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«on need) Total frac lengths 1000-1500 ft  Multiple Well Stimulation In a typical stage, water and sand were pumped at a rate of 50-70  bbls/min ...»

Rock Failure, Stimulated Volume &

Permeability Enhancement in Gas

Shale HF

Ahmad Ghassemi

HF, Multiple Fractures

Multiple horizontal are drilled to

increase more contact area

between the well and the

reservoir

Wells are stimulated in multiple

 Sv

Sh

stages (1-10 per well, depending SH

on need)

Total frac lengths 1000-1500 ft

Multiple Well Stimulation

In a typical stage, water and sand were pumped at a rate of 50-70

 bbls/min Large volumes of pumped water per stage (100000-1,000,000  gal) Horizontal Wells toe Stage 1 Stage 1 Stage 2 Stage 2 heel Stage 3 Stage 3 Z-Frac S-Frac Mechanical Fracture Interaction HFs propagate perpendicular to the least principal 

in-situ stress unless:

Out of zone growth encouraged Sv Sh SH 4 In Addition to Stress, Fracture Growth is Controlled by Discontinuities  Courtesy Nemcok Frac fluid density  Permeability  Bons (2000) Local fracture growth  controlled by rock fabric Global fracture growth  controlled by total stress 5 H-Fracturing Perturbs Pore Pressure & Stress in Rock Distance from Fracture Surface (ft) 0 100 200 300 x=0 1 x=50 0.9 0.8 x=100 Δσz/net pressure 0.7 x=150 0.6 x=200 0.5 x=250 0.4 x=300 0.3 0.2 x=350

–  –  –

Distribution of the maximum and minimum (iii) principal effective stresses in the reservoir (MPa).

Shear/Tensile Failure Failure is caused by high  stresses near the tip of the fractures, & by increased pore pressure elsewhere

–  –  –

(i) Guess a value for permeability (ii) Predict the failed rock volume (FRV) using the stress analysis for a selected net fracture pressure (iii) Vary perm until the FRV matches the extent shown by induced seismicity for the given net fracturing pressures

–  –  –

The statements made during the workshop do not represent the views or opinions of EPA. The claims made by participants have not been verified or endorsed by EPA.

Introduction Generally, a tight gas reservoir is defined by its low permeability, however, it has been suggested (Holditch, 2007) to define a tight gas reservoir as one that “cannot be produced at economic flow rates or recover economic volumes of natural gas unless a special technique is used to stimulate production.” Large hydraulic fracture treatments, often from a horizontal wellbore or multilaterals must be used to increase the recovery efficiency in the reservoir.

Fracture conductivities of 10 mD/ft or higher appear to be necessary for economic gas production.

Shale gas reservoirs have heterogeneous geological and geomechanical characteristics that pose challenges to accurate prediction of their response to hydraulic fracturing. Experience in shale gas formations shows that stimulation often results in formation of a complex fracture structure, rather than the planar fracture aligned with the maximum principal stress. The fracture complexity arises from intact rock and rock mass textural characteristic and the in-situ stress and their interaction with applied loads. Open and mineralized joints and interfaces, and contact between rock units play an important role in fracture network complexity which affects the rock mass permeability and its evolution with time. Currently, the mechanisms that generate these fracture systems are not completely understood, and can generally be attributed to lack of in-situ stress contrast, rock brittleness, shear reactivation of mineralized fractures, and textural heterogeneity.

Stimulated Volume and Permeability Enhancement The idea of stimulation by hydraulic fracturing is to create a large volume of fractured rock with enhanced permeability. Many tight gas reservoirs are characterized by high deviatoric stresses and hard, naturally fractured rock. Stimulation treatments in such reservoirs may result from slip on pre-existing critically stressed fracture systems and or creation of new fractures. It is generally believed that fracturing is caused by both shear and tensile failure. Shear slippage is induced by altered stresses near the tip of the fractures as well as by increased pore pressure in response to leakoff through the fracture “walls”. In view of this, it has been suggested that increased viscosity promotes tensile failure and can lower complexity (Cipolla et al. 2008).

Accordingly, water fracs are used where shear failure is anticipated to dominate (Chipperfield, S.T., Wong, J.R., Warner, D.S. et al. 2007). According to Cramer (2008), water is used as a base fluid in most unconventional reservoir treatments.

To determine intact rock failure and joint slippage, a failure criterion is employed. There are many failure criteria for the sliding of jointed rock masses but often the Mohr-Coulomb failure criterion is used. By combining a stress analysis with a criterion, one can assess the effects of increasing pore pressure on rock by generating a structural permeability diagram. This map that shows the ΔP required to reactivate joints of different orientations (e.g., Nygren and Ghassemi, 2005; Nelson et al. 2007) during fracture stimulation treatments at high treating pressures. One such map is shown in Figure 3 for the New Albany Shale.

Figure 3. Structural Permeability Diagram for New Albany Shale ( µ=0.





6).

–  –  –

Most field implementation of stimulation involves creation of multiple hydraulic fractures and stimulation of the neighboring rock volume by compression and pore pressure increase.

Normally hydraulic fracturing is performed in horizontally-drilled wells. The geometry and propagation direction of a hydraulic fracture will mostly depend on the drilling direction of horizontal well and the in situ conditions as shown in Figure 4.

It is generally accepted that hydraulic fractures propagate perpendicular to the least principal stress. In shallower environments where the least principal stress is vertical, a fracture will grow horizontally. At some depth where the increase in overburden causes the least principal stress to be horizontal, the predominant fracture growth geometry will be vertical. Variations in stresses between different lithology in vertical sequences of rocks can cause fracture growth in a contained manner and generate length, or allow it grow vertically upwards or downwards. In addition to the in-situ stress, fracture growth will depend on many factors such as natural fractures, bed laminations, and other characteristics of a reservoir including the formation pore pressure in the reservoir. The pore pressure will affect the effective in situ stresses, and can further affect the post-fracturing deformation of rock and its natural fractures which will, in turn, influence the path of the hydraulic fracture (Koshelev and Ghassemi, 2001).

Fracture interaction Multiple stage hydraulic fracturing is popular in the stimulations of tight gas reservoirs.

Figure 5. Interaction of multiple fractures in a horizontal well.

Green represents closed fractures.

Note the fractures turning away from each other to follow the path of least resistance.

Figure 6. Fracture aperture distribution (in cm) after 3 hours of pumping in Barnett shale.

Estimating Stimulated Volume It is believed that microseismic events (Figure 8) are mainly created as a result of shear slippages around the hydraulic fractures (Albright and Pearson (1982); Warpinski et al. (2001);

Rutledge et al. (2003)). Shear slippage is induced by altered stresses near the tip of the fractures as well as shear slippages related to leakoff induced pore pressure changes.

Accepting that failure of the formation around a hydraulic fracture is caused by pore-pressure and stress perturbations, the stimulated reservoir volume (volume of “failed” rock in the reservoir) can be assessed using the areal extent of the micro-seismic cloud (Plamer et al. 2005;

Jun and Ghassemi, 2005). However, it should be this procedure for evaluation of stimulated volume and fracture surface area is based on the assumption that energy release is exclusively related to fluid penetration, which may not always hold true. The micro-seismic record may also be used to detect hydraulic connection with the outside zone.

Prediction of enhanced permeability The methodology of predicting the permeability in the failed region around a fracture is based on a trial and error procedure: (i) use the pressure profile at shut-in, and guesses a value for permeability, K; (ii) for a selected net fracture pressure, predict the failed rock volume (FRV) using the stress analysis; (iii) vary K until the FRV matches the particular trend-line of the stimulated reservoir volume from induced seismicity at the given net fracturing pressures. This method is based on the equivalent permeability for the failed rock and does not consider the time dependent behavior of rock and the fractures that are created. Furthermore, it is assumed that the MEQ’s are related to local pore pressure perturbations.

The interaction of the multiple hydraulic fracture stimulation on the larger scale flow regime is not clearly understood. The large stimulated volume that is generated tends to redistribute the stresses within the crust and can cause changes in nearby rock permeability. In this context, the presence of faults (active and inactive) need be considered.

Figure 7. Distribution of pore pressures (MPa) in the formation; minimum principal effective stress (Barnett shale, 0.

09 m3/s per fracture; 3 hrs) (Rawal & Ghassemi, 2011).

Figure 8. Microseismic map shows network growth and the potential stimulated volume in shale (GTI-NAS-Project).

Chipperfield, S.T., Wong, J.R., Warner, D.S. et al. (2007). Shear dilation diagnostics: A new approach for evaluating tight gas stimulation treatments. SPE Hydraulic Fracturing Technology Conference, College Station, Texas USA. SPE 106.

Cipolla, C.L., Warpinski, N.R., Mayerhofer, M.J. et al. (2008). The relationship between fracture complexity, reservoir properties, and fracture treatment design. SPE Annual Technical Conference and Exhibition, Denver, Colorado, USA. SPE 115.

Cramer, D.D. (2008). Stimulating unconventional reservoirs: lessons learned, successful practices, areas for improvement. SPE Unconventional Reservoirs Conference, Keystone, CO. SPE# 114172.

Ge, J., Ghassemi, A. (2011). Permeability enhancement in shale gas reservoirs after stimulation by hydraulic fracturing. Proc. 45th U.S. Rock Mechanics Symposium, June 26 –29, San Francisco.

Ge, J., Ghassemi, A. (2008). Analysis of failure potential around a hydraulic fracture in jointed rock. Proc. 42nd U.S. Rock Mechanics Symposium, June 29 – July 2, San Francisco.

Koshelev, V. & Ghassemi, A. (2003). Numerical modeling of stress distribution and crack trajectory near a fault or a natural fracture. Soil-Rock America Symp., Boston.

Nelson, E.J., et al. (2007). Using geological information to fracture optimize stimulation practices in the Cooper Basin, Australia. Petroleum Geoscience, (13), 3–16.

Nygren, A. and Ghassemi, A. (2005). Influence of cold water injection on critically stressed fractures in Coso Geothermal Field, CA. 40th U.S. Rock Mech. Symp., Anchorage, Alaska, June 25-29.

Palmer, I. D., Moschovidis, Z. A., and Cameron, J. R. (2005). Coal failure and consequences for coalbed methane wells. SPE 96872, ATCE, Dallas, 9-12 Oct 2005.

Peasron, C. (1981). The relationship between micro-seismicity and high pore pressure during hydraulic stimulation experiments in low permeability rocks. J. Geophy. Res., 86, B9, 7855.

Rawal, C., Ghassemi, A. (2011). Poroelastic rock failure analysis around multiple hydraulic fractures using a BEM/FEM model. Proc. 45th U.S. Rock Mechanics Symposium, June 29 – 29, San Francisco.

Rutledge, J., and Philips, W. (2003). Hydraulic stimulation of natural fractures as revealed by induced microearthquakes, Carthage Cotton Valley gas field, east Texas, Geophysics, 68(2), 441–452.

Warpinski, N.R., Wolhart, S.L., and Wright, C.A. (2001). Analysis and prediction of microseismicity induced by hydraulic fracturing. SPE 71649.



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