KEYWORDS ABSTRACT. Dr. Raymond L. Johnson, Jr Unconventional Reservoir Solutions 168 Ninth Ave, St Lucia QLD

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1 IMPROVING FRACTURE INITIATION AND POTENTIAL IMPACT ON FRACTURE COVERAGE BY IMPLEMENTING OPTIMAL WELL PLANNING AND DRILLING METHODS FOR TYPICAL STRESS CONDITIONS IN THE COOPER BASIN, CENTRAL AUSTRALIA Dr. Raymond L. Johnson, Jr Unconventional Reservoir Solutions 168 Ninth Ave, St Lucia QLD Dr. Hani Farouq Abul Khair Australian School of Petroleum, University of Adelaide Santos Petroleum Engineering Building, University of Adelaide, Adelaide SA Dr. Rob Jeffrey CSIRO Energy, CSIRO Bayview Avenue, Clayton, VIC Dr. Jeremy Meyer Ikon Science Level 2, 60 Hindmarsh Square, Adelaide SA Carly Stark Petro king Australia Pty Ltd Level 2, 333 King William Street, Adelaide SA king.com.au James Tauchnitz Petro king Australia Pty Ltd Level 2, 333 King William Street, Adelaide SA king.com.au KEYWORDS Cooper Basin, geomechanics, geomechanical modelling, hydraulic fracturing, fracture initiation, fracture optimization, in situ stress, drilling, well planning ABSTRACT Drilling conditions involving high mean and deviatory stresses and natural fractures in the Cooper Basin pose difficulties in drilling and introduce wellbore rugosities, leaving a damaged wellbore subject to a stress cage effect. Fracture initiations have been problematic in vertical Cooper Basin wells, exhibiting high initiation and treating pressure frac treatments, and high stress conditions pose greater risks in non vertical completions. Whilst far field fracture complexity should simplify, the near wellbore complexity results in reduced fracture conductivity. We believe that current drilling practices and wellbore azimuths may be contributing to sub optimal hydraulic fracture initiations and complexities. Current analytical modelling methodologies can derive initiation pressures for circular wellbores, but require more complex numerical models to include flaws and ellipticity to represent natural fractures Johnson 1

2 and wellbore rugosities. This study compares initiation pressures and presents graphical results comparing circular and elliptical wellbore cases with flaws. We will outline the criteria used in these models and remark on areas for further research and model development. Finally, we propose improved drilling techniques to achieve more stable, smoother wellbores, potentially reducing some rugosity and drilling induced fractures. Then, using data from recent research and other cases with complex stress environments, it is proposed that initiation pressures might be reduced by inclining wells for hydraulic fracturing treatments in a favourable alignment to the maximum horizontal stress direction ( H Max) and implementing completion techniques that aid better fracture initiation. Introduction EXTENDED ABSTRACT The stress and rock strength environment in the Cooper Basin typically results in significant wellbore breakout. For example, it is a typical practice to run dual density tools offset by 90 degrees with one tool getting stuck in the breakout while the other tool measures undamaged formation. These conditions often result in a rugose non circular wellbores impacting the quality of the cement job and a damaged wellbore subject to a stress cage effect, thereby affecting fracture initiation conditions. As a result, fracture initiations have been problematic in vertical wells and pose an even greater risk for deviated to horizontal completions. Whilst the fracture may become less complex in the far field, a majority of Cooper Basin completions exhibit high initiation, high treating pressures, and near wellbore (NWB) pressure losses. Solutions to these problems have been proposed by many authors. The knock on effects of their applications are often not solving the issue of complex geometries and potentially lower NWB fracture widths, reducing fracture effectiveness in connecting to the main fracture and to any stimulated reservoir volumes. Typically, analytical methods to predict fracture initiation assume a circular, undamaged wellbore. We will provide some analytical and numerical modelling used to explore the likely geometries that might result from damage to the stress cage from drilling induced tensile (DITF) and drilling induced petal fractures (DIPF), natural fracture leakoff, and wellbore breakout. Next, we will discuss drilling strategies that create these effects and propose improved techniques to achieve more stable, smoother wellbore conditions. These would provide a less damaged stress cage from which trial completion strategies might be applied to reduce fracture complexity. To identify areas for completion improvement, we will present data from recent research and results from other complex stress environments, which when combined with other successfully implemented Cooper Basin completion, might improve future multistage hydraulic fracturing treatments. Finally, whilst any journey starts with a single step, it is unlikely that any one modelling, drilling, or completion strategy will individually unlock the problematic areas of the Cooper Basin. It is likely to require the application of improvements in all areas in tandem to generate this solution. In the final section, we will explore areas for future research in the areas of geomechanical modelling, drilling, and completions that must be pursued to achieve this goal. Analytical and Numerical Modelling Results As fracture initiation is a perceived problem, finite element models and analytic methods can provide insight into fracture initiation pressures and initial trajectories where natural fractures or wellbore flaws may be influencing the initiation. To understand these effects, we illustrate separate wellbore cases with and without natural fractures or flaws at various angles to the maximum principle stress (i.e., maximum horizontal stress, H Max) based on a strike slip stress state case representing typical Cooper Basin stress conditions. The data set used for the modelling (Table 1) is based on typical strike slip conditions indicative of the Cooper Basin, and represents values expected near 2500m consistent with published stress models of the Cooper Basin (Reynolds et al., 2006) Johnson 2

3 Table 1. Input data for geomechanical and hydraulic fracture modelling Data Value Maximum horizontal stress ( H Max, MPa) 120 Minimum horizontal stress ( h min, MPa) 50 Vertical Stress( vert, MPa) 65 Young s Modulus (E, GPa) 40 Poisson s Ratio ( dim) 0.25 Maximum principal stress at damage initiation (MPa) 8 Wellbore pressure applied to initiate (MPa) 35 Wellbore diameter (inch) 8.5 Wellbore depth (m) 2500 Estimated Reservoir Pressure (MPa) 25 Analytical models can be used to derive DITF and fracture initiation pressures based on solutions derived from the Kirsch equations (Brudy and Zoback, 1999) and often predict drilling induced tensile failure at low pressure conditions, consistent with Cooper Basin image logs. However, observed fracture initiations are much higher than anticipated using these same analytical models, requiring a need to find alternative, numerical models to explain these behaviours. To numerically simulate the fracture propagation from open hole circular and elliptical wellbores, we have presented results using an Extended Finite Element Method (XFEM) to model initiation and propagation of fractures. This is a numerical technique introduced to model cracks independent of meshes (Belytschko and Black, 1999); it allows simulation of discrete crack initiations and propagation along arbitrary, solution dependent paths without re meshing requirements. The methodology can be summarized by the equation (1): (1) Where: is u is the displacement vector, N I are shape functions, u I are nodal displacement vectors, H( ) are jump functions, a I are nodal enriched degree of freedom vectors, F are asymptotic crack tip functions, and are nodal enriched degree of freedom vectors. The initiation of a fracture occurs when the maximum principle stress reaches a critical value, and =1, using equation (2): (2) Where: is the normal stress acting on the initiated fracture plane and is the maximum principal stress at fracture initiation. To represent borehole breakout an elliptical wellbore shape is used and a natural fracture or flaw is introduced from 15 to 60 from H Max in 15 increments. Using these models, we compare initiation pressures to a smoother circular or elliptical cases and visualize early fracture propagation paths. Figures 2 and 3 represent fracture initiations from smooth circular and elliptical wellbores. In figure 2, the initiated fracture is vertical and oriented 30ᵒ from the H Max orientation, as expected for a strike slip stress regime. However, the fracture has not propagated adequately to escape the hoop stress effects and reorient itself in the H Max direction. In figure 3, the fracture initiated and propagated in the H Max direction. This indicates the effect of the wellbore shape on redistributing the hoop stress and effects on initiation points of hydraulic fractures Johnson 3

4 Figure 2. Numerical modelling results in a circular wellbore Figure 3. Numerical modelling results in a an elliptical wellbore Figures 4 7 illustrate fracture initiations where natural fractures were introduced to the elliptical wellbore in 15 increments from the H Max direction. In the 15 & 30ᵒ models, fracture propagation shows strong branching indicating high effects of heterogeneity and a general tortuosity towards the direction of H Max. However, as the angle increased to 45 60, H Max prevented the propagation of fractures under the same pumping pressure and stress shadowing prevented new fracture initiations and limited substantial propagation by any fracture. Whilst this modelling does show some differences and similarities to prior work, is at an early stage and further investigations of meshing and flaw introduction will be investigated Johnson 4

5 Figure 4. Numerical modelling results from an elliptical wellbore with natural fracture direction 15 from H Max direction. Figure 5. Numerical modelling results from an elliptical wellbore with natural fracture direction 30 from H Max direction Johnson 5

6 Figure 6. Numerical modelling results from an elliptical wellbore with natural fracture direction 45 from H Max direction. Figure 7. Numerical modelling results from an elliptical wellbore with natural fracture direction 60 from H Max direction. Drilling Effects and Strategies Drilling induced petal fractures (DIPF) (e.g., petal, centreline and petal centreline) can occur ahead of the bit during drilling as a result of stress imbalances caused by removal of in situ stress and interaction with bit loading forces. Studies based on theoretical reconstructions of stresses at a core bit concluded that failure occurred on the periphery of the core and slightly ahead of the bit (GangaRao et al., 1979). The strike of these fractures is controlled primarily by in situ stresses, but studies suggest that they are also influenced locally by shear stresses inherent from bit rotation (e.g., rotary drilling) (Lorenz and Finley, 1988). These studies concluded that regular spaced petal fractures originate during abrupt increases in vertical bit stress caused by regularly increased weight on bit and can extend at least three wellbore diameters from the side of the wellbore; which are then potential sites for fracture initiation that is not aligned with Johnson 6

7 the far field stress direction. Lorenz and Finley noted the absence of such fractures from smoother drilling techniques whilst other research into DIPF determined that various other drilling factors including bit type also influence the extent of wellbore damage (Fuenkajorn and Daemen, 1992). Although public data is limited, petal fractures were observed to be present in the small sample of Cooper Basin core images available (Figure 8). Anecdotal evidence in conjunction with photographic indication of existence in the Cooper Basin leads us to believe that based on the parameters, drilling techniques may be contributing to the extent of DIPF. This suggests that applying a lower and more consistent weight on bit (e.g., turbine drilling techniques) and reduced circulating pressures may result in a reduction in the occurrence of DIPF and DITF, aiding fracture initiation and near wellbore propagation. Figure 8. Core photographs from the Cooper Basin indicating potential petal fractures Other Modelling, Completion Effects and Strategies Other authors have investigated fracture propagation using two dimensional numerical models to analyse initiation and growth of hydraulic fractures from a wellbore, aligning the well either with the maximum or intermediate principal stress (Jeffrey and Zhang, 2010). Their modelling results show that hydraulic fracture width is narrowed at the wellbore for misaligned fractures that reorient as they grow away from the well; ultimately, the far field pressures of these fractures are equal to or below those expected for an aligned planar fracture. Further, they noted that while wellbore pressure did not significantly increase with smoothly, curving fractures; however, when a modelled fracture is segmented and includes offsets, then the pressure increases significantly with the reduction of width. Together, these factors can contribute to high NWB pressures and potential failure to maintain a conductive NWB propped fractures. Figure 9 from Jeffrey and Zhang (2010), summarises this modelling work and shows fracture growth paths as a function of a non dimensional parameter, F that controls curving of the path (see equation 3). The rock is assumed to be homogeneous, elastic and isotropic. The fracture re orientation occurs more slowly as the value of F becomes smaller. Therefore, this result predicts that higher rate and higher viscosity will reduce curving (complexity) near the wellbore. Χ. (3) where H Max and h min are the maximum and minimum principal stresses, respectively, in the x y plane, R is the wellbore radius, E = E/(1 2 ) is the plane strain Young s modulus, =12 where is the fluid viscosity, and Q is the injection rate into both fracture wings per unit height of the fracture. Using the parameters listed in Table 1, and assuming injection of water at 2 m 3 /minute (12.58 bbl/min) per m of perforated zone length, F takes on a value of 1.67, implying rapid reorientation, primarily caused by the large deviatory stress conditions. This suggests that ensuring the initiation occurs in the plane of eventual hydraulic fracture growth will be the most effective control since the injection rate and viscosity have an effect that depends on their product raised to the ¼ power. However, use of higher viscosity fluid is likely to have other effects not captured by F or in this 2D modelling Johnson 7

8 Figure 9: Fracture paths calculated as a function of the non dimensional parameter F (after Jeffrey and Zhang, 2010). For the cases shown, h min = 60 MPa and H Max = 80 MPa. Jeffrey and Zhang s research supports the use of viscous fluids and high injection rates to initiate hydraulic fractures and reduce near wellbore fracture tortuosity; this method along with oriented perforating was used in a Cooper Basin trial to successfully reduce NWB effects (Johnson et al., 2002). Further, in an area of shallower depth but nevertheless a complex stress environment, diagnostic results had proven that a complex fracture would form in vertical wells (Johnson et al., 2010) based on natural fracture interaction with the stress regime. In this same area, orienting the well in the H Max direction in either 27.5 or 60 inclination resulted in less complex propagation as compared to a vertical well based on multiple hydraulic fracturing diagnostics used in both cases (Megorden et al., 2013). Combining these technologies, drilling a well in the azimuth of H Max and completing the well by aligning the perforations or slots with the H Max direction may result in lowered NWB pressures and more effective vertical fracture propagation in the Cooper Basin stress regimes. Conclusions and Recommendations Reorientation of hydraulic fractures NWB is known from experiments to result in segmentation of the fracture as the reorientation occurs. The path that is produced is highly complex and is associated with high entry losses during injection. Current numerical models are unable to reproduce details of the fracture segmentation process and this is an area of research that may lead to better understanding of initiation and improved understanding of the development of associated fracture complexity along the path of the fracture reorientation. Benefits may be realised by creating longitudinal or oblique fractures placed in inclined wells in the azimuth of H Max in complex stress regimes. Initially, placing longitudinal or oblique fractures may seem a capitulation strategy with less perceived benefits than applying North American transverse fracturing techniques. However, lower treating pressures, more effective fracture length and increased width will likely developed vertically with longitudinal or oblique fractures as compared to case histories of transverse fracturing in the Cooper Basin stress regimes where NWB complexities as well as vertical, and horizontal fracture components were all noted, and likely lead to sub optimal fracturing. Based on this work, several areas of drilling and completion practices could be optimized to reduce fracture initiation pressures and potentially hydraulic fracture complexity. Drilling with reduced pump pressures and using smoother, higher speed (turbine) drilling practices may reduce DITF and DIPF. Although borehole breakout will be difficult to eliminate based on the magnitudes of the horizontal stresses, particular care in assuring adequate wellbore cleanout, casing centralization, and reduced cement slurry shrinkage should be considered whether the wellbore is vertical or inclined. Finally, if Johnson 8

9 drilling in the vertical, h min or an alternative direction to those favourably oriented with H Max is still desirable, then efforts to perforate or slot the well in the H Max direction are recommended to initiate fractures in the correct plane, avoiding as much NWB tortuosity effects as possible. REFERENCES Belytschko, T. and Black, T. (1999). Elastic crack growth in finite elements with minimal remeshing. International Journal for Numerical Methods in Engineering, 45(5), Brudy, M. and Zoback, M. D. (1999). Drilling induced tensile wall fractures: implications for determination of in situ stress orientation and magnitude. International Journal of Rock Mechanics and Mining Sciences, 36(2), Fuenkajorn, K. and Daemen, J. J. K. (1992). Drilling Induced Fractures in Borehole Walls. Journal of Petroleum Technology, 44(02), 7. GangaRao, H. V. S., Advani, S. H., Chang, P., Lee, S. C., and Dean, C. S. (1979). In Situ Stress Determination Based On Fracture Responses Associated With Coring Operations, ARMA Paper presented at the 20th U.S. Symposium on Rock Mechanics (USRMS), Austin, Texas. Jeffrey, R. G. and Zhang, X. (2010). Mechanics of Hydraulic Fracture Growth From a Borehole, SPE Paper presented at the Canadian Unconventional Resources and International Petroleum Conference, Calgary, Canada. Johnson, R. L., Jr., Aw, K. P., Ball, D., and Willis, M. (2002). Completion, Perforating and Hydraulic Fracturing Design Changes Yield Success in an Area of Problematic Frac Placement the Cooper Basin, Australia, SPE Paper presented at the SPE Asia Pacific Oil and Gas Conference and Exhibition, Melbourne, Australia. Johnson, R. L., Jr., Scott, M., Jeffrey, R. G., Chen, Z. Y., Bennett, L., Vandenborn, C., and Tcherkashnev, S. (2010, September). Evaluating Hydraulic Fracture Effectiveness in a Coal Seam Gas Reservoir from Surface Tiltmeter and Microseismic Monitoring, SPE Paper presented at the SPE Annual Technical Conference and Exhibition, Florence, Italy. Lorenz, J. C. and Finley, S. J. (1988). Significance of Drilling and Coring Induced Fractures in Mesaverde Core, Northwestern Colorado: Sandia National Laboratories. Megorden, M. P., Jiang, H., and Bentley, P. J. D. (2013). Improving Hydraulic Fracture Geometry by Directional Drilling in Coal Seam Gas Formation, SPE Paper presented at the SPE Unconventional Resources Conference and Exhibition Asia Pacific, Brisbane, Australia. Reynolds, S. D., Mildren, S. D., Hillis, R. R., and Meyer, J. J. (2006). Constraining stress magnitudes using petroleum exploration data in the Cooper Eromanga Basins, Australia. Tectonophysics, 415, Johnson 9

10 Biographies Dr Raymond L. (Ray) Johnson, Jr. is currently Principal at Unconventional Reservoir Solutions and serves as Adjunct Associate Professor at the University of Adelaide and Fellow at the University of Queensland. He has a PhD in Mining Engineering, MSc in Petroleum Engineering, G.D. in Information Technology, and B.A, in Chemistry. Ray has been active in the Society of Petroleum Engineers (SPE), past chair of the SPE Queensland Section, 2013 co Chair of the SPE Unconventional Reservoir Conference and Exhibition Asia Pacific, and will be 2015 co Chair of the SPE Unconventional Reservoir Conference and Exhibition Asia Pacific. Dr Hani Abul Khair received his BSc in Earth and environmental sciences, his MSc sedimentology and his PhD in petroleum geosciences at the University of Jordan, Jordan. In 2008, he worked as petroleum geoscientist with Target Exploration UK, before taking a post doctoral position at the University of Jordan. In 2010, he joined the Australian School of Petroleum as a Research Associate focused on a shale gas project funded by Primary Industries and Resources SA (PIRSA). In 2011, he started working with the South Australian Centre for Geothermal Energy Resources on a project involved geomechanics and fractures in deep shale horizons Johnson 10

11 Dr Rob Jeffrey holds a PhD in Geological Engineering from the University of Arizona. Prior to joining CSIRO in 1989, he was employed by Dowell Schlumberger, working on hydraulic fracturing and specifically fracturing of coalbed methane wells. He continued with this research interest at CSIRO and has run a range of projects investigating hydraulic fracture mechanics in coal and in naturally fractured rocks. Rob was instrumental in introducing hydraulic fracturing to the mining industry for cave inducement and preconditioning of rock masses and this technology is now being used at mines in Australia and Chile. Rob is currently Leader of the hydraulic fracturing Team at CSIRO in Melbourne and is a member of SPE and ARMA. Dr Jeremy Meyer completed a BSc majoring in Applied Mathematics and Physics before completing a PhD in geomechanics as part of the Stress Group at Adelaide University. After initial work at the Australia School of Petroleum, Jeremy formed JRS Petroleum Research Pty. Ltd., which is now park of Ikon Science where he is Sr VP Geomechanics. He has spent the last 15 years working as a geomechanics and image log specialist throughout the Australasian region in a variety of sectors including conventional oil & gas, coal seam gas, geothermal energy and CO 2 sequestration. Jeremy is a member of SPE, PESA & AAPG Ms Carly Stark is the Well Stimulation Leader for Petro King Australia, an independent China based oil and gas technology company. She is responsible for leading well stimulation capability projects for the production enhancement team within the Australasian region. She graduated with honours in Petroleum and Chemical Engineering from the University of Adelaide and has previously held roles at Schlumberger and National Oilwell Varco where she worked in the Well Services and Downhole divisions, respectively. Her primary focus was centered on hydraulic fracturing in coalbed methane applications and drilling in Central Australia. Carly is a member of SPE Johnson 11

12 Mr James Tauchnitz is the Country Manager for Petro King Australia, an independent China based oil and gas technology company. He is responsible for Petro King operations from well planning, drilling, stimulations, completions, and operations in Australasia. James graduated from the University of Adelaide with honours in Petroleum and Chemical Engineering and has previously held a number of technical and management positions for Arrow Energy (Shell and CNPC JV), APLNG (Origin, ConocoPhillips, Sinopec JV) and BHP Billiton. Most recently he was Well Factory Manager for Arrow Energy where he held overall Project Management and stakeholder engagement responsibilities for the Daandine Expansion Project. James is a member of SPE and AMICDA Johnson 12