Research Article  Open Access
Kongjie Wang, Lian Wang, Caspar Daniel Adenutsi, Zhiping Li, Sen Yang, Liang Zhang, Lan Wang, "Analysis of Gas Flow Behavior for Highly Deviated Wells in Naturally FracturedVuggy Carbonate Gas Reservoirs", Mathematical Problems in Engineering, vol. 2019, Article ID 6919176, 13 pages, 2019. https://doi.org/10.1155/2019/6919176
Analysis of Gas Flow Behavior for Highly Deviated Wells in Naturally FracturedVuggy Carbonate Gas Reservoirs
Abstract
To improve the carbonate gas reservoir development and production, highly deviated wells (HDW) are widely used in the field. Production decline analysis of HDW is crucial for longterm gas reservoir development. However, it is a new challenge to incorporate the complex pore structure of naturally fracturedvuggy carbonate gas reservoirs and evaluate the production performance of HDW. This paper presents a semianalytical model to analyze the pressure and production behavior of HDW in naturally fracturedvuggy carbonate gas reservoirs, which consist of fractures, vugs, and matrix. The primary flow occurs only through the fracture and the outer boundary is closed. Introducing pseudopressure and pseudotime, the Laplace transformation, Fourier transformation, and its inverse and Stehfest numerical inversion were employed to establish a point source and line source solutions. Furthermore, the validity of the proposed model was verified by comparing a field data from the Arum River Basin in Turkmenistan. Finally, the effects of major parameters on the production decline curves were analyzed by using the proposed model and it was found that they had influences at different stages of gas production history and the sensitivity intensity of each parameter was different. With its high efficiency and simplicity, this semianalytical model will serve as a useful tool to evaluate the well production behavior for the naturally fracturedvuggy carbonate gas reservoirs.
1. Introduction
Carbonate gas reservoirs are widely distributed throughout the world. In these carbonate reservoirs, the original gas in place (OGIP) and gas production account for more than half of gas reserves and production in the world [1]. Carbonate gas reservoirs commonly have extremely complex porous structures. This mainly comprises three types of pores, which are matrix, natural fractures, and vugs with different degrees of development. Thus, gas flow in carbonate gas reservoirs show characteristics of multipleporosity system [2]. To improve gas reservoir development and production, highly deviated wells (HDW) are widely used [3]. A new challenge that arises from the application of this technology to improve reservoir development is the difficulty in analyzing and predicting the production behaviors of HDW in naturally fracturedvuggy carbonate gas reservoirs.
In the past decades, a lot of researchers reported some relevant works. The theory and applications on dualporosity flow model for fractured reservoirs have been well researched [4–8]. The dualporosity model was first proposed by Warren and Root in which it was assumed that the reservoir has matrix blocks with low permeability but high porosity and the fracture system with high permeability but low porosity [9]. Based on this model, Bourdet and Gringarten introduced a loglog analysis model with wellbore storage and skin in dualporosity systems [10]. Jalali and Ershaghi established a pressure transient model for carbonate reservoirs on semilog plots and found that the slope characteristics of the transition cover an embracing spectrum [11]. EiBanbi extended previous analytical models to develop a catalog of linear flow causes, models, and solutions for dualporosity linear reservoirs, dualporosity radial reservoirs, and dualporosity channel reservoirs [12]. YingLan et al. represented a dualporosity model within a porousvuggy carbonate reservoir that does not introduce the fracture system [13].
Reservoirs composed of matrix, fracture, and vugs are called tripleporosity systems. A lot of tripleporosity models have been proposed through analytical, semianalytical, and numerical methods for analyzing gas flow in fracturedvuggy carbonate reservoirs. With regard to analytical methods, a tripleporosity and singlepermeability model was first proposed by Abdassah and Ershaghi [14]. The authors considered an unsteadystate interporosity flow model between the fractures and the others, which is a more realistic representation. AlGhamdi and Ershaghi presented a tripleporosity dualpermeability model to characterize fracture heterogeneities, which considered discontinuous matrix and two continuous fracture networks, microfractures and macrofractures [15]. Later, another tripleporosity dualpermeability model was proposed to characterize vuggy porosity, coexisting with matrix and fractures in carbonate reservoir by CamachoVelázquez et al. [16]. Wu et al. presented an analytical method for pressure transient analysis in fracturedvuggy carbonate reservoir that relied on a triplecontinuum concept [17]. Lately, Wang et al. developed a model for transient flow analysis of acid fracturing wells in fracturedvuggy carbonate reservoirs [18]. With regard to semianalytical and numerical methods, Gulbransen et al. proposed a multiscale mixed finite element method for modeling fracturedvuggy carbonate reservoirs [19]. Li et al. built a coupled StokedDarcy model for estimating the equivalent permeability tensor and modeling twophase flow with a full permeability tensor in a fracturevug media system [20]. Zhang et al. presented a new numerical model that considered the effect of geomechanics on fractures and vugs [21]. For upscaling fracturedvuggy reservoir models, Gao et al. introduced a numerical model that consisted of four different porosity systems, i.e., the matrix, fractures, isolated vugs, and connected vugs [22].
A substantial amount of research has focused on the pressure behavior and production performance of deviated wells. Abbaszadeh and Hegeman first proposed analytical solution for the pressure drawdown behavior of a deviated limitedentry well with different combinations of boundaries. The authors used the method of source and Green’s functions to derive these solutions [23]. Ozkan and Raghavan presented a solution for a deviated limitedentry well in an infinite reservoir with noflow top and bottom boundaries by employing the Laplace transformation [24]. Harmohan et al. introduced a method of numerical simulation to analyze the pressure transient behavior of deviated wells that intersect high permeability layers between two low permeability layers [25]. Based on rigorous derivation, Wang et al. presented a transient pressure solution for deviated wells, which reduced the amount of computation and significantly improved the computational efficiency [26]. In a recent work, Meng et al. proposed a semianalytical model of HDW for evaluating the pressure behavior which considered the stresssensitive performance in fracturedvuggy carbonate gas reservoirs with composite systems [27]. Zhao et al. built a new model for evaluating inflow performance of HDW in anisotropic reservoirs, which was proposed by introducing the anisotropic quantitative characterization method [28].
Currently, only few suitable analytical models exist to evaluate the production behavior of HDW in fracturedvuggy carbonate gas reservoirs. In this study, a semianalytical flow model was established by employing Laplace transformation, Fourier transformation and inversion, Stehfest numerical inversion algorithm, and point source function. Based on the proposed model, the effects of major parameters on production performance were studied.
2. Physical Model
Figure 1 shows a schematic for HDW in a fracturedvuggy carbonate gas reservoir. Fracturedvuggy carbonate gas reservoirs are naturally structured by matrix system, natural fractures system, and vugs system. Figure 2 shows the physical modeling scheme of a fracturedvuggy carbonate medium. In order to mathematically define the gas flow behavior, the assumptions of this model are listed as follows:(1)HDW are located in a laterally infinite gas reservoir.(2)The gas reservoir is assumed to be horizontal with equal thickness and have two impermeable boundaries at the top and bottom.(3)During the well production, gas flows only through the fracture system into the wellbore; interporosity flow occurs from the vugs and the matrix systems to the fracture system.(4)Flow is single phase, isothermal and follows Darcy's law. Gravitational and capillary effects are negligible.(5)The pressure is uniform initially throughout the gas reservoir and is equal to .(6)The HDW produces at a constant rate or at constant pressure .(7)The permeability in horizontal direction and in vertical direction are different.
3. Mathematical Model
3.1. Establishment of Mathematical Model
In this work, the interporosity flow from vugs and matrix to fractures is assumed to be pseudosteady state. Combining the continuity equation with transport equation as well as the equation of state and the introduction of pseudopressure and pseudotime (the detailed procedure for pseudopressure and pseudotime is documented in Appendix A), the governing equation for the tripleporosity system in radial cylindrical coordinate is given as follows:
For the matrix system the equation is
For the vugs system the equation is
where , , is the pseudopressure of fractures system, matrix system, vugs system, respectively, ; , , is porosity of fracture system, matrix system, vugs system, respectively, fraction; , , is permeability of fracture system, matrix system, vugs system, respectively, md; is vertical fracture permeability, md; , , is compressibility of fracture system, matrix system, vugs system, respectively, ; is gas viscosity, ; , are shape factors of matrix and vugs, ; and is pseudotime, day.
The initial pseudopressure is assumed uniform for the tripleporosity system:
The outer boundary is closed:
At the inner boundary, there is a continuous point source () with a constant gas rate :
where is fracture horizontal permeability, .
At the top and bottom, the boundaries are impermeable:
where is formation thickness, .
Based on the definitions of dimensionless variables in Table 1, the governing equations and the initial and boundary conditions (Eq. (1)(7)) can be transformed into dimensionless terms (Eq. (8)(14)).

The dimensionless governing equation of fracture, matrix, and vugs systems are
Transformed initial condition:
Transformed outer boundary condition:
Transformed inner boundary condition:
Transformed top and bottom boundaries:
3.2. Solution of Mathematical Model
3.2.1. Basic Continuous Point Source Solution
Laplace transformation, Fourier transformation, and inversion were employed to solve the dimensionless model (Eq. (8)(14)). The solution in Laplace space is as follows (the detailed procedure for the solution is documented in Appendix B).
where
where is modified Bessel function of zero order of the second kind; is modified Bessel function of order one of the second kind; is modified Bessel function of order zero of the first kind; is modified Bessel function of order one of the first kind.
3.2.2. Pressure Distribution of a HDW
To obtain the pressure solution of HDWs, the wellbore was treated as a uniform flux line source. It was assumed that there was an infinitesimal point on the HDW. Based on the principle of superposition for a point source, integration was carried out along the deviated line for the line source solution. Cinco (1975) successfully got the , , coordinates of the equivalentpressure point where the wellbore pressure of HDW can be calculated easily [30]. Therefore, the dimensionless pressure distribution of HDW in Laplace domain is given as follows:
where
Based on the principle of superposition, the pressure solution with wellbore storage and skin effect in Laplace domain can be obtained as
where C is wellbore storage coefficient, ; is the dimensionless bottom pseudopressure.
3.2.3. Gas Production Based on the Well Pressure Responses
According to Van Everdingen and Hurst [31], the dimensionless production response for a HDW producing at a constant bottomhole pressure in the Laplace domain can be obtained as follows:
Equation (25) can then be inverted to obtain in real space using suitable numerical inversion algorithms such as Stehfest's inversion algorithm [32].
4. Results and Discussion
4.1. Proposed Model Application and Validation
Field data from the Arum River Basin in Turkmenistan was used to validate the proposed model and to demonstrate its practical application. Arum River Basin is a large scale sedimentary basin, which is located between the border of Turkmenistan and Uzbekistan. The reservoir bed possesses carbonate rock that is formed by postdepositional diagenesis, including dissolution and dolomitization. Vugs, fractures, and dissolution pores are highly dispersed in the reservoir. The details of relevant parameters needed for the model evaluation are listed in Table 2. These parameters are obtained by various methods in the field. In particular, it should be noted that formation radius (), fracture permeability (), interporosity flow coefficients between different media systems (), and initial reservoir pressure () can be obtained through interpretation of well testing data. And the porosity of three different media () can be obtained by combining well logging data with core CT scanning.

Figure 3 shows a comparison between daily rate of gas production from a highly deviated well from the field and simulated gas production rate from the proposed model. It was found that the proposed model had a good fitting with actual production data. Except for very few data points that deviated from the simulated curve due to the real production time being less than 24 hours, the rest of the data fits well with the curve. After ignoring data points less than 24 hours of production, the average relative error () between the remaining actual data and model data is only 4.19%. The average relative error () is evaluated by
where is simulated production rate from the proposed model, ; is field production rate, .
Moreover, it could be seen that the trend of simulated production rate in the following 1000 days and even longer predicted the gas production trend for the future with a constant bottomhole pressure. Based on this application, it is confirmed that the proposed model can be used to describe the gas production behavior of HDW in naturally fracturedvuggy carbonate gas reservoir. Therefore, the estimated input parameters of the model will be used as the basis for the sensitivity analysis.
4.2. Modeling of Production Behavior with TriplePorosity Flows
In order to understand the production behavior with tripleporosity flows, different flow regime analysis was conducted to study the effects of various flow mechanisms on the overall production behavior. Figure 4 shows the complete transient flow process of HDW production in fracturedvuggy carbonate gas reservoir under closed circle boundary and it can be divided into five flow stages. The first stage was dominated by wellbore storage and skin effect and the dimensionless pseudopressure and pseudopressure derivative curves showed a straight line with a slope of 1. After that, skin factor affected the shape of the derivative curve that looked like a “hump”. The second stage was dominated by inclination angle () of HDW. When the inclination angle approached 0°, the HDW was treated as a vertical well. In this case, this stage would not be obvious or would completely disappear on the curve. The third stage was dominated by interporosity flow between fractures and vugs and this flow regime behaved with a “dip” on the pressure derivative curve. Because the gas flow in the vugs was relatively smoother than in the matrix, the interporosity flow between fractures and vugs appeared first when the wellbore pressure began to deplete. Therefore, wellbore pressure depletion was retarded due to gas supplement from vugs to fracture system. The fourth stage was dominated by interporosity flow between fractures and matrix and this stage also behaved with a “dip” on the pressure derivative curve. It is worth noting that the third and fourth stages could interfere with each other, depending on the value of and . The fifth stage was dominated by closed circle boundary, which manifested on the derivative curve with a slope of 1.
4.3. Model Sensitivity Analyses
Based on the field data, the production sensitivity analyses for different key parameters are discussed. In this section, the HDW produces with a constant bottomhole pressure. The key parameters include formation thickness, fracture permeability, inclination angle of the HDW, formation radius, interporosity flow coefficient between fractures and vugs and vugs storativity ratio. The influences of these parameters are apparent and their estimates are essential for future production analysis and forecasting.
Figure 5 shows the effects of formation thickness on production performance. From Figure 5, it can be seen that formation thickness primarily influences every stage of gas production. For the time, days, the difference of gas production rates between different formation thicknesses were almost the same. It meant that the decline rates of gas production for different scenarios were almost the same. After the time, days, the differences become smaller with increase in time. In addition, it was also observed that with decrease in formation thickness, the area enclosed by the curve became smaller, which meant the cumulative production reduced.
From Figure 6, it was noted that permeability affects the whole period of gas production. The higher the fracture permeability, the higher the initial production rate. However, for a reservoir with higher fracture permeability, production rate would decrease drastically, and during the middlelate stages the production rate would be exceeded by a reservoir with lower fracture permeability. Moreover, a well with low fracture permeability has a long stable production period.
Figure 7 shows the effects of reservoir radius on gas production performance of HDWs. The difference of gas production at late stage was increasingly wider. It was noted that with increase in gas reservoir radius, the production curves declined more gently, which meant a gas reservoir with bigger radius would have a longer stable production period.
Figure 8 shows the effects of interporosity flow coefficient between fractures and vugs on gas production performance of the HDW. It can be seen that the coefficient primarily affected early stage of gas production. For the time, days, with the interporosity flow coefficient between fractures and vugs smaller, the initial production also became smaller and the production rate decreased relatively slower. For the time, days, there was no difference between the production rates of the three scenarios. From Figure 9, it was observed that vugs storativity ratio affected middlelate stage of gas production. During days, with vugs storativity ratio smaller, production rate decreased more rapidly. However, after days, the difference in the production curves was contrary to the previous one. Meanwhile, it was obvious that the extent of production variation is less drastic than the middle stage.
Figure 10 shows the effects of the angle of inclination on gas production performance of the HDW. It can be seen that the angle of inclination also affects the entire stage of gas production. Due to the effects of different inclination angle on contact area of wellbore, the cumulative gas production increases with increase in inclination angle.
According to Figures 5–10, the production decline curve was affected by many parameters and the intensity of production variation was different at different stages of gas production history. By extracting production rate data at different times (t=10days, 100days, 1000days) for adjacent parameters in Table 3, production difference percentage () could be obtained which could be helpful in comparing the sensitivity of these parameters.

Based on Table 3, trends of difference in percentage of parameters are shown in Figure 11. It can be seen that the bigger the difference in percentage value, the more sensitive the parameters. Inclination angle () and fracture permeability () seemed to be the two most sensitive parameters; reservoir radius () was the third, vugs storativity ratio () and interporosity flow coefficient between fractures and vugs () were the least two sensitive parameters.
5. Conclusions
This research investigated the production decline behavior of highly deviated well (HDW) in naturally fracturedvuggy carbonate gas reservoir. The validity of the proposed model was verified by matching it with the production history of a field case from the Arum River carbonate gas reservoir in Turkmenistan. Furthermore, the effects of relevant parameters on production performance were studied. The main conclusions drawn are as follows:(1)The proposed production semianalytical model could be used to predict the gas production trend with a constant bottomhole pressure.(2)Pressure type curves for HDW in naturally fracturedvuggy carbonate gas reservoir were divided into five flow stages. Among them, the second stage was dominated by the inclination angle () of the HDW. The third stage was dominated by interporosity flow between fractures and vugs. The fourth stage was dominated by interporosity flow between fractures and matrix. However, the third and fourth stages could interfere with each other, depending on the values of and .(3)Using the proposed model, sensitivity analyses were conducted and it was found that formation thickness (), fracture permeability (), inclination angle of the HDW affected the entire stage of gas production history. Interporosity flow coefficient between fractures and vugs () affected the early stage of gas production history. Vugs storativity ratio affected middlelate stage of gas production history. Gas reservoir radius affected late stage of gas production history. Moreover, inclination angle () seemed to be the most sensitive parameter, fracture permeability () was the second most sensitive parameter, followed by reservoir radius (), while vugs storativity ratio () and interporosity flow coefficient between fractures and vugs () were the last two sensitive parameters.
Appendix
A. Calculation of Pseudopressure and Pseudotime
In (1) (7), , , is the pseudopressure of the fracture system, matrix system, and vugs system, respectively, ; is pseudotime, day. The pseudopressure and pseudotime can be given as follows:
B. Calculation of Continuous Point Source Solution
Equations (8)(14) can be transformed into Laplace domain by the Laplace transformation.
The dimensionless governing equations of fractures, matrix, and vugs systems in the Laplace domain are as follows:
The outer boundary condition is transformed as
The inner boundary condition is transformed as
The top and bottom boundaries are transformed as
where
To eliminate the variable in the governing equation, (B.1)(B.5) can be transformed by Fourier cosine transform. The Fourier cosine transform and inverse Fourier cosine transform are given as follows:
where
By employing the Fourier cosine transform (Eq. (B.8)), Eqs. (B.1)(B.5) can be transformed as follows:
where
The outer boundary condition is transformed as
The inner boundary condition is transformed as
Then (B.11) can be transformed to a modified Bessel function of zero order, like the following:
The general solution of (B.16) is given as follows:
Based on the outer and inner boundary conditions (Eq. (B.14)(B.15)), the solution in Laplace domain can be obtained by inverse Fourier cosine transform as follows:
Nomenclature
Wellbore storage coefficient,  
:  Total compressibility, 
Average relative error, %  
Formation thickness,  
Permeability of vugs system,  
:  High deviated well length, 
Pseudopressure,  
:  Well bottomhole pseudopressure, 
Pressure,  
:  Well bottomhole pressure, 
:  Pressure at standard condition, 
:  Production rate from point source, 
:  Gas production rate, 
:  Simulated production rate from the proposed model, 
:  Field production rate, 
Radial distance,  
:  Wellbore radius, 
:  Formation radius, 
Skin factor  
Laplace transform variable  
Pseudotime, day  
:  Pseudotime, day 
Reservoir temperature,  
:  Temperature at standard condition, 
Directional coordinates  
:  Distance of midperforation in x, y, and z coordinates, 
Zfactor of gas, dimensionless  
:  Shape factors of vugs and matrix, 
Interporosity flow coefficient, dimensionless  
Storativity ratio, dimensionless  
Inclination angle, degree  
Porosity, fraction  
:  Gas viscosity, mPa·s 
Constant, 
Vugs system  
Fractures system  
Vugs system  
Horizontal direction  
Initial condition  
Initial condition  
Vertical direction  
Dimensionless. 
Laplace domain  
Fourier domain  
Field production data. 
Data Availability
The field data from the Arum River Basin in Turkmenistan used to support the findings of this study are included within the article.
Conflicts of Interest
The authors declare that they have no conflicts of interest.
Acknowledgments
The authors would like to acknowledge the support provided by Xin Zhao and Jun Shi in the initial stages of this study. This article is funded by National Science and Technology Major Project of China (Grant Nos. 2017ZX05030003 and 2017ZX05009005).
References
 L. Yong, W. Qi, L. Baozhu, and L. Zhiliang, “Dynamic characterization of different reservoir types for a fracturedcaved carbonate reservoir,” in Proceedings of the SPE Kingdom of Saudi Arabia Annual Technical Symposium and Exhibition, SPE188113MS, pp. 390–403, Dammam, Saudi Arabia, April 2017. View at: Google Scholar
 P. Yue, Z. Xie, S. Huang, H. Liu, S. Liang, and X. Chen, “The application of N2 huff and puff for IOR in fracturevuggy carbonate reservoir,” Fuel, vol. 234, pp. 1507–1517, 2018. View at: Publisher Site  Google Scholar
 P. Ghahri and M. Jamiolahmady, “A new, accurate and simple model for calculation of productivity of deviated and highly deviated well – Part I: Singlephase incompressible and compressible fluid,” Fuel, vol. 97, pp. 24–37, 2012. View at: Publisher Site  Google Scholar
 H. Kazemi, “Pressure transient analysis of naturally fractured reservoirs with uniform fracture distribution,” SPE Journal, vol. 9, no. 4, pp. 451–462, 1969. View at: Publisher Site  Google Scholar
 K. Serra, A. Reynolds, and R. Raghavan, “New pressure transient analysis methods for naturally fractured reservoirs,” Journal of Petroleum Technology, vol. 35, no. 12, pp. 2271–2283, 1983. View at: Publisher Site  Google Scholar
 R. D. Evans, “A proposed model for multiphase flow through naturally fractured reservoirs,” SPE Journal, vol. 22, no. 05, pp. 669–680, 1982. View at: Google Scholar
 A. O. Igbokoyi and D. Tiab, “Well test analysis in naturally fractured reservoirs using elliptical flow,” in Proceedings of the International Petroleum Technology Conference 2007, IPTC 2007, pp. 150–165, Dubai, UAE, December 2007. View at: Google Scholar
 B. Gao, Z. Huang, J. Yao, X. Lv, and Y. Wu, “Pressure transient analysis of a well penetrating a filled cavity in naturally fractured carbonate reservoirs,” Journal of Petroleum Science and Engineering, vol. 145, pp. 392–403, 2016. View at: Publisher Site  Google Scholar
 J. E. Warren and P. J. Root, “The behavior of naturally fractured reservoirs,” SPE Journal, vol. 3, no. 3, pp. 245–255, 1963. View at: Google Scholar
 D. Bourdet and A. C. Gringarten, “Determination of fissure volume and block size in fractured reservoirs by typecurve analysis,” in Proceedings of the SPE annual technical conference and exhibition, SPE9293MS, Dallas, Tex, USA, September 1980. View at: Google Scholar
 Y. Jalali and I. Ershaghi, “Pressure transient analysis of heterogeneous naturally fractured reservoirs,” in Proceedings of the SPE California Regional Meeting, SPE16341MS, pp. 175–188, Ventura, Calif, USA, April 1987. View at: Google Scholar
 A. H. ElBanbi, Analysis of tight gas well performance [Ph.D. thesis], Texas A&M University, Texas, Tex, USA, 1999.
 Y. Jia, X. Fan, R. Nie, Q. Huang, and Y. Jia, “Flow modeling of well test analysis for porous–vuggy carbonate reservoirs,” Transport in Porous Media, vol. 97, no. 2, pp. 253–279, 2013. View at: Publisher Site  Google Scholar
 D. Abadassah and I. Ershaghi, “Tripleporosity systems for representing naturally fractured reservoirs,” SPE Formation Evaluation, vol. 1, no. 2, pp. 113–127, 1986. View at: Publisher Site  Google Scholar
 A. AlGhamdi and I. Ershaghi, “Pressure transient analysis of dually fractured reservoirs,” SPE Journal, vol. 1, no. 1, pp. 93–100, 1996. View at: Publisher Site  Google Scholar
 R. CamachoVelazquez, M. VasquezCruz, R. CastrejonAivar, and V. AranaOrtiz, “Pressure transient and decline curve behaviors in naturally fractured vuggy carbonate reservoirs,” in Proceedings of the SPE Annual Technical Conference and Exhibition, SPE77689MS, San Antonio, Tex, USA, 2002. View at: Publisher Site  Google Scholar
 Y. Wu, H. Liu, and G. Bodvarsson, “A triplecontinuum approach for modeling flow and transport processes in fractured rock,” Journal of Contaminant Hydrology, vol. 73, no. 14, pp. 145–179, 2004. View at: Publisher Site  Google Scholar
 M. Wang, Z. Fan, X. Dong, H. Song, W. Zhao, and G. Xu, “Analysis of flow behavior for acid fracturing wells in fracturedvuggy carbonate reservoirs,” Mathematical Problems in Engineering, vol. 2018, Article ID 6431910, 20 pages, 2018. View at: Publisher Site  Google Scholar
 A. F. Gulbransen, V. L. Hauge, and K.A. Lie, “A multiscale mixed finiteelement method for vuggy and naturally fractured reservoirs,” SPE Journal, vol. 15, no. 2, pp. 395–403, 2010. View at: Publisher Site  Google Scholar
 Y. Li, J. Yao, Y. Li et al., “An equivalent continuum approach for modeling twophase flow in fracturedvuggy media,” International Journal for Multiscale Computational Engineering, vol. 15, no. 1, pp. 79–98, 2017. View at: Publisher Site  Google Scholar
 F. Zhang, M. An, B. Yan, and Y. Wang, “Modeling the depletion of fractured vuggy carbonate reservoir by coupling geomechanics with reservoir flow,” in Proceedings of the SPE Reservoir Characterisation and Simulation Conference and Exhibition, SPE186050MS, Abu Dhabi, UAE, 2017. View at: Publisher Site  Google Scholar
 S. Gao, J. E. Killough, J. He, M. M. Fadlelmula, F. Y. Wang, and M. L. Fraim, “A new approach for the simulation of fractured vuggy carbonate reservoir with an application to upscaling,” in Proceedings of the SPE Reservoir Characterisation and Simulation Conference and Exhibition, SPE186018MS, Abu Dhabi, UAE, 2017. View at: Publisher Site  Google Scholar
 M. Abbaszadeh and P. S. Hegeman, “Pressuretransient analysis for a slanted well in a reservoir with vertical pressure support,” SPE Formation Evaluation, vol. 5, no. 3, pp. 277–284, 1990. View at: Publisher Site  Google Scholar
 E. Ozkan and R. Raghavan, “A computationally efficient, transientpressure solution for inclined wells,” in Proceedings of the SPE Annual Technical Conference and Exhibition, New Orleans, La, USA, 1998. View at: Publisher Site  Google Scholar
 H. Gill, R. AlZayer, and M. B. Issaka, “Pressure transient behavior of horizontal and slant wells intersecting a highpermeability layer,” in Proceedings of the SPE 15th Middle East Oil and Gas Show and Conference, MEOS 2007, pp. 1332–1344, Manama, Bahrain, March 2007. View at: Google Scholar
 H. Wang, L. Zhang, J. Guo, Q. Liu, and X. He, “An efficient algorithm to compute transient pressure responses of slanted wells with arbitrary inclination in reservoirs,” Petroleum Science, vol. 9, no. 2, pp. 212–222, 2012. View at: Publisher Site  Google Scholar
 F. Meng, Q. Lei, D. He et al., “Production performance analysis for deviated wells in composite carbonate gas reservoirs,” Journal of Natural Gas Science and Engineering, vol. 56, pp. 333–343, 2018. View at: Publisher Site  Google Scholar
 X. Zhao, H. Wang, and S. Xue, “Effective model to evaluate the inflow performance of highly deviated wells in anisotropic reservoirs,” Journal of Engineering Science and Technology Review, vol. 11, no. 5, pp. 119–127, 2018. View at: Google Scholar
 L. Wang, X. Chen, and Z. Xia, “A novel semianalytical model for multibranched fractures in naturally fracturedvuggy reservoirs,” Scientific Reports, vol. 8, no. 1, 2018. View at: Google Scholar
 H. CincoLey, H. Ramey, and F. G. Miller, “Pseudoskin Factors for PartiallyPenetrating DirectionallyDrilled Wells,” in Proceedings of the fall meeting of the society of petroleum engineers of AIME, Dallas, Tex, USA, 1975. View at: Publisher Site  Google Scholar
 A. F. van Everdingen and W. Hurst, “The application of the Laplace transformation to flow problems in reservoirs,” Journal of Petroleum Technology, vol. 1, no. 12, pp. 305–324, 1949. View at: Publisher Site  Google Scholar
 H. Stehfest, “Algorithm 368: Numerical inversion of Laplace transforms [D5],” Communications of the ACM, vol. 13, no. 1, pp. 47–49, 1970. View at: Publisher Site  Google Scholar
Copyright
Copyright © 2019 Kongjie Wang et al. This is an open access article distributed under the Creative Commons Attribution License, which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited.