Methods of Decline Curve Analysis for Shale Gas Reservoirs

Tan, Lei; Zuo, Lihua; Wang, Binbin

doi:10.3390/en11030552

Cited by 62 publications

(36 citation statements)

References 63 publications

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“…With the rapid development of the global economy, the discrepancy between oil and gas supply and demand has become more prominent in most countries. The shortage of oil and gas has become one of the main bottlenecks restricting economic and social development [1][2][3]. Our location to explore energy resources has changed from the land to the ocean, and offshore oil and gas will become important energy resources in the future [4][5][6].…”

Section: Introductionmentioning

confidence: 99%

Hydrate Formation and Decomposition Regularities in Offshore Gas Reservoir Production Pipelines

et al. 2020

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In recent years, the exploitation and utilization of offshore oil and gas resources have attracted more attention. In offshore gas reservoir production, wellbore temperature and pressure change continuously when water-bearing natural gas flows upward. The wellbore temperature is also affected by the low-temperature sea water. The combination of temperatures and pressures controlled by the upward flow, and cooling from the surrounding seawater frequently leads to the conditions of temperature and pressure for hydrate formation. This can lead to pipeline blockage and other safety accidents. In this study, we utilize mathematical models of hydrate phase equilibrium, wellbore temperature, wellbore pressure to study hydrate formation and decomposition in offshore gas reservoir production. Numerical solution algorithms are developed and numerical solutions are validated. The sensitivity influence of different parameters on the regions and regularities of hydrate formation and decomposition in wellbores are obtained through numerical simulations. It is found that increased daily gas production, water content, or geothermal gradient in offshore gas reservoir production pipelines results in less hydrate formation in the wellbores. Accordingly, the risk of wellbore blockage decreases and production safety is maintained. Decreased tubing head pressure or seawater depth results in similar effects. The result of this study establishes a set of prediction methods for hydrate formation and decomposition that can be used in the development of guidelines for safe construction design.

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Section: Introductionmentioning

confidence: 99%

Hydrate Formation and Decomposition Regularities in Offshore Gas Reservoir Production Pipelines

et al. 2020

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“…Well-established flow and transport theory for conventional reservoir rocks are not directly applicable to unconventional porous media (Gensterblum et al, 2015). For decades, researchers have been investigating the storage and transport mechanisms for unconventional reservoirs, which includes gas desorption, adsorbed gas porosity, gas slippage, and Knudsen diffusion, etc (Javadpour et al, 2007;Wang and Reed, 2009;Civan et al, 2010Civan et al, ,2011Sakhaee and Bryant, 2012;Akkutlu and Fathi, 2012, Yu et al, 2016and Tan et al, 2018. In addition, the fractured shale matrix is comprised of a hierarchical network of pores down to a few nanometers, cracks and micro-fractures, which makes the formation a multi-scale porous medium with large heterogeneity and anisotropy (Akkutlu et al, 2018).…”

Section: Introductionmentioning

confidence: 99%

MRST-Shale: An Open-Source Framework for Generic Numerical Modeling of Unconventional Shale and Tight Gas Reservoirs

Wang¹

2020

Preprint

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We present a generic and open-source framework for the numerical modeling of the expected transport and storage mechanisms in unconventional gas reservoirs. These unconventional reservoirs typically contain natural fractures at multiple scales. Considering the importance of these fractures in shale gas production, we perform a rigorous study on the accuracy of different fracture models. The framework is validated against an industrial simulator and is used to perform a history-matching study on the Barnett shale. This work presents an open-source code that leverages cutting-edge numerical modeling capabilities like automatic differentiation, stochastic fracture modeling, multi-continuum modeling and other explicit and discrete fracture models. We modified the conventional mass balance equation to account for the physical mechanisms that are unique to organic-rich source rocks. Some of these include the use of an adsorption isotherm, a dynamic permeability-correction function, and an embedded discrete fracture model (EDFM) with fracture-well connectivity. We explore the accuracy of the EDFM for modeling hydraulically-fractured shale-gas wells, which could be connected to natural fractures of finite or infinite conductivity, and could deform during production. Simulation results indicates that although the EDFM provides a computationally efficient model for describing flow in natural and hydraulic fractures, it could be inaccurate under these three conditions: 1. when the fracture conductivity is very low. 2. when the fractures are not orthogonal to the underlying Cartesian grid blocks, and 3. when sharp pressure drops occur in large grid blocks with insufficient mesh refinement. Each of these results are very significant considering that most of the fluids in these ultra-low matrix permeability reservoirs get produced through the interconnected natural fractures, which are expected to have very low fracture conductivities. We also expect sharp pressure drops near the fractures in these shale gas reservoirs, and it is very unrealistic to expect the hydraulic fractures or complex fracture networks to be orthogonal to any structured grid. In conclusion, this paper presents an open-source numerical framework to facilitate the modeling of the expected physical mechanisms in shale-gas reservoirs. The code was validated against published results and a commercial simulator. We also performed a history-matching study on a naturally-fractured Barnett shale-gas well considering adsorption, gas slippage & diffusion and fracture closure as well as proppant embedment, using the framework presented. This work provides the first open-source code that can be used to facilitate the modeling and optimization of fractured shale-gas reservoirs. To provide the numerical flexibility to accurately model stochastic natural fractures that are connected to hydraulically-fractured wells, it is built atop other related open-source codes. We also present the first rigorous study on the accuracy of using EDFM to model both hydraulic fractures and natural fractures that may or may not be interconnected.

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“…Thus, traditional DCA commonly overestimates EURs of shale wells [7,8]. In early 2019, the Wall Street Journal (WSJ) published an article entitled "Fracking's Secret Problem-Oil Wells Aren't Producing as Much as Forecast" [9,10].…”

Section: Introductionmentioning

confidence: 99%

“…To predict EUR, assume -somewhat optimistically -that deviation from the line starts at τ = 2 × t max . Thus, the corresponding M can be calculated asM = (K √ t max )/RF( 1 2 ), where RF( 1 2 ) is calculated fromEquation(8). Finally, EUR is calculated from Equation(10).…”

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confidence: 99%

Physical Scaling Predicts Oil Production Rates and Ultimate Recovery from All Horizontal Wells in the Bakken Shale

Saputra¹,

Kirati²,

Patzek³

2019

Preprint

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A recent study by the Wall Street Journal reveals that the hydrofractured horizontal wells in shales have been producing less than forecasted by the industry with the empirical hyperbolic decline curve analysis (DCA). As an alternative to DCA, we introduce a simple, fast and accurate method of estimating ultimate recovery (EUR) in oil shales. We adopt a physics-based scaling approach to analyze oil rates and ultimate recovery from 14,888 active horizontal oil wells in the Bakken shale. To predict EUR, we collapse production records from individual horizontal shale oil wells onto two segments of a master curve: (1) We find that cumulative oil production from 4,845 wells is still growing linearly with the square root of time; and (2) 6,401 wells are already in exponential decline after approximately seven years on production. In addition, 2,363 wells have discontinuous production records, because of refracturing or changes in downhole flowing pressure, and are matched with a linear combination of scaling curves superposed in time. The remaining 1,279 new wells with less than 12 months on production have too few production records to allow for robust matches. These wells are scaled with the slopes of other comparable wells in the square-root-of-time flow regime. In the end, we predict that total ultimate recovery from all existing horizontal wells in Bakken will be some 4.5 billion barrels of oil. We also find that wells completed in the Middle Bakken formation, in general, produce more oil than those completed in the Upper Three Forks formation. The newly completed longer wells with larger hydrofractures have higher initial production rates, but they decline faster and have EURs similar to the cheaper old wells. There is little correlation among EUR, lateral length, and the number and size of hydrofractures. Therefore, technology may not help much in boosting production of new wells completed in the poor immature areas along the edges of the Williston Basin. Operators and policy-makers may use our findings to optimize the possible futures of the Bakken shale and other plays. More importantly, petroleum industry may adopt our physics-based method as an alternative to the overly-optimistic hyperbolic DCA that yields an "illusory picture" of shale oil resources.

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Methods of Decline Curve Analysis for Shale Gas Reservoirs

Cited by 62 publications

References 63 publications

Hydrate Formation and Decomposition Regularities in Offshore Gas Reservoir Production Pipelines

Hydrate Formation and Decomposition Regularities in Offshore Gas Reservoir Production Pipelines

MRST-Shale: An Open-Source Framework for Generic Numerical Modeling of Unconventional Shale and Tight Gas Reservoirs

Physical Scaling Predicts Oil Production Rates and Ultimate Recovery from All Horizontal Wells in the Bakken Shale

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