Transient IPR for Fractured Horizontal Wells in Niobrara Formation

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1 Transient IPR for Fractured Horizontal Wells in Niobrara Formation Bin Yuan, Rouzbeh Ghanbarnezhad Moghanloo, and Da Zheng, University of Oklahoma Copyright 2016, International Petroleum Technology Conference This paper was prepared for presentation at the International Petroleum Technology Conference held in Bangkok, Thailand, November This paper was selected for presentation by an IPTC Programme Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the International Petroleum Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the International Petroleum Technology Conference, its officers, or members. Papers presented at IPTC are subject to publication review by Sponsor Society Committees of IPTC. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the International Petroleum Technology Conference 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 where and by whom the paper was presented. Write Librarian, IPTC, P.O. Box , Richardson, TX , U.S.A., fax Abstract The dominate flow regime for multistage fractured wells in unconventional shale reservoirs is transient flow regime. Understanding the interplay between flow rates and the flowing pressures for different fracturing schemes and completions is critical knowledge required for production optimization. The well production can be optimized by adjusting the flowing bottom-hole pressure. The Inflow Performance Relationships (IPR) are based on the premise of pseudo-steady state flow regime that is inherently not applicable to transient flow; thus, this paper introduces a new empirical IPR model obtained by integrating a series of piece-wised pseudo-steady state flow regimes that occur as the drainage volume expands. The average reservoir pressure calculated within the dynamical drainage volume (DDV) at any given time is used to derive an IPR model. A computer code is developed to evaluate the evolution of DDV using the macroscopic material balance equation. Fluid and rock compressibilities are the only production mechanism. The computer code is used for ten wells in the Niobrara shale oil play. The size of the DDV, associated average reservoir pressure, and transient productivity index are calculated. This newly derived empirical IPR is capable of predicting production performance In practice, this paper provides an insight to understand the long-term transient flow regime and its impact on productivity of wells in shale plays. The method does not require comprehensive inputs, and can be used to optimize the design of multistage fractured wells. Introduction A transient flow regime can last for several years in unconventional reservoirs. In addition, a wide range of complexity in reservoir/fluid properties (i.e., gas desorption, non-darcy flow, stress-dependent reservoir properties, and dual-porosity/dual-permeability features, etc.) and presence of macro/micro fracture networks make conventional reservoirs less efftive to predict the production performance. However, it is crucial to predict the well performance for development of unconventional reservoirs. The field operators control the well production rate by adjusting bottom-hole flowing pressure via pumps. Therefore, it is important to understand the interplay between flow rates and the bottom hole flowing pressures for different fracturing completions (Mayerhofer 2010). A simple analytic equation referred to as the

2 2 Inflow Performance Relationship (IPR) is widely used in the prediction of well performance (Vogel 1968). However, due to ultra-low conductivity of unconventional reservoirs, and long transient flow regime, the conventional Vogel-type IPR becomes inapplicable (Shahri 2013). It is necessary to find a new empirical IPR correlation with high-level accuracy prediction for multistage fractured horizontal wells in shale reservoirs. This paper extends our previous work (G.Moghanloo et al., 2015) concerning a new IPR to match well production data in the Niobrara shale oil play. Vogel et al (Vogel 1968) used computer programming to analyze inflow performance relationships for oil production wells with free solution gas that involves two constants for a linear and quadratic term. It only needs one single production test to construct IPR curves. However, it will not yield a good prediction of IPR during the late production stages. Wiggins et al (1994, 2005) developed a generalized empirical IPR correlation for a three-phase production of fully penetrating horizontal well performance over a wide range of operation conditions. Retnanto et al (1998) proposed an IPR for horizontal wells and multilateral oil wells with free gas production by using different shape factors for single and multilateral well configurations with different reservoir and fluid properties. Tabatabaei et al (2010) proposed IPR equations for horizontal gas wells under three boundary conditions: constant boundary pressure (steady-state flow condition), noflow boundary (pseudo-steady state flow condition), and infinite acting reservoir (transient flow condition). Shahri et al (2013) summarized different kinds of Vogel-type IPRs. As described above, despite many previous studies of IPR conducted for multi-phase multi-shaped wells, there are still no applicable IPR correlations for the transient flow of multi-stage fractured horizontal wells in shale reservoirs. Any changes in operation conditions in shale reservoirs can introduce a transient flow response, which will take a long time to spread through the well reservoirs. Time-dependence is one of the difficulties that are not easy to characterize for shale reservoirs. In addition, the long length of horizontal wells, the existence of complex fracture networks, and low bottom-hole flowing pressure that two-phase flow exhibits around nearby well makes the IPR of MFHW a nonlinear characteristic (Liu et al 2012). Zhou et al. (2014) investigated that the slope of transient IPR as a function of both production index and time-step size. Shahamat et al (2015) introduced a methodology to generate a "practical" transient IPR for multistage fractured horizontal wells by considering the effects of production history and production conditions. As for transient the flow period, in order to obtain the transient flow solutions, it is necessary to know the dynamic propagation of flowing boundary and the changes of average reservoir pressure. Yuan et al (2015) introduced a new empirical Transient IPR correlation to describe well performance during the long-term transient flow period in shale reservoirs, after obtaining the changes of reservoir pressure using a macroscopic material balance model with a moving boundary. The comparison between the new model and conventional Vogel model indicates the accuracy of the new empirical transient IPR model. This paper is an extended work of Yuan et al (2016a) by applying the new type of transient IPR model into Niobrara well examples. The effects of stress-dependent reservoir properties and pressure-dependent fluid properties on production analysis are incorporated into the macroscopic model (Yuan 2016b). This model is a weak (integral) form of macroscopic mass balance model with a moving boundary during the long-term transient-flow regimes in non-static shale oil/gas reservoirs saturated with compressible fluids. After we have obtained the real-time changes of average reservoir pressures for ten Niobrara wells, a new empirical IPR model with constant matching coefficients are achieved to help us determine the relation between well production rates and bottom-hole flowing pressures of multistage fractured horizontal wells.

3 3 Description of Macroscopic Tank Model and Transient IPR During long-term transient-linear flow for multistage fractured horizontal wells, and as the pressure disturbance caused by the transient production history propagates slowly throughout the reservoir, an expanding drainage volume (dynamic drainage volume) is created. The boundaries of the drainage volume are pushed back, and the size of Dynamic Drainage Volume (DDV) grows as production continues. Yuan et al (2015, 2016) developed a macroscopic material balance model (Eq.1) within the dynamic drainage volume that is always changing with the well production. Inside the material balance equations, it is necessary to introduce a formula of dynamic drainage volume to quantify the propagation of transient flow region. As introduced by our previous work (Zheng and Yuan, 2016), we applied the concept of maximum rate of pressure response and the method of multi-variable regression to obtain an analytical equation of DDV (Eq.2) for multistage fractured horizontal wells. The equation includes the effects of different diffusivities within SRV and unstimulated matrix, hydraulic fracture length, and fracture spacing. The novel analytical model of DDV indicates a linear relationship with the square root of time. (1) where Vp is the drainage pore volume in ft3; Bo and Bw are the oil and water formation volume factor corresponding to the average pressure of DDV in bbl/stb; Bg is the gas formation volume factor corresponding to the average pressure of DDV in bbl/scf; t is the production time in days; Rs is the dissolved gas-oil ratio at average pressure in SCF/STB; Sw, So, and Sg are the average water, oil and gas saturation within DDV; Nwp, Nwp and Ngp are the cumulative oil, water and gas production amount; n is the time step, day. For constant-fbhp boundary conditions, the expression of Dynamic-Drainage-Volume (DDV) is shown as follows, (2) Where, the diffusivity of inner and outer reservoir are defined separately as, where xf is the half-length of primary fracture, ft; ηinner, ηouter is the average diffusivity within the inner SRV and the outer unstimulated matrix, respectively; te is the time when the production region (DDV) has just become same with the value of SRV, i.e., the end time of linear flow within SRV, days; ye is the fracture spacing, ft. By using the macroscopic code, the production analysis of ten wells in Niobrara was finished and the changes of DDV were obtained, and within which the average reservoir pressure changed with the production time.

4 4 Figure 1 Estimate of Dynamic Drainage Volume (DDV) with production time for 10 MFHWs in Niobrara Figure 2 Estimate of average reservoir pressure with production time for 10 MFHWs in Niobrara Inferred from our previous work (Yuan 2016a), this paper proposes a new IPR formulation (Eq. 6), and derives an oil-gas-water multiphase inflow performance relationship (IPR). (3) (4)

5 5 (5) Where, Hence, the liquid production index (PI) is (6) Here, q0max,sc is the maximum production rate at surface condition, STB; B0,max is the oil formation factor at the production condition of q0max,sc, bbl/stb; a and n are the empirical factors to be matched; B0b is the oil formation factor at the bubble-point pressure condition, bbl/stb; Jl(t) is liquid production index, STB/ (day psia); is the average pressure within the dynamic drainage volume at time t. In Eq. 6, all the variables are pressure-dependent, and the corresponding pressure is the average reservoir pressure within dynamic drainage volume (DDV). The average pressure of ten wells has been obtained from the above part using a macroscopic code. During transient flow regimes in shale reservoirs, the DDV is always dynamically expanding, and thereby the average pressure also keeps changing; therefore, this IPR correlation coupled the effects of changing average reservoir pressure can represent well performance during the transient flow regime in shale/tight reservoirs. The comparison of new transient IPR and Vogel IPR for ten wells are listed in Fig.3a-j. The matching coefficient of a and b for the ten wells keeps constant as 0.8 and 1.0, respectively.

6 6 Figure 3 Comparison results of Vogel IPR, new IPR model and actual field data

7 7 Figure 3 (Continued.) Comparison results of Vogel IPR, new IPR model and actual field data

8 8 Figure 3 (Continued.) Comparison results of Vogel IPR, new IPR model and actual field data

9 9 Figure 3 (Continued.) Comparison results of Vogel IPR, new IPR model and actual field data To quantify the accuracy of the new transient IPR model, we define a cumulative error, which means the cumulative relative difference between the envelop area of different PI curves in Fig.3, as shown in Eq. 10. The comparison results are presented in Table. 3. The comparison results indicate the feasibility and accuracy to apply the new proposed IPR model to predict the well performance in shale oil reservoirs. (7) Table 1 Cumulative error of IPR results between Vogel model and new model Well number Error_Vogel model Error_New model MFHW 1# 142% 35% MFHW 2# 104% 0.8% MFHW 3# 72% 18% MFHW 4# 80% 0.2% MFHW 5# 213% 71% MFHW 6# 66% 0.6% MFHW 7# 167% 22% MFHW 8# 25% 24% MFHW 9# 42% 25% MFHW 10# 25% 37% Well Deliverability Curve with Optimal Fracture Design Another objective of this paper is to determine the optimal fracture design (fracture spacing) and well spacing after we have finished the estimate of fracture and reservoir properties using rate-transient analysis (Yuan 2016b). To eliminate the effects of different horizontal well length on well performance, the well

10 10 length-normalized EUR is the ultimate recovery of MFHW divided by the length of horizontal section, which represents the contribution of fracture spacing alone. Fig.4 indicates the optimal fracture spacing for the multistage fractured horizontal well in Niobrara shale oil, approximately ft. In view of the optimal fracturing based on the design of bottom-hole flowing pressure, the oil production rate can be read out from the IPR curves under the condition of different average reservoir pressures. The correlation between production rate calculated from the new IPR model and actual field production data is shown as Fig.5. Figure 4 Relation between fracture spacing and horizontal well length normalized EUR of multistage fractured horizontal well Figure 5 The comparison between production rates derived from new IPR model and actual field data for the optimal fracture design Summary and Conclusion This study introduces and applies a new empirical transient IPR correlation for multistage fractured horizontal wells in a shale oil reservoir, Niobrara, USA. We obtained the real-time average reservoir pressure changing with the production history using our developed macroscopic code. The main conclusions are as follows: 1. New IPR correlation can better match with production history and provide us a graphic approach to predict new well performance.

11 11 2. By comparing the different EUR normalized by horizontal well length for the different cases of fracture spacing, we determined the optimal fracture spacing approximated as ft. 3. The well deliverability curve (botthom-hole pressure vs. oil production rates) of the optimal fracture design case is achived by using new IPR model. Acknowledgement The authors greatly acknowledge the support provided by RKI Exploration and Production. We appreciate the unconventional consortium at University of Oklahoma for providing lab data. Garth McLoed provided editing services. References Ghanbarnezhad Moghanloo R.., Yuan B., Ingrahama N., Kramf E., Arrowooda J., Dadmohammadi Y. (2015) Applying macroscopic material balance to evaluate interplay between dynamic drainage volume and well performance in tight formations. Journal of Natural Gas Science and Engineering, Vol.27 November 2015: pp doi: / j.jngse Liu, H., et al Single-Phase Inflow Performance Relationship for Horizontal, Pinnate-Branch Horizontal, and RadialBranch Wells. SPE Journal, (02): pp Mayerhofer, M. J., E. Lolon, N. R. Warpinski, C. L. Cipolla, D. W. Walser and C. M. Rightmire. 2010, "What Is Stimulated Reservoir Volume?" SPE Production & Operations 25(01): Pordel Shahri, M., et al Generalized Inflow Performance Relationship (IPR) for Horizontal Wells, 2013, SPE MS presented at SPE Eastern Regional Meeting. Pittsburgh, August, Pennsylvania, USA. Retnanto, A. and M.J. Economides, 1998, Inflow Performance Relationships of Horizontal and Multibranched Wells in a Solution-Gas-Drive Reservoir, SPE MS presented at European Petroleum Conference August, The Hague, Netherlands. Shahamat, S. M., Tabatabale, H.S., and Mattar, L., Inflow Performance Relationship for Unconventional Reservoirs (Transient IPR), SPE MS presented at SPE/CSUR Unconventional Resource Conference held at Calgary, Alberta, Canada, October. Tabatabaei, M. and D. Zhu, Generalized inflow performance relationships for horizontal gas wells. Journal of Natural Gas Science and Engineering, (2 3): p Vogel, J.V., Inflow Performance Relationships for Solution-Gas Drive Wells. Journal of Petroleum Technology, (01): Wiggins, M.L., 1994, Generalized Inflow Performance Relationships for Three-Phase Flow, SPE Reservoir Engineering, 9(03): Wiggins, M.L. and H. S. Wang, (2005). A Two-Phase IPR for Horizontal Oil Wells, SPE MS presented at SPE Production Operations Symposium April, Oklahoma City, Oklahoma. Yuan, B., Y. Su, R. G. Moghanloo, Z. Rui, W. Wang and Y. Shang, (2015). A new analytical multi-linear solution for gas flow toward fractured horizontal wells with different fracture intensity. Journal of Natural Gas Science and Engineering 23(0): Yuan, B., R. G. Moghanloo, and Emad Shariff et al (2016a). Integrated Investigation of Dynamic Drainage Volume (DDV) and Inflow Performance Relationship (Transient IPR) to Optimize Multi-stage Fractured Horizontal Wells in Shale Oil. Journal of Energy Resource Technology, 138(5): Yuan, B., Zheng, D., and Moghaloo, R. G. (2016b). Integrated Production Analysis Using the Concept of Dynamic Drainage Volume: Modelling, Simulation and Field Applications. SPE Asia Pacific Hydraulic Fracturing Conference August, Beijing, China. Zheng, D., Moghaloo, R. G., and Yuan, B., (2016). Modeling Dynamic Drainage Volume for Multi-Stage Fractured Wells in Composite Shale Systems: New Analytical Solution for Transient Linear Flow. SPE Asia Pacific Hydraulic Fracturing Conference August, Beijing, China. Zhou, W., Banerjee, R. and Prano, E., Nodal Analysis for a Transient Production System Principles and Application. SPE MS presented at Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, UAE, Nov

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