2014_Yu Et Al_Sensitivity Analysis of Hydraulic Fracture Geometry in Shale Gas Reservoirs_JPSE

Sensitivity analysis of hydraulic fracture geometry in shalegas reservoirs

W. Yu a, Z. Luo a, F. Javadpour b,n, A. Varavei a, K. Sepehrnoori a

a Petroleum and Geosystems Engineering, The University of Texas at Austin, Austin, TX, USAb Bureau of Economic Geology, The University of Texas at Austin, University Station, Box X, Austin, TX 78713, USA

a r t i c l e i n f o

Article history:Received 12 October 2012Accepted 14 December 2013Available online 22 December 2013

Keywords:hydraulic fracturingshale gassensitivity analysisfracture interferencehorizontal well

a b s t r a c t

The combination of horizontal drilling and multiple hydraulic fracturing has been widely used tostimulate shale gas reservoirs for economical gas production. Numerical simulation is a useful tool tooptimize fracture half-length and spacing in a multistage fracturing design. We developed a methodol-ogy to use a commercial reservoir simulator to simulate production performance of shale gas reservoirsafter fracturing. We veried our simulation method with the available eld data from the Barnett Shale.In this work, we performed a sensitivity study of gas production for a shale gas well with differentgeometries of multiple transverse hydraulic fractures, in which fractures0 half-lengths vary. Hydraulicfractures are divided into two outer and inner fracture groups. The simulation results revealed that theouter fractures contribute more to gas production when fracture spacing is small due to the effect offracture interference. Also, we studied the effects of fracture half-length and fracture spacing on gasproduction. This work can provide some insights into characterization of hydraulic fracture geometry onthe basis of production data in shale gas reservoirs.

& 2013 Elsevier B.V. All rights reserved.

1. Introduction

Newly developed techniques in the elds of horizontal drillingand hydraulic fracturing have made possible the current ourish-ing gas production from shale gas plays in the United States, aswell as the fast-growing investment in shale gas exploration anddevelopment worldwide. Hydraulic fracturing has been used inthe oil and gas industry since the 1940s. Multiple transversehydraulic fractures in a horizontal wellbore can create a largestimulated reservoir volume (SRV), which is the main contributorto high gas production from shale gas plays with extremely lowpermeability (Javadpour et al., 2007; Warpinski et al., 2009;Javadpour, 2009; Soliman and Kabir, 2012).

Although hydraulic fractures improve gas production fromshale gas wells, hydraulic fracturing is expensive. Long lateralsrequire greater volume of liquids and proppants, contributing tohigher cost (Kaiser, 2012). Therefore, optimization of hydraulicfracture parameters, such as fracture spacing and fracture half-length, is important. It is well known that the longer the fracturehalf-length and the shorter the fracture spacing, the higher gasproduction will be. The greater the number of fractures in theshale around the wellbore, the faster the gas will be produced

(Kalantari-Dahaghi, 2011). In some cases, more than 20 fracturestages have been tried in a horizontal well in order to increasefracture contact with the formation and to produce high initial gasrates (Castaneda et al., 2010; King, 2010). Meyer et al. (2010)suggested that initial production increases linearly with number offractures, but a high gas ow rate is not sustainable and willdecline sharply once fractures interfere over a given lateral length.Fazelipour (2011) stated that more hydraulic fractures around thewellbore increase production rate; fractures are the key compo-nent to effective production. Mayerhofer et al. (2010) pointedout that a large SRV with small fracture spacing could providemaximum well performance and gas recovery, considering eco-nomic optimization in design. Waters et al. (2009) stated thatoptimum fracture spacing depends on the incremental cost associ-ated with creating denser fracture systems or productivityimprovement from available fracture networks. All of these studiessuggest the importance of economic factors in optimizing multipletransverse hydraulic fractures. For example, reduction in fracturespacing is expensive and may even cause interference and sub-sequent reduction in gas production. Analytical models do notincorporate fracture interference and assume equal fracture half-length (Ambrose et al., 2011; Zhao et al., 2012); hence, numericalsimulation is necessary.

In this paper, we performed a sensitivity study of gas produc-tion for a shale gas well with uncertain but possible hydraulicfracture geometry. Hydraulic fractures are divided into outerfractures and inner fractures (Fig. 1). The performance of the outer

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Journal of Petroleum Science and Engineering 113 (2014) 17

fractures is much more benecial for gas production than is theperformance of the inner fractures, owing to the interferenceeffect of inner fractures. We also studied the effects of bothfracture half-length and fracture spacing on gas production. Thegoal of this work is to provide insights into characterization ofhydraulic fracture geometry on the basis of production data inshale gas reservoirs.

2. Shale gas reservoir modeling

Given the complex nature of hydraulic fracture growth and thevery low permeability of matrix rock in shale gas reservoirs,coupled with the predominance of horizontal completions, reser-voir simulation is a preferred approach to predict and evaluatewell performance. Local grid renement with logarithmic cellspacing is used in simulation to accurately model gas ow fromthe matrix to a fracture, i.e., properly incorporating the transientow behavior from the matrix to and within the fracture. In ablock, the hydraulic fracture is explicitly modeled; moreover, inorder to properly simulate the large pressure drop between thematrix and the fracture, the matrix is described as some sub-cellswhose size increases logarithmically while moving away from thehydraulic fracture. In addition, a dual-permeability grid is used toallow simultaneous matrix-to-matrix and fracture-to-fractureow. This method can accurately and efciently model transientgas production from hydraulic fractures of horizontal wells inshale gas plays (Rubin, 2010; Cipolla et al., 2010). The reservoir isassumed to be homogeneous and the fractures evenly spaced, withstress-independent porosity and permeability.

In our simulation, gas is owing into the wellbore only throughfractures, i.e., no matrix-wellbore communication exists. Thegas ow, which is turbulent as a result of the high gas owrate in hydraulic fractures, is modeled with non-Darcy ow. The

non-Darcy Beta factor used in the Forchheimer number is deter-mined using a correlation proposed by Evans and Civan (1994):

f 1:485E9=K1:021 1

where the unit of K is md and the unit of is ft1. The (f) corre-lation was developed using more than 180 data points, includingthose for propped fractures, and was found to closely match thedata (Rubin, 2010). Fig. 1 is a diagram of a typical shale gascompletion design, illustrating several important geometric frac-ture parameters, such as fracture spacing and fracture half-length.

3. Case study

Published average reservoir data for the Barnett Shale in theNewark East eld were used (Grieser et al., 2009). The Mississip-pian Barnett Shale, which sits on an angular unconformityabove the Cambrian- to upper-Ordovician-age carbonates of theEllenberger Group and Viola Formation and overlying thePennsylvanian-age Marble Falls Limestone, is associated with thelate Paleozoic Ouachita orogeny and located in the Fort WorthBasin area in North-Central Texas (Roy et al., 2013). The leastprinciple stress is roughly NW to SE, which is the wellboreorientation, so that multiple transverse hydraulic fractures wouldbe created (Fisher et al., 2004).

In this case, the well was stimulated by a four-stage fracturingwith a single, perforated interval for each stage. Detailed reservoirinformation about this section of the Barnett Shale is listed inTable 1. For this well, fracture maps were obtained using geo-phones installed in offset wells, and estimates of fracture half-length at each initiation were provided (Grieser et al., 2009). Weused the simulator CMG-IMEX (CMG, 2012) to model hydraulicfractures around the wellbore and simulate gas production, asillustrated in Fig. 2(a). Note the variation in fracture half-lengthin this well. History matching of the led data is presented inFig. 2(b). It shows a reasonable match between numerical simula-tion results and actual eld gas ow data.

We set up another shale gas reservoir model with a volume of990 ft1980 ft50 ft, based on average reservoir data from theBarnett Shale (Table 1). The effect of the number of hydraulicfractures on cumulative gas production with a base horizontal welllength (660 ft) is presented in Fig. 3. It shows that cumulative gasproduction increases linearly at early times of production and thenslows down at later times, nally reaching a plateau. The initialcumulative production increase is more dramatic in cases witha higher number of fractures (smaller fracture spacing). Fig. 4shows the impact of the number of fractures on cumulative gasproduction from the base well (660 ft) after 10 years of production.

Horizontal well

Outer fractures

Fracture

Fracture half-length

Inner fractures

Fig. 1. Sketch of four induced hydraulic fractures in horizontal shale gas productionwell.

Table 1Basic reservoir information.

Parameter Barnett Shale case Synthetic case Unit

Model dimensions (LWH) 35005000400 (1066.81524121.9) 990198050 (301.8603.515.2) ft (m)Initial reservoir pressure 3800 (2.62107) 3776 (3.60107) psi (Pa)Bottom-hole pressure 1500 (1.03107) 1000 (6.89106) psi (Pa)Production period 3 (9.47107) 10 (3.16108) year (s)Reservoir temperature 180 (82) 180 (82) oF (oC)Gas viscosity 0.02 (0.00002) 0.02 (0.00002) cP (Pa s)Top of reservoir 7000 (2133.6) 6956 (2120.2) ft (m)Initial gas saturation 0.70 0.80 fractionCompressibility of shale 3.0106 (4.351010) 106 (1.451010) psi1 (Pa1)Fracture height 400 (121.9) 50 (15.2) ft (m)Fracture conductivity 9 (2.71015) 100 (31014) md-ft (m2-m)Matrix permeability 0.00035 (3.51019) 0.0001(9.91020) md (m2)Matrix porosity 0.04 0.08 fractionHorizontal wellbore length 2052 (625.4) 600 (182.9) ft (m)

W. Yu et al. / Journal of Petroleum Science and Engineering 113 (2014) 172

Below a critical value (5 fractures), cumulative gas productionincreases linearly, and the increasing trend reaches a plateaubeyond the critical value. The change in the cumulative gasproduction trend at later times is the result of fracture interferenceeffects. Fig. 5 shows the effect of the number of fractures on gasow rate in the base well (660 ft) for a period of 10 years ofproduction. Higher number of fractures results in higher produc-tion rates. However, as a result of fracture interference effects,production decline might be more dramatic in cases with a highernumber of fractures, e.g., in a case of 12 fractures in Fig. 5.

Therefore, optimization of the number of fractures is alwaysnecessary.

We also studied the effect of fracture spacing on cumulative gasproduction for the case of two fractures in the base well, as shownin Fig. 6. Cumulative gas production remains constant for frac-ture spacing larger than 200 ft and decreases with a decrease infracture spacing (o200 ft). This observation also implies that,when the fracture spacing is below a critical distance (whichdepends on reservoir characteristics), the interference effectbetween fractures becomes important. Therefore, optimal fracture

Fig. 2. (a) Four-stage fracture in Barnett Shale and (b) actual versus numerical data of gas ow rate.

Fig. 3. Effect of number of fractures on cumulative gas production in base well.

Fig. 4. Effect of number of fractures on cumulative gas production in base well after10 years of production.

Fig. 5. Effect of number of fractures on gas ow rate in base well (660 ft).

Fig. 6. Effect of fracture spacing on cumulative gas production in base well withequal number of fractures.

W. Yu et al. / Journal of Petroleum Science and Engineering 113 (2014) 17 3

spacing should be selected for practical design of fracture treat-ment (e.g., the optimal distance of 200 ft in Fig. 6).

Fig. 7 presents the effect of hydraulic fracture half-length oncumulative gas production in the base well with constant fracturespacing of 40 ft. The gure shows that cumulative gas productionincreases with an increase in fracture half-length, although stronginterference might occur between fractures. Fig. 8 shows that gasow rate also increases with increasing fracture half-length. Thiscorrespondence suggests that longer fractures produce moreaninference that is in agreement with the results of Frantz et al.(2005).

4. Uncertainty in fracture geometry

Because uncertainty exists in hydraulic fracture geometry, westudied ve different outer-to-inner fracture half-length combina-tions, as illustrated in Fig. 9. Inner and outer fractures are markedin this gure.

Fig. 7. Effect of fracture half-length on cumulative gas production in the basemodel with 40 ft of fracture spacing.

Fig. 8. Effect of fracture half-length on gas ow rate in base well with 40 ft offracture spacing.

Case 1: Equal length but short fractures

Case 2: Inner fractures longer than outer fractures

Case 3: Mixed fracture lengths

Case 4: Outer fractures longer than inner fractures

Case 5: Equal length but long fractures

Fig. 9. Schematic diagrams of ve different innerouter combinations of quadruple transverse fractures in horizontal well.

Fig. 10. Cumulative gas production of ve outerinner fracture-combination casesdescribed in Fig. 9.


Case 1. Fractures with equal and short fracture half-length of250 ft.

Case 2. Outer fractures with a half-length of 250 ft, and innerfractures with a length of 550 ft.

Case 3. Outer fractures with half-lengths of 250 ft and 550 ft, andinner fractures with lengths of 500 ft and 1100 ft.

Case 4. Outer fractures with a half-length of 550 ft, and innerfractures with a length of 250 ft.

Case 5. Fractures with equal and long half-length of 550 ft.

Fig. 10 compares well performance of the fracture layouts illu-strated in Fig. 9. Among these ve cases presented in Fig. 10, Cases1 and 5 exhibit the lowest and the highest cumulative gas production,respectively. This outcome is simply because Cases 1 and 5 have thelowest and the highest total fracture half-length. Interestingly, cumu-lative gas production gures, particularly at later times, are different inCases 24, although the total fracture half-length is the same in thesethree scenarios. The cumulative gas production in Cases 3 and 4 islarger than that of Case 2; in addition, Case 4 performs slightly betterthan Case 3. The performance of Case 2 is between that of Case 1 andCase 5. The reason for the difference between Cases 4 and 2 is thestronger interference effect between longer inner fractures in Case 2versus an absence of the interference effect between longer outerfractures in Case 4. Interestingly, the fracture spacing of the outerFig. 11. Comparison of gas velocities in outer and inner fractures of Cases 2 and 4.

Case 1

Case 4 Case 5

Case 2 Case 3

Fig. 12. Pressure distribution after 10 years of production for ve cases.


fractures in Case 4 is 240 ft (greater than 200 ft, the critical fracturespacing). Because the spacing of longer fractures in Case 3 is 160 ft(less than 200 ft, the critical fracture spacing), a slight interferencebetween fractures exists, leading to slightly lower cumulative gasproduction in Case 3. It should be noted that fracture interference alsoexists in the process of fracture propagation because of a stressshadow effect, resulting in immature fracture growth and fracturewidth restriction (Wu and Olson, 2013; Wu, 2013); however, thisfactor is not considered in this paper. In addition, Fig. 11 shows that thedifference of gas ow velocity between outer fractures and innerfractures decreases rapidly with time for Case 2, whereas, in Case 4,gas ow velocity in the outer and inner fractures continue to bedifferent for a longer period of time. Fig. 11 also shows that gas owvelocity of outer fractures in Case 4 is larger than that of innerfractures and of the other fractures in Case 2. For Case 2, the gas owvelocities of both outer and inner fractures reach the same value after6 years of production, and approach the gas ow velocity in the innerfractures of Case 4. This observation means that contributions of thelonger outer fractures to cumulative gas production and gas ow rateare higher than the contributions of the inner fractures, owing tostrong fracture interference between inner fractures. This pattern maysuggest longer outer fractures result in improved gas production inpractice.

Fig.12 shows pressure distribution of the ve cases after 10 years ofproduction. Clearly, Case 1 has the smallest disturbed volume and Case5 has the highest disturbed volume. The disturbed volumes in Cases24, with the same total fracture half-length, are between Cases 1 and5. The disturbed volume in Case 4 is more than that in Cases 2 and 3.The disturbed volume in Case 4 is almost as high as that in Case 5. Thisresult suggests the possibility of equal disturbed volumewith less totalfracture half-length (cf. Cases 4 and 5 in Fig. 12).

Fig. 13 shows the effect of the aspect ratio of outer fractures toinner fractures on cumulative gas production in Case 4. The gureshows that cumulative gas production increases with the increas-ing aspect ratio of outer fractures to inner fractures. Note that totalfracture half-length is equal in all these scenarios (1600 ft). Theimprovement in cumulative gas production in the scenario oflonger outer fractures is the result of the lack of interference effectbetween the outer fractures.

5. Conclusions

Using numerical simulation, we performed a sensitivity studyof gas production for a shale gas well with uncertainty hydraulicfracture geometry. We rst veried our numerical simulation

method using eld data from a horizontal well with multistagehydraulic fracturing in the Barnett Shale formation. We thensuggested distinct outer and inner hydraulic fractures and pre-sented a detailed study of ve different combinations of outer andinner fractures. We also performed sensitivity analyses on theeffects of fracture half-length and fracture spacing on cumulativegas production and gas ow rate. The following conclusions can beobtained from the results of this simulation study: (1) reduction offracture spacing increases cumulative gas production, until thepoint at which fractures start to interfere; (2) cumulative gasproduction increases linearly with an increase in fracture half-length; (3) the contributions of outer fractures to cumulative gasproduction and gas ow rate are higher than the contributions ofinner fractures; and (4) depending on the characteristics of a shalereservoir, a scheme of outer and inner fracture scheme can bepotentially designed to optimize gas production rate, cumulativegas production, and cost associated with the total induced half-length in a multistage fracturing job.

Acknowledgments

The authors thank Computer modeling Group (CMG) for usage ofsoftware, and this work was supported partly by the ReservoirSimulation Joint Industry Project at the Center for Petroleum andGeosystems Engineering and the NanoGeosciences Lab at The Uni-versity of Texas at Austin. Chris Parker edited the manuscript.Publication authorized by the Director, Bureau of Economic Geology.

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Fig. 13. Effects of outer-to-inner fracture half-length aspect ratio on cumulative gasproduction.


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Sensitivity analysis of hydraulic fracture geometry in shale gas reservoirsIntroductionShale gas reservoir modelingCase studyUncertainty in fracture geometryConclusionsAcknowledgmentsReferences

2014_Yu Et Al_Sensitivity Analysis of Hydraulic Fracture Geometry in Shale Gas Reservoirs_JPSE

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