is because because of the belief that there is no trade-off between schedule and production, only between schedule and cost. Our analysis provides evidence to the contrary leading us to conclude that the order of priority should be reversed. We go beyond this observation and provide the reader with insights into how the unintended consequences of certain project drivers can be incorporated into more realistic economic models. Copyright 2012, Society of Petroleum Engineers.

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.

Rui R.,Independent Project Analysis Inc. | Walker J.,Independent Project Analysis Inc.
Proceedings - SPE Annual Technical Conference and Exhibition | Year: 2014

Offshore facility weight is significantly related to the cost, schedule, and complexity of offshore facility projects. Therefore, controlling offshore facilities weight growth is important to project success. This paper sought to understand weight growth among different project phases and its causes. Using Independent Project Analysis, Inc.'s (IPA's) detailed database of oil and gas projects, we conducted a rigorous statistical analysis of offshore weight growth to identify the root cause(s). This paper evaluates the offshore facilities weight growth for 153 global offshore projects at the end of the concept selection and authorization gates. The study results show that industry weight growth is much higher than expected. Although Industry typically allocates 13 percent of dry weight for weight contingency at the end of Front-End Loading (FEL) 2 and 6 percent of dry weight at authorization to account for unexpected weight growth, half of the topsides had more than 10 percent weight growth, and more than one in three substructures had more than 10 percent weight growth from authorization to completion. There is a large gap between the estimated weight contingency and the actual amount spent for these projects. This analysis shows that most offshore facilities weight growth is caused by poor engineering status for the facilities at authorization. The analysis also shows that setting aggressive schedule targets erodes the benefits of good engineering definition. In general, projects with good engineering and aggressive schedule targets have an extra 9 percent weight growth compared to projects with good engineering and non-aggressive schedule targets. Offshore facilities weight growth was found across many different offshore facility concepts (e.g., fixed platforms, spars, tension-leg platforms, etc.). This research provides an understanding of industry offshore facilities weight performance and the main causes of weight growth, and offers recommendations for improving weight predictability. Copyright © 2014, Society of Petroleum Engineers.

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