石油工程师协会技术年会论文spe166120
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SPE 166120 Modeling Wellbore Transient Fluid-Temperature and -Pressure During Diagnostic Fracture Injection Testing in Unconventional Reservoirs
B. Nojabaei, SPE, Penn State U., A.R. Hasan, SPE, Texas A&M University, and C.S. Kabir, SPE, Hess Corp
Abstract Diagnostic fracture injection testing or DFIT has gained widespread usage in the evaluation of unconventional reservoirs. The DFIT entails injection of water above the formation-parting pressure, followed by a long-duration pressure falloff test. This test is a pragmatic way of gaining critical reservoir information, such as the formation-parting pressure, fracture-closure pressure, and initial-reservoir pressure, leading to fracture-completion design and reservoir-engineering calculations. In typical field operations, pressure is measured at the wellhead, not at the bottomhole, because of cost considerations. The bottomhole pressure (BHP) is obtained by simply adding a constant hydrostatic head of the water column to the wellhead pressure (WHP) at each timestep. Questions arise whether this practice is sound because of significant changes in temperature that occur in the wellbore, leading to changes in density and compressibility throughout the fluid column. The paper explores this question and offers an analytical model for estimating the transient temperature at a given depth and timestep for computing the BHP. Furthermore, based on the premise of line-source well, we showed that the early-time data can be represented by the square-root of time formulation, leading to the new modified-Hall relation for the injection period. Introduction Historically, many studies have explored various interpretation aspects of diagnostic fracture injection tests or DFIT in unconventional shale reservoirs, encompassing micro- to nano-darcy formations. Some of these studies include those of Mayerhofer et al. (1995), Abousleiman et al. (1994), Soliman et al. (2005, 2010, 2011), Craig et al. (2005), Barree et al. (2009), Soliman and Kabir (2012), and Nojabaei and Kabir (2012), among others. DFIT entails inducing a hydraulic fracture by injecting a small volume of fluid into the formation and shutting the well in for a long-duration falloff. Typically, this type of test allows estimation of pfb, pfc, initial reservoir pressure (pi), the leakoff type, and some measure of formation conductivity. The injection period leads to the determination of pfb, whereas the falloff analysis yields the remaining parameters. The use of bottomhole pressure is implicit in all interpretation methods. However, the economic reality in field operations suggests the use of wellhead pressures in most settings. Questions arise whether the WHP data lend themselves for transient interpretation without rigorous wellbore modeling, given significant changes in water density and compressibility as a function of shut-in time. Although compressibility of water is much lower than that of hydrocarbons, relevant papers (Kabir and Hasan 1998, Izgec et al. 2009) pointing out gauge placement issues in conventional gas and oil reservoirs suggest that this question merits thorough vetting. Accordingly, this paper expands upon the previous study of Nojabaei and Kabir (2012) for translating WHP into BHP with a transient wellbore-heat-transfer model. Note that the contribution of friction to total pressure loss during a typical 5 bbl/min injection in a 4-in. ID casing is less than 0.2% of the total, and that this minimal contribution does not change with time. Therefore, adding hydrostatic head to the WHP for estimating BHP is a sound practice. However, the changes in pressure and temperature with time and depth cause density variation of the injected water, leading to a variation of hydrostatic head with time that warrants careful examination. Therefore, we explored the validity of the constant hydrostatichead correction with focus on the the pressure falloff period. This study presents an analytical fluid-temperature model as a more rigorous determination of BHP. Applications include confident analysis of injection data, such as with the modifiedHall method.
Copyright 2013, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Annual Technical Conference and Exhibition held in New Orleans, Louisiana, USA, 30 September–2 October 2013. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and 百度文库re subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.
B. Nojabaei, SPE, Penn State U., A.R. Hasan, SPE, Texas A&M University, and C.S. Kabir, SPE, Hess Corp
Abstract Diagnostic fracture injection testing or DFIT has gained widespread usage in the evaluation of unconventional reservoirs. The DFIT entails injection of water above the formation-parting pressure, followed by a long-duration pressure falloff test. This test is a pragmatic way of gaining critical reservoir information, such as the formation-parting pressure, fracture-closure pressure, and initial-reservoir pressure, leading to fracture-completion design and reservoir-engineering calculations. In typical field operations, pressure is measured at the wellhead, not at the bottomhole, because of cost considerations. The bottomhole pressure (BHP) is obtained by simply adding a constant hydrostatic head of the water column to the wellhead pressure (WHP) at each timestep. Questions arise whether this practice is sound because of significant changes in temperature that occur in the wellbore, leading to changes in density and compressibility throughout the fluid column. The paper explores this question and offers an analytical model for estimating the transient temperature at a given depth and timestep for computing the BHP. Furthermore, based on the premise of line-source well, we showed that the early-time data can be represented by the square-root of time formulation, leading to the new modified-Hall relation for the injection period. Introduction Historically, many studies have explored various interpretation aspects of diagnostic fracture injection tests or DFIT in unconventional shale reservoirs, encompassing micro- to nano-darcy formations. Some of these studies include those of Mayerhofer et al. (1995), Abousleiman et al. (1994), Soliman et al. (2005, 2010, 2011), Craig et al. (2005), Barree et al. (2009), Soliman and Kabir (2012), and Nojabaei and Kabir (2012), among others. DFIT entails inducing a hydraulic fracture by injecting a small volume of fluid into the formation and shutting the well in for a long-duration falloff. Typically, this type of test allows estimation of pfb, pfc, initial reservoir pressure (pi), the leakoff type, and some measure of formation conductivity. The injection period leads to the determination of pfb, whereas the falloff analysis yields the remaining parameters. The use of bottomhole pressure is implicit in all interpretation methods. However, the economic reality in field operations suggests the use of wellhead pressures in most settings. Questions arise whether the WHP data lend themselves for transient interpretation without rigorous wellbore modeling, given significant changes in water density and compressibility as a function of shut-in time. Although compressibility of water is much lower than that of hydrocarbons, relevant papers (Kabir and Hasan 1998, Izgec et al. 2009) pointing out gauge placement issues in conventional gas and oil reservoirs suggest that this question merits thorough vetting. Accordingly, this paper expands upon the previous study of Nojabaei and Kabir (2012) for translating WHP into BHP with a transient wellbore-heat-transfer model. Note that the contribution of friction to total pressure loss during a typical 5 bbl/min injection in a 4-in. ID casing is less than 0.2% of the total, and that this minimal contribution does not change with time. Therefore, adding hydrostatic head to the WHP for estimating BHP is a sound practice. However, the changes in pressure and temperature with time and depth cause density variation of the injected water, leading to a variation of hydrostatic head with time that warrants careful examination. Therefore, we explored the validity of the constant hydrostatichead correction with focus on the the pressure falloff period. This study presents an analytical fluid-temperature model as a more rigorous determination of BHP. Applications include confident analysis of injection data, such as with the modifiedHall method.
Copyright 2013, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Annual Technical Conference and Exhibition held in New Orleans, Louisiana, USA, 30 September–2 October 2013. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and 百度文库re subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.