Risks and opportunities associated with shale plays as unconventional projects go global. (Part 2/5)
Posted by D Nathan Meehan November 20, 2013

Risks and opportunities associated with shale plays as unconventional projects go global. (Part 2/5)

Some of this material was prepared for presentation at the ADIPEC 2013 Technical Conference, Abu Dhabi, UAE, 10-13 November 2013 in a presentation titled “A Consistent Approach to Source Rock Resource Evaluation and Optimization.” This is the second in a series of five blog entries on the subject.


Shale heterogeneities

Shale heterogeneities exist at many levels. Fathi and Akkutlu (Ebrahim Fathi, 2009) examine very fine scale heterogeneities and conclude, “…that the local heterogeneities can generate non-trivial transport and kinetic effects which retard gas release from the matrix and influence the ultimate gas recovery adversely.”  Analysis of FIB/SEM, QRMESCAN® EDS and XRD measurements show these fine scale variations. Such heterogeneity is common at the micro- and nano-scale for many producing formations, particularly carbonates. However, conventional resources primarily store moveable hydrocarbons in pores (and to a far lesser extent fractures) and use connected pores and fractures for production. Shale reservoirs also store free gas; however, gas is also sorbed on organic and mineral surfaces within natural fractures and within the matrix. Gas is also dissolved in hydrocarbon liquids present in bitumen. Kerogens may or may not be porous and the long-term role of sorbed and dissolved gas is not clear.

Marine shales are generally deposited in relatively low energy environments and thus should be (at the fine scale) laterally continuous. Unfortunately, due to the same low depositional energies, thick sections of shales often represent long time periods and heterogeneous vertical compositions. Marine shales tend to have somewhat lower clay contents and are relatively rich in brittle minerals including quartz, feldspar and carbonates. This makes them generally more susceptible to hydraulic fracturing, all other things being equal. Non-marine shale depositional environments include lacustrine (lake bottom) and terrestrial (principally fluvial and deltaic). Such environments tend to have greater amounts of clays and thus may be less susceptible to hydraulic fracturing.

Variability vertically in shales is often substantial and numerous studies have pointed to the importance of well placement for success. Well-to-well variations in horizontal laterals that have had nearly identical hydraulic fracture treatments are significant. A common observation when production logs are run in horizontal laterals is that a substantial fraction (20-50%) of hydraulic fractures are apparently ineffective. There is wide variability in the relative contribution of each fracture stage and it is virtually unheard of to have results that compare closely with analytic solutions. Some authors have suggested that analysis of local fractures and petrophyiscally derived parameters help to explain these variations; there are few published results explaining this variability. Reservoir characterizations that fail to predict this behavior are clearly over simplistic.

Vertical and horizontal well logs, particularly image logs are critical to describe shales.  Advanced logging tools now enable operators to image fractures and faults away from the wellbore using advanced logging techniques.  Whole cores are relatively rare and operators increasingly rely on rotary sidewall cores for conventional measurements. The low permeabilites involved complicate conventional core analysis. Advances in digital rock physics have been encouraging, particularly in making sense of the shales and in using cuttings.

The key drivers explaining this variability arise from multiple sources; however, geomechanical variations and variations in fractures, particularly in critically stressed fractures may well explain much of the lateral variability.  Microseismic measurements often provide clues to lateral variability; current rock stresses along with the variations in natural fractures and the presence of faults each contribute to this variability. Operators of very low permeability horizontal wells requiring hydraulic fracturing have generally settled on preferring to have transverse fractures, suggesting that they drill parallel with the minimum horizontal compressive stress, σh. Operators in such reservoirs rarely try and parallel σH; this is more common for higher permeability applications. Wells drilled in intermediate directions are generally to be avoided. Fractures generated at the wellbore may often result in multiple initiations that compete for fluid and turn into a direction normal to the local minimum compressive stress. This results in shear, narrow fracture widths, high net pressures and potential screenouts.

In active normal faulting stress environment where σh< σH< σV the tendency would then be to create a number of parallel vertical hydraulic fractures orthogonal to the wellbore. Such behavior has been observed in multiple cases, particularly in tight gas sands. If the created fractures are sufficiently closely spaced, significant stress interference may arise between the created fractures. This can be manifested in increasing ISIPs and fracture initiation and net pressures with increasing job number, usually reaching a maximum level. However, the presence of critically stressed fractures can complicate this simple model (and improve the performance results).

Simple parallel fractures created in Mode I tensile failure in unaltered nano-darcy rock generally cannot explain the performance of successful wells. As fractures are created, the region of increased stress may activate substantial numbers of critically stressed fractures and perhaps even slowly slipping faults. While the closure of the tensile failures may require proppant, the permeability created by activated critically stressed fractures may be responsible for a substantial fraction of all fluid flow (Barton, 1997) (Zoback, 2012).  The numerous linear features common in Barnett microseismic that are not parallel to the major faulting directions are unlikely to be fluid-filled much less proppant filled. When σh σH then it will be easier for the created hydraulic fracture to turn, particularly near preexisting failures. However, the vast  numbers of microseismic events in such applications support the critically stressed fractures model.  To the extent that they are created in shear due to slippage of critically stressed fractures, they will have a tendency to be self-propped. Some authors have referred to this behavior as fracture complexity and incorrectly assumed that it was primarily due to the varying directions and paths of injected fluids.

In strike-slip faulting environments the maximum horizontal compressive stress exceeds the vertical stress. Estimation of the maximum horizontal compressive stress cannot be done accurately by simple log measurements; a full geomechanical model is required. Important components of such a model include measurements from mini-fracs or micro-fracs and wellbore image logs. The presence (or absence), size, direction and other characteristics of drilling induced tensile failures and wellbore breakouts are critical components of a geomechanical model. The geomechanical model is used in many aspects of shale development including defining wellpaths, lateral placement and hydraulic fracture design. However, it is in understanding the fundamental characteristics that dominate flow behavior where its greatest value may lie.

In strike-slip faulting environments where σV approches σH such as in portions of the Sichuan basin, there may be a tendency for locally horizontal fractures to be initiated as treating pressures increase. Layering in fissile shales may complicate this. In such environments as well as in active reverse faulting environments, successful treatments of shales may be difficult to achieve. There is some debate on this point with some experts believing that this problem is cited as the reason for ineffective fracture stimulation treatments without clear proof. One trick from vertical well applications with extremely overpressured reservoirs is to produce the unstimulated (or lightly stimulated) wellbore for an extended period of time to locally lower the stresses allowing vertical fractures to be created. This has been obtained in 0.01 to 0.1 md gas applications; there is considerable doubt that it would be applicable in K<<0.01 md applications.



Barton, C. M. (1997, 10 1). In situ stress measurements can help define local variations in fracture hydraulic conductivity at shallow depths. The Leading Edge , 16, pp. 1653-1656.

BP. (2013). Statistical Review of World Energy 2013. Retrieved from Statistical Review of World Energy 2013: http://www.bp.com/en/global/corporate/about-bp/statistical-review-of-world-energy-2013.html

Ebrahim Fathi, I. Y. (2009, November 1). Matrix Heterogeneity Effects on Gas Transport and Adsorption in Coalbed and Shale Gas Reservoirs. Transport in Porous Media , pp. 281-304.

Lafollette, R. (2012). Shale Gas and Light Tight Oil Reservoir Production Results: What Matters? Proceedings of the Twenty-third (2013) International Offshore and Polar Engineering. ISBN 978-1-880653-99–9 (Set);, pp. 54-60. Anchorage, AK: International Society of Offshore and Polar Engineers (ISOPE).

Meehan, D. N. (2012, 1 23). Hydraulic Fracturing: An Environmentally Responsible Technology for Ensuring our Energy Future (I of III). Retrieved 9 1, 2013, from Baker Hughes Reservoir Blog: http://blogs.bakerhughes.com/reservoir/2012/01/23/hydraulic-fracturing-an-environmentally-responsible-technology-for-ensuring-our-energy-future-i-of-iii/

Meehan, D. N. (2012, 1 23). Hydraulic Fracturing: An Environmentally Responsible Technology for Ensuring our Energy Future (I of III). Retrieved 9 1, 2013, from Baker Hughes Reservoir Blog: http://blogs.bakerhughes.com/reservoir/2012/01/23/hydraulic-fracturing-an-environmentally-responsible-technology-for-ensuring-our-energy-future-i-of-iii/

Meehan, D. N. (2012, 2 6). Hydraulic Fracturing: An Environmentally Responsible Technology for Ensuring our Energy Future (II of III). Retrieved 9 1, 2013, from Baker Hughes Reservoir Blog: http://blogs.bakerhughes.com/reservoir/2012/02/06/hydraulic-fracturing-an-environmentally-responsible-technology-for-ensuring-our-energy-future-ii-of-iii/

Meehan, D. N. (2012, 2 2). Hydraulic Fracturing: An Environmentally Responsible Technology for Ensuring Our Energy Future (Part III of III). Retrieved 9 1, 2013, from Baker Hughes Reservoir Blog: http://blogs.bakerhughes.com/reservoir/2012/02/20/hydraulic-fracturing-an-environmentally-responsible-technology-for-ensuring-our-energy-future-part-iii-of-iii/

Randy F. LaFollette, W. D. (2012). Practical Data Mining: Analysis of Barnett Shale Production Results with Emphasis on Well Completion and Fracture Stimulation . SPE Hydraulic Fracturing Technology Conference . SPE 152531. The Woodlands, Texas, USA,: Society of Petroleum Engineers.

U.S. Energy and Information Administration. (2013). Technically Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formations in 41 Countries Outside the United States. Retrieved September 1, 2013, from Analysis & Projections: http://www.eia.gov/analysis/studies/worldshalegas/

U.S. Energy and Information Administration. (2013). U.S. Imports of Crude Oil. Retrieved 9 1, 2013, from EIA Crude Oil data: http://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=pet&s=mcrimus1&f=m

Z. Dong, S. H. (2012, January). Resource Evaluation for Shale Gas Reservoirs . SPE Economics & Management , 5-16.

Zoback, M. (2012, 7 1). Identification and Hydraulic Properties of Critically-Stressed Faults and Anticipating Triggered Seismic and Aseismic Fault Slip. Retrieved 9 1, 2013, from https://pangea.stanford.edu: https://pangea.stanford.edu/researchgroups/scits/sites/default/files/Zoback%20Presentation.pdf



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