OR/15/066 Induced versus natural fractures

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Cuss, R J, Wiseall, A C, Hennissen, J A I, Waters, C N, Kemp, S J, Ougier-Simonin, A, Holyoake, S, and Haslam, R B. 2015. Hydraulic fracturing: a review of theory and field experience. British Geological Survey Internal Report, OR/15/066.

This chapter examines the inter-play of the pre-existing fracture network found in natural shale units and the induced hydrofractures created during hydraulic fracturing. As introduced in Fracture propagation, one of the limitations of fracture propagation theory is that it does not always take into account the natural fractures found in shale formations at a range of scales. These features may act as conduits for the hydraulic fracturing fluid, or stress perturbations that influence the fracture propagation direction. Whether fracture interplay results in fluid loss or influence fracture propagation direction, knowledge of induced versus natural fractures is vitally important.

In terms of shale gas exploration, the interplay of induced and natural fractures is desired as it leads to a complex fracture network that promotes gas extraction. In terms of regulation, knowledge of the interplay of natural and induced fractures is vital in order to ensure the shale unit is not breached, which might lead to leakage of hydraulic fracture fluid.

Hydraulic fracturing in shale gas reservoirs has often resulted in complex fracture network growth, due to promoting the propagation and connection of natural fractures, as evidenced by microseismic monitoring (Liu et al., 2015[1]). It has been studied extensively by researchers from different aspects: Gale et al. (2007)[2] studied the importance of natural fractures on hydraulic fracture treatments; Zhao et al. (2012)[3] presented new insight into fracture network generation in reopening and slippage of natural fractures; Yu et al. (2014)[4] performed a sensitivity study of gas production for a shale gas well with different geometries of multiple transverse hydraulic fractures; and Olson et al. (2009)[5] and Rahman & Rahman (2013)[6] investigated fracture propagation behaviour in the presence of natural fractures.

Natural fractures

The natural fractures in a shale can be defined by their geometric properties (e.g. width, length, spatial distribution, orientation), fluid properties (e.g. porosity, permeability) and their physical properties (e.g. fracture fill and fracture roughness). Describing all of these properties by using borehole data alone is very difficult, therefore observations from wells are often combined with field observations. Gale et al. (2014)[7] conducted an extensive field and borehole study of the natural fractures in many of the shale gas prone shale units in North America. Their approach was to compare and contrast the properties of the fractures and look for correlations between the shale formations.

The most common natural fracture Gale et al. (2014)[7] describe are sub-vertical and have formed perpendicular to the bedding plane; some were seen at 70–80° to the bedding plane. These fractures often terminated against bedding layers or intersected other structures within the shale. Much of this data came from core, so Gale et al. (2014)[7] describe the fractures in terms of the number of vertical fractures per 100 ft (30.5 m) of vertical core; this number varies from 7 to 160 per 100 ft (1 fracture per 0.2 to 4.4 metres). In some cases, a correlation was observed between high fracture density and mineralogy; for example the Forestburg Limestone had a very high carbonate content and a high fracture density, whereas the Marcellus Shale has a high clay content and a low fracture density. Zeng et al. (2013)[8] measured fracture density in the Longmaxi Shale Formation in China and found that fracture density positively correlated with total organic carbon (TOC), however for the Niutitang Shale fracture density negatively correlated. Zeng et al. (2013)[8] argue the Longmaxi shale has a positive correlation with TOC due to the thermal evolution of organic acids which have dissolved carbonate and feldspar, which has increased the porosity and also the susceptibility to fracture under external forces. Zeng et al. (2013)[8] suggest that mineralogy, such as brittle mineral content, acts as the predominant control on fracturing. Fracture density will also be controlled by large-scale tectonic structures, which are areas of high deformation; for instance folds and thrusts are more likely to have a higher fracture density (Zeng et al., 2013)[8].

Gale et al. (2014)[7] report that the fracture aperture of the observed sub-vertical fractures ranged from 30 µm to 10 cm, however the large majority of these fractures were between 30 µm and 1 mm. Furthermore, the fracture heights varied from <1 cm to 1.8 metres. It has to be noted that these lengths were recorded from core and that the fractures may have extended further. Many of the sub-vertical fractures were recorded in detail; however, as they were measured from narrow bore core it was not always possible to analyse the fracture tips to examine the mechanisms that arrested fracture propagation.

Zeng et al. (2013)[8] reported observations on natural fractures in core material from China. Only 2.5% of the fractures terminated abruptly by stratigraphy, 26.5% gradually tapered to a stop, while 71% of the fractures ended off the core. Therefore of the fracture tips that could be observed 8.6% terminated abruptly by stratigraphy, while 91.4% gradually tapered. Ferril et al. (2014)[9] conclude that bed-scale compositional and textural variations in the Eagle Ford shale led to contrasting mechanical behaviour with regards to fracture propagation and length.

As described above, many of the gas producing shale formations in North America contain sub-vertical fractures. To form a highly conductive natural fracture network these fractures must be connected. Gale et al. (2014)[7] also describe a set of fractures parallel to bedding, although these are not ubiquitous in all of their studied shale formations. These bedding parallel fractures were up to 15 cm wide and extended for tens of metres laterally (Rodrigues et al., 2009[10]). The fracture density of these bed-parallel fractures varied significantly throughout the same formation; for example the Vaco-Muerta Formation in Argentina contained just one bed-parallel fracture at outcrop scale at one location, whereas at another outcrop of similar size 100 bed-parallel fractures were described with thicknesses up to 5 cm.

Many of the fractures, both bed parallel and sub-vertical, described by Gale et al. (2014)[7] were filled with calcite cement. Cemented fractures and faults give evidence for fluid flow within the rock, this may have occurred during diagenesis or during another part of the burial history. The most common cement to have been described is a fibrous calcite cement, although quartz filled fractures were also observed (Gale et al., 2007[2]; Montgomery & Jarvie, 2005)[11]. In the Barnett Shale, Gale et al. (2007)[2] and Montgomery et al. (2005)[11] state that all sub-vertical fractures were calcite filled. Montgomery et al. (2005)[11] believe that the calcite filled cements are a barrier to fluid flow. However, Gale et al. (2007)[2] oppose this as they state the low tensile strength of the cement and the fact that it is not in crystallographic continuity with the fracture walls means that it will be re-activated and therefore not a barrier to fluid flow (Zeng et al. 2013)[8]). Gale & Holder (2008)[12] showed that calcite filled fractures have half the strength of intact rock. They also showed that quartz filled fractures in the Woodford shale are stronger than the host rock. Zeng et al. (2013)[8] describe natural fractures in Niutang and Longmaxi shale from core material in China. They state that a high density of natural fractures will be beneficial to the hydraulic fracturing process even if filled with calcite cement, resulting in an increase of gas flow to the well.

The limited research summarized above shows that vertical fractures of varying density predominate in shale formations. Bedding-parallel fractures may also be present, but are not ubiquitous. The scale of the fracturing is variable, as is the mineralogy of cement infill. In certain cases this mineral infill can strengthen the host rock, whereas in others it is a mechanical weakness. There is evidence that geomechanical variations between facies within a shale formation can result in fracture arrest, although this is not the only mechanism that results in fracture termination. It is vital that similar comparisons are made with shale-gas prone formation in Europe to describe the expected natural fracture population.

Interaction of natural and induced fractures

The benefits, or not, of a natural fracture network for the hydraulic fracturing process are an area of current research and debate. Ferril et al. (2014)[9] state that natural fractures can act to compartmentalise fluid pressure during the hydraulic fracturing process. This may result in the injected fracturing fluid flowing through the natural fracture network, resulting in the pressurized fluid being dispersed over a larger area thus reducing fluid pressure (leak-off). This may result in fluid pressure reducing below the tensile strength of the shale arresting hydraulic fracture propagation. However, the injection of a pressurized fluid into a naturally fractured volume may result in the reactivation of fractures if calcite cement is sufficiently weak. This could potentially result in an increase in flow of hydrocarbons through the natural fractured network towards the well.

Zhao et al. (2012)[3] and Gale et al. (2007)[2] have proposed a theory of how natural and hydraulic fractures may interact. When the initial hydraulic fracture from the well intersects a natural fracture, it will form two left and right branches. These branches will propagate along the natural fracture, until they reach the crack tip, at which point they will change direction and propagate in the direction perpendicular to σ3; as shown in Figure 9. This process can continue until the fluid pressure within the fractures is less than σ3. If a shale formation has a complex natural fracture network, the injection of hydraulic fluid is likely to only ‘activate’ this network, as opposed to producing a complex network of fractures.

Figure 9    Representation of the interaction of natural and induced hydrofractures in shale gas operations.

Microfractures

At a smaller scale to the natural fractures discussed above, microfractures within shale formations may play an important role in fracture propagation. Lockner et al. (1992)[13] showed that before a rock fails there is an increase in microcracks which coalesce to form a larger failure plane; therefore meaning a high abundance of microcracks may mean that it is easier for a failure plane to develop during the hydraulic fracturing process. Pitman et al. (2001)[14] showed bed-parallel microfractures in the dolomitic siltstone of the Bakken Formation and Capuano (1993)[15] found microfractures in Oligocene Frio Formation shale.

Microfractures form due to the actual splitting apart of the rock fabric in the direction of least resistance, i.e. perpendicular to the minimum in-situ stress direction or least principal stress. Since shale can be described as a multi-phase and multi-scale sedimentary rock mainly composed of clay platelets surrounding inclusions of other, stiffer minerals (e.g. quartz, calcite, and/or pyrite) or more compliant organic phases (kerogen), local density contrasts are very likely to occur. In fact, microfracturing may be the rule rather than the exception (Vernik, 1993 [16], 1994[17]; Vernik & Liu, 1997[18]; Lash & Engelder, 2005[19]; Padin et al., 2014[20]). It could arise from the internal production of fluids by the organic matter decay or the dehydration of clays (shrinkage processes); in that case, microfractures are expected to be predominantly parallel to the bedding plane (e.g. Harrington & Horseman, 1999[21]; Keller et al., 2011[22]; Jiu et al., 2013[23]). Several studies have demonstrated that microfracture populations correlate to the shale content of brittle minerals, such as quartz, calcite, dolomite, and/or feldspar (e.g. Nelson, 2009; Hill et al, 2002[24]; Nie et al., 2009[25]; Li, 2009[26]; Ding et al., 2012[27]; Zeng, 2013[8]). The presence of microfractures mostly relies on the combination of many factors through the shale history.

It has been observed that the finer the grain size, the more conducive the shale matrix will be to fracture development, providing shales with similar mineral compositions (Zeng & Xiao, 1999[28]; Li et al., 2009[26]). However, if natural fractures are known to have a positive impact on the permeability of a shale formation (e.g. Decker, 1992[29]; Gale et al., 2007[2], 2014[7]; Ding et al., 2012[27]; Zeng et al., 2013[8]), the role of microfractures on shale permeability seems to be more complex. Padin et al. (2014)[20] argue that the microfracture network also acts as permeable pathways when fluid pressure is increased, Zeng et al. (2013)[8] argue that it will also be extremely unfavourable to the preservation of hydrocarbons. After microfracture formation, fluid flow may occur allowing the precipitation of minerals, which may seal them; fully filled (micro)fractures will act as fluid barriers (Warpinski & Teufel, 1987[30]).

Gale et al. (2014)[7] hypothesize a power law relationship for fracture width and length, using data from the Marcellus Shale and Austin Chalk. If this power law is extrapolated into the microfracture domain, the average spacing for fractures would be approximately 0.1 to 1 m. Thus the paucity of microfracture data may be due to the low probability of microfractures being captured in core samples. The presence of microfractures in shale formations and their influence on hydraulic fracture propagation is poorly understood and represents a gap in understanding. Moreover, since elastic properties evolve with the scale and damage, any upscaling procedure is challenging despite the crucial contribution of microfractures to the fracture formation.

Conclusions on induced vs natural fractures

Natural fractures and microfractures may represent planes of weakness within natural shale formations. It is likely that the density and orientation of these features will influence fracture propagation. Thus, the interaction between natural fractures and hydraulic fractures is a key area of research. Natural fracturing will be controlled by current and historical tectonic stresses and mineralogy. Mineral infill of geological fractures also has a control on whether natural fractures influence hydraulic fractures or not. Therefore an increase in knowledge of natural fracture properties, the stress regime, the role of mineralogy, and the interaction of natural and induced hydrofractures is required to better understand the potential stimulated reservoir volume.

Knowledge gaps and recommendations

This chapter has described the state of understanding of the interaction of induced hydraulic fractures and the natural fracture/microfracture network within shale. The following statements on our current knowledge, knowledge gaps and recommendations can be made:

  • In order to predict the influence of natural fracture populations on hydraulic fracture propagation it is vital to understand the natural fractures. Limited studies have been conducted on natural fractures at depth and this represents a clear gap in our understanding.
  • Discontinuities occur on a range of scales, from microfractures through to regional scale faults. The influence of these features on hydraulic fracture propagation needs to be better understood.
  • The presence of microfractures in shale formations and their influence on hydraulic fracture propagation is poorly understood and represents a gap in our understanding.
  • Generally, vertical fractures of varying density predominate in shale formations. Bedding-parallel fractures may also be present, but are not ubiquitous. Therefore a better understanding of the full three-dimensional orientation of fracture sets and the influence this has on fracture propagation and arrest is required.
  • Mineral infill within fractures may act to either strengthen or mechanically weaken the host rock. A full assessment of the role mineralised fracture fill has on mechanical strength is needed.
  • Fracture population studies need to be conducted for European shale plays and these need to be carefully assessed based on North American experiences.
  • The full 3-dimensional description of natural and hydraulically induced fractures is required. This needs to include data on fracture roughness/topology, aperture, length, and extent.
  • Numerical models of fracture propagation need to take into account shear movement that occurs along natural fractures when they are reactivated during stimulation.

References

  1. ↑ Liu, C, Liu, H, Zhang, Y, Deng, D, and Wu, H. (2015). Optimal spacing of Staged fracturing in Horizontal shale-gas well. Journal of Petroleum Science and Engineering.
  2. ↑ 2.0 2.1 2.2 2.3 2.4 2.5 Gale, J F, Reed, R M, and Holder, J. (2007). Natural fractures in the Barnett Shale and their importance for hydraulic fracture treatments. AAPG Bulletin, 91, pp.603–622.
  3. ↑ 3.0 3.1 Zhao, H, Chen, M, Yan, M, Ding, Y, and Wang, Y. (2012). Rock fracture kinetics of the fracture mesh system in shale gas reservoirs. Petroleum Exploration and Development, 39, pp.498–503.
  4. ↑ Yu, W, Luo, Z, Javadpour, F, Varavei, A, and Sepehrnoori, K. (2014). Sensitivity analysis of hydraulic fracture geometry in shale gas reservoirs. Journal of Petroleum Science and Engineering, 113, pp.1–7.
  5. ↑ Olson, J E, and Taleghani, A D. (2009). Modelling simultaneous growth of multiple hydraulic fractures and their interaction with natural fractures. In SPE Hydraulic Fracturing Technology Conference. Society of Petroleum Engineers.
  6. ↑ Rahman, M M, and Rahman, S S. (2013). Studies of hydraulic fracture-propagation behavior in presence of natural fractures: fully coupled fractured-reservoir modeling in poroelastic environments. International Journal of Geomechanics. 13, pp.809–13,826.
  7. ↑ 7.0 7.1 7.2 7.3 7.4 7.5 7.6 7.7 Gale, J F W, Laubach, S E, Olson, J E, Eichbul, P, and Fall, A. (2014). Natural fractures in shale: A review and new observations. AAPG Bulletin, 11, pp.2165–2216.
  8. ↑ 8.0 8.1 8.2 8.3 8.4 8.5 8.6 8.7 8.8 8.9 Zeng, W, Zhang, J, Ding, W, Zhao, S, Zhang, Y, Liu, Z, and Jiu, K. (2013). Fracture development in Paleozoic shale of Chongqing area (South China). Part one: Fracture characteristics and comparative analysis of main controlling factors. Journal of Asian Earth Sciences, 75, pp.251–266.
  9. ↑ 9.0 9.1 Ferril, D A, McGinnis, R N, Morris, A P, Smart, K J, Sickmann, Z T, Bentz, M, Lehrmann, D, Evans, M A. (2014). Control of mechanical stratigraphy on bed-restricted jointing and normal faulting: Eagle-Ford Formation, south-central Texas. AAPG Bulletin, 11, pp.3477–2506.
  10. ↑ Rodrigues, N, Cobbold, P, Loseth, H, and Ruffet, G. (2009). Widespread bedding-parallel veins of fibrous calcite (beef) in a mature source rock (Vaca Muerta Fm, Neuquen Basin, Argentina): evidence of overpressure and horizontal compression. Journal of the Geological Society, 166, pp.695–709.
  11. ↑ 11.0 11.1 11.2 Montgomery, S L, Jarvie, D, Bowker, K, and Pollastro, R M. (2005). Mississippian Barnett Shale, Fort Worth basin, north-central Texas: Gas-shale play with multi-trillion cubic foot potential. AAPG Bulletin, 89, pp.155–175.
  12. ↑ Gale, J, and Holder, J. (2008). Natural fractures in the Barnett Shale: Constraints on spatial organization and tensile strength with implications for hydraulic fracture treatment in shale- gas reservoirs. Proceedings of the 42nd US Rock Mechanics Symposium.
  13. ↑ Lockner, D, Byerlee, J, Kuksenko, V, Ponomarev, A, and Sidorin, A. (1992). Observations of quasistatic fault growth from acoustic emissions. International Geophysics, 51, pp.3–31.
  14. ↑ Pitman, J, Price, L, and LeFever, J. (2001). Diagenesis and fracture development in the Bakken Formation, Williston basin: Implications for reservoir quality in the Middle Member. U.S. Geological Survey Professional Paper 1653.
  15. ↑ Capuano, R M. (1993). Evidence of fluid flow in microfractures in geopressured shales. AAPG Bulletin, 77, pp.1303–1314.
  16. ↑ Vernik, L. (1993). Microcrack-induced versus intrinsic elastic anisotropy in mature HC-source shales. Geophysics, 58, pp.1703–1706.
  17. ↑ Vernik, L. (1994). Hydrocarbon-generation-induced microcracking of source rocks. Geophysics, 59, pp.555–563.
  18. ↑ Vernik, L, and Liu, X. (1997). Velocity anisotropy in shale: a petrophysical study. Geophysics, 62, pp.521–532.
  19. ↑ Lash, G G, and Engelder, T. (2005). An analysis of horizontal microcracking during catagenesis: Example from the Catskill delta complex. AAPG bulletin, 89, pp.1433–1449.
  20. ↑ 20.0 20.1 Padin, A, Tutuncu, A N, and Sonnenberg, S. (2014). On the Mechanisms of Shale Microfracture Propagation. Society of Petroleum Engineers.
  21. ↑ Harrington, J F, and Horseman, S T. (1999). Gas transport properties of clays and mudrocks.Geological Society, London, Special Publications, 158(1), pp.107–124.
  22. ↑ Keller, L M, Holzer, L, Wepf, R, and Gasser, P. (2011). 3D geometry and topology of pore pathways in Opalinus clay: Implications for mass transport. Applied Clay Science, 52, pp.85–95.
  23. ↑ Jiu, K, Ding, W, Huang, W, Zhang, Y, Zhao, S, and Hu, L. (2013). Fractures of lacustrine shale reservoirs, the Zhanhua Depression in the Bohai Bay Basin, eastern China. Marine and Petroleum Geology, 48, pp.113–123.
  24. ↑ Hill, D G, Lombardi, T E, and Martin, J P. (2002). Fractured Shale Gas Potential in New York. Arvada, Colorado, pp.1–16.
  25. ↑ Nie, H K, Tang, X, and Bian, R K. (2009). Controlling factors for shale gas accumulation and prediction of potential development area in shale gas reservoir of South China. Acta Petrolei Sinica, 30(4), pp.484–491.
  26. ↑ 26.0 26.1 Li, D H, Li, J Z, Wang, S J, and Li, X J. (2009). Conditions of shale gas reservoir formation. Natural Gas Industry, 29(5), pp.22–26 (in Chinese with English abstract).
  27. ↑ 27.0 27.1 Ding, W L, Chao, L, Chunyan, L, Changchun, X, Kai, J, Weite, Z, and Liming, W. (2012). Fracture development in shale and its relationship to gas accumulation. Geoscience Frontiers, 3, pp.97–105.
  28. ↑ Zeng, L B, and Xiao, S R. (1999). Fractured mudstone reservoir bodies in low permeability reservoirs. Petroleum Geology and Experiment, 21(3), pp.266–269 (in Chinese with English abstract).
  29. ↑ Decker, D, Coates, J M P, and Wicks, D. (1992). Stratigraphy, gas occurrence, formation evaluation and fracture characterization of the antrim shale, Michigan basin. Topical report, January 1990-March 1992 (No. PB-95-104634/XAB). Advanced Resources International, Inc., Lakewood, CO (United States).
  30. ↑ Warpinski, N R, and Teufel, L W. (1987). Influence of Geologic Discontinuities on Hydraulic Fracture Propagation (includes associated papers 17011 and 17074), Society of Petroleum Engineers, SPE-13224-PA, doi: 10.2118/13224-PA.
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