OR/15/066 Conclusions: knowledge gaps

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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.
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It is clear that there is considerable understanding of the initiation, propagation and arrest of hydraulic fracturing due to the downhole technologies employed during stimulation and exploitation. However, this knowledge is incomplete and a number of unknowns still exist. This is in part due to the depth that hydraulic fracturing occurs and the difficulty of acquiring information on the process at such depths.

One limitation of the understanding comes from the most significant source of information. The literature is dominated by examples of North American shale gas operations. Depending on the source of the estimate, between 50 000 and 100 000 wells have been drilled for shale gas/oil in North America; for instance 8,341[1] wells have been drilled in Pennsylvania alone by the end of 2014. This compares with no active shale gas production wells in Europe and less than 100 exploration boreholes drilled to assess the European shale gas resource. Research is needed as to the differences seen between the major North American shale gas formations (such as the Marcellus, Woodford, Haynesville, Barnett, Mancos, Bakken, New Albany and others) and the potential European shale gas plays (such as Alum (SE, DK), Baltic, Podlasie (PL), Lublia (PL), Dneipe (UA), Ponnonian-Transylvanian (SK, AT, HU, HR, BA, RS), Carpathian-Balkanian (RO), Saxony (DE), France Southeast (FR), Paris (FR), North Sea — German basin (DE), Bowland, Lias, Oxford, Corallian, Kimmeridge, Gullane, West Lothian Oil Shale, Lower Limestone, Limestone Coal (UK), Lusitanian (PT), Cantabrian (ES)). Geologically there are clear differences between the basins that host these shales and it cannot be assumed that hydraulic fracturing will have the same consequences on the different rocks in both continents. The main differences that might occur between all prospective shale gas plays is thickness of high TOC facies, mineralogy of individual facies, relative tensile strength and elastic properties of facies, degree of natural fracturing, and in situ stress state.

A gap in the understanding results from the general lack of well-preserved core material from depth that has been obtained by pressure-coring to maintain the stress state of the samples. This also reduces the effects of drying, chemical, and biological degradation and is vital in order to compare datasets from the same shale gas play, or between different shale gas plays. Numerous experimental studies have been conducted on core material that has not been preserved and in some cases has been air-drying for decades. This will influence experimental results and is therefore undesirable. Comparison of experimental studies is also made difficult by the lack of disclosure of experimental protocols used by different workers. Little research has been conducted on quantifying tensile and/or hydraulic fracturing properties in the laboratory or on the effect of perforation on the mechanical properties of shale. It is clear that mineralogy plays a major control on the initiation of fractures in shale. More research is required in order to quantify the influence of different mineral constituents on the overall mechanical properties. A better understanding of where and how fractures are initiated is also required.

Shale is a highly variable and heterogeneous material. Both variability and heterogeneity need to be better understood and incorporated into numerical models. The drilling of a deviated well creates a complex stress field. The complexity of stress can be described for a perfectly elastic medium, the complexity of shale variability and anisotropy need to be incorporated so that a better understanding of where fracture initiation is likely to occur.

Many numerical approaches exist; modelling should work towards a unified approach of describing fracture propagation in shale. Numerical models tend to over-predict the length of hydraulic fractures that are formed. Current understanding of fracture arrest in a complex geological unit, such as shale, needs to improve to numerically represent the hydraulic fracturing process. Experimental observations are needed on fracture propagation in a complex, layered shale in order to identify the controls of fracture deviation and/or arrest. Shale does not behave as a perfect elastic medium and as a result numerical models need to incorporate the full thermo-hydro-mechanical-chemical coupled behaviour of the rock. Many studies have been conducted that consider shale as a uniform, homogenous, elastic material. Whilst complexity is difficult to incorporate within numerical models, representative physics is required with good ground truth field data.

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 stimulated reservoir volume. 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. The presence of microfractures in shale formations and their influence on hydraulic fracture propagation is poorly understood and represents a gap in understanding. It is vital that similar observations are made for shale-gas prone formation in Europe to describe the expected natural fracture population.

Microseismic monitoring has increased knowledge of the extent of the stimulated reservoir volume. However, the full complexity of the formed fracture network is not fully understood; for instance, a means of determining fracture density is required. Microseismic monitoring has allowed model predictions to be calibrated and refined, although numerical models have been limited in their ability to fully describe hydraulic fracturing in certain settings suggesting the full physics of the system is not encapsulated within the modelling approaches.

Drilling engineering plays an important role in controlling hydraulic fracturing. The fracture fluid volume plays a role on the full extent of hydraulic fractures. While the processes governing the role of fluid volume are understood, a means of predicting fracture propagation lengths is not yet available. The process of leak-off also needs to be better understood in order to predict fracture lengths. The role of hydraulic fracture fluid pressurization rate is acknowledged as contributing to fracture lengths, yet a full understanding of this has not yet been achieved. Advanced drilling techniques have been proposed, with the full consequence of these strategies yet to be realized. Complex, controlled fracture networks are theoretically possible; these need to be properly tested in the field to refine drilling engineering. The full impact of proppants and additives on hydraulic fluid viscosity and subsequent fracture propagation is also required.

Fisher & Warpinski (2011)[2] highlight the state of knowledge of the shale gas system. They state that an understanding of the geology surrounding the target area is needed in order to estimate the direction of fracture propagation. Their concluding remarks clearly assess the current state of understanding:

“The directly measured height growth is often less than that predicted by conventional hydraulic-fracture propagation models because of a number of containment mechanisms… Some of those mechanisms include complex geologic layering, changing material properties, the presence of higher permeability layers, the presence of natural fractures, formation of hydraulic-fracture networks, and the effects of high fluid leak-off.”
“Fracture physics, formation mechanical properties, the layered depositional environment, and other factors all conspire to limit hydraulic-fracture-height growth, causing the fracture to remain in the nearby vicinity of the targeted reservoirs.”

Thus the current state of knowledge is yet to fully predict the extent of hydraulic fracturing during shale gas operations and the comparisons and contrasts seen between European and North American shale facies has yet to be fully defined.

References

  1. Source: Pennsylvania Department of Environmental Protection, quoted at http://geology.com/articles/marcellus-shale.shtml
  2. Fisher, K, and Warpinski, N. (2011). Hydraulic fracture-height growth: real data. Paper SPE 145949 presented at the Annual Technical Conference and Exhibition of the Society of Petroleum Engineers, Denver, Colorado. DOI: 10.2118/145949-MS.