Critical Assessment of Shale Resource Plays

Edited by Jean-Yves Chatellier and Daniel M. Jarvie


This volume is the product of a joint Hedberg research meeting headed by the AAPG in collaboration with the Society of Petroleum Engineers, and the Society of Exploration Geophysicists. It consists of 10 peer-reviewed chapters covering items from geochemistry, geology, basin analysis, diagenesis, geophysics, geomechanics, and engineering with a main emphasis on shale from North America and Europe. The digital data in the included DVD is a compilation of all extended abstracts submitted for the event or updated since the meeting as well as most presentations and posters in PDF format. Additionally, three videos presented at the meeting have been included. They relate to three-dimensional views of shale pore systems and flume experiements of mudstones bringing a new light on the deposition of fine-grain deposits.

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    This conference was designed to be a forum for open discussion of current knowledge, advances that are in progress, and direction for additional and future research into these systems. Further, the interlacing of professional disciplines was meant to provide dynamic interactions to foster information exchange among these groups. These professional disciplines included geologists, petrophysicists, geochemists, geophysicists, and engineers as well as individuals involved in the business of drilling and producing wells.

    An organizing committee of 11 individuals representing these professional organizations and specific professional specialties proposed the meeting and solicited participation from their knowledgebase of persons working in industry and academia. In order to achieve optimum participation of attendees and committee members, all were required to submit an abstract for consideration either as an oral or poster and either as lead or co-author to maximize interaction and make sure all attending were participants rather than attendees. Decisions on participation and oral presentations were made based on (1) obtaining coverage of the many scientific specialties involved in shale resource plays and (2) committee member voting. Poster presenters were allowed to introduce their presentations with an oral presentation of one to three slides. All posters were available for viewing during the entire meeting.

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    Since the discovery of the Groningen gas field, the Netherlands has been a large producer and consumer of natural gas. Current forecasts show that production from convention on- and offshore fields will decline noticibly in the next decades. The Netherlands has the ambition to sustain its prominent role in the northwestern European gas market and will have to be able to meet the future domestic demand. Import of natural gas, either through liquid natural gas import (North Africa, Middle East) or from the East (Nordstream), are therefore evaluated and planned. Following the developments in the United States, the question has arisen if there is shale gas potential in the Netherlands that could add to the domestic gas production. A first evaluation in 2009 confirmed this potential, although the uncertainties are huge. Others have, however, challenged this positive view on the potential resource of the Netherlands. The follow-up work presented in this paper provides more detailed information based on extensive data evaluations and interpretations of potential shale gas targets in the Netherlands.

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    The aim of this work is to determine the volume balance of gas generated in shale gas systems in both the oil and the gas windows. For this purpose, immature as well as mature source rocks were selected in order to carry out experimental simulation of kerogen cracking in a closed pyrolysis system. First, the compositional kinetic model previously calibrated on three kerogens was applied to immature Barnett and Posidonia shale kerogens, respectively Mississippian and Lower Jurassic in age. Subsequently, the mature kerogens were artificially matured at 375 degrees C for 24 hours in order to mature the kerogens to the beginning of the gas window and remove all generated products by solvent extration. The goal was to create postoil generative kerogen in order to measure generated products from mature kerogen only. These oil-free mature kerogens were then heated to higher tempeartures for evaluation of late gas generation from postoil kerogen. A tentative simulation of gas generation from secondary cracking of the retained compounds after the main phase of primary expulsion demonstrates that, although between 1.5% and 2% of wet gas is produced, the overall gas dryness in the Ro range 1.5-3.0% is between 85 and 90 molar %. A tentative gas balance (scf per ton of rock) under geological conditions was calculated for an initial source rock of 2% TOC. It predicts that 20 scf/ton of wet gas are generated from residual oil cracking and gas present after the main phase of oil expulsion, while 60 scf/ton of rock of dry gas are produced from the thermal evolution of the residural insoluble organic matter.

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    A study of up to 2.5 km (8000 ft) of gas-bearing shale has shed new light on the relationship between geochemistry and overpressure. Our analysis of a few large geochemical data sets has also identified alternative ways to look at down-hole pressures and has revealed some limitations of currently available tools, such as Rock-Eval pyrolysis below a certain depth in Alberta and Quebec. The very thick Ordovician Shale of the St. Laurence Lowlands in Quebec is gas-bearing and prospective. While the prime target is the carbonate-rich Utica Shale, the overlying and thick Lorraine Shale was also studied. Recent Quebec geochemical data from the St. Lawrence Lowlands was analyzed together with hydraulic fracture and reservoir pressure data from the same wells. The first phase of the study focused exclusively on vertical wells and delivered new insights with respect to pressure domains and fracture gradients.

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    This paper presents a straightforward and effective method to predict source rock organofacies using basic compositional data and a ternary discriminant plot prior to the availability of suitable pyrolysis data. Associating compositional data with organofacies can tie into previously correlated depositional environments and expulsed hydrocarbon types. Using this methodology to preliminarily establish organofacies can help classify source rocks and reduce the practice of comparing source rock plays based solely on production characteristics. Four basic source rock affinities have been noted: (1) clay-quartz affinity with minor carbonate, (2) clay-quartz affinity with carbonate, (3) carbonate affinity, and (4) bimodal clustering and affinities. Trends in the compositional data can also aid in the prediction of lateral and vertical changes in depositional systems and help ascertain the presence or absence of specific organofacies in an area. Each source rock may have multiple organofacies, and these can vary within or between basins. Ternary plots also distinguish the relative brittleness of lithofacies and, therefore, more suitable unconventional reservoirs. This technique does not directly indicate quality of the source rock; standard geochemical analysies are still needed to identify high-quality source rocks.

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    A study of the Upper Devonian-Lower Mississippian Woodford Shale was undertaken on samples at low thermal maturity from the Arbuckle Mountains, southern Oklahoma, to dientify possible mechanisms by which natural gas might be stored in Woodford reservoirs in the adjacent Anadarko Basin. The two main lighologies in the Woodford, chert and mudstone, display different inorganic and organic characteristics. Cherts have (1) variable porosity from 0.59% to 4.90%, (2) low calculated permeabilities, and (3) small mean pore apertures. Intercrystalline pores dominate in cherts. In contrast, mudstones generally have (1) porosities ranging from 1.97% to 6.31%, (2) low calculated permeabilities, and (3) small mean pore apertures. Interparticle, intraparticle, and moldic pores all are present in mudstones. Because of their high quartz content, cherts are brittle and commonly demonstrate microfracturing that is lithologically controlled and bedding perpendicular, whereas much less microfracturing exists in mudstones. The early diagenetic intercrystalline porosity in cherts has likely been preserved since it formed because of the rigid, internal framework provided by the abundant authigenic quartz. Coupled with their relatively high TOC contents, cherts then may be important intervals of gas generation and storage in the Woodford. Where abundant, cherts may then play a significant role as source and reservoir intervals within the formation in the Anadarko Basin.

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    This paper proposes five hypotheses concerning small intraplate earthquakes and the possibility that they are triggered by fluid injection. The proposed hypotheses are based on empirical observations but are consistent with the generally accepted ideas that small intraplate earthquakes are ubiquitous and occur on preexisting faults in response to regional tectonic stress and that injected fluids can induce seismic clip by reducing normal stress and hence fault strength. Although these hypotheses are not yet proven, they serve as a template for additional research. They also provide a basis for making decisions that reduce the likelihood of triggering earthquakes and for mitigating potential seismic hazard associated with injection activities.

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    It is well known that shale exhibits highly anisotropic behavior due to the sedimentation process during deposition. Anisotrophy affects the deformation, plasticity, and strength of shale. In this paper, the dilation and yielding characteristics of shale were investigated. The outcome of this study can be useful in various geomechanical applications, including borehole stability modeling and analysis and hydraulic fracturing models for gas shale. The experimental results show that shale has a significant dilatancy tendency due to the confinement pressure and sample's geometry. The dilatancy effect should not be ignored in time-delayed rock failure analysis or in other geomechanical applications, particularly when the plasticity effect is significant.

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    This paper reviews petrographic evidence concerning the mechanisms by which mudrocks lithify. Mudrocks clearly undergo processes analogous to compaction and cementation in sandstone and limestone, although the relative importance of these two processes in the diagenesis of mudrocks remains uncertain. Cement in mudrocks can be demonstrated to fill both primary and secondary pores. Inter- and intragranular cements are observed in mudrocks as well as cement within fracture fills. Thus, cements in mudrocks take the full range of form and distribution as observed for cements in sandstone and limestone. Displacive precipitation is a chemical-mechanical process observed with particular frequency in mudrocks, which contrasts with the common cementation processes in sandstones and limestones. Overall, the same authigenic minerals common in sandstone and limestone dominate the authigenic assemblages in mudrocks. Sediment accumulation rate is a significant factor in mudrock cementation. In situations of slow sediment accumulation, cement emplacement, typically in the form of highly localized carbonate and phosphate minerals, takes place near the sediment-water interface. In contrast, rapidly deposited mudrocks tend to lithify at greater depths in response to thermally controlled diagenetic reaction of the detrital assemblage. Authigenic quartz in mudrocks, a topic of particular interest for an understanding of quartz are readily documented in mudrocks, but convincing demonstration of intergranular quartz cement remains elusive. High-resolution imaging by transmission electron microscopy may be required to fully resolve issues surrounding the emplacement of authigenic quartz into the minute pores of mudrocks.

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    Delineating the sweet spots, areas where well performance will be most economic, is a critical issue for both the exploration and the development of gas-shale reservoirs. Two simple methods to aid identification and mapping of sweet spots using density and neutron logs are presented in this paper. The first method is apparent shale porosity*thickness (PHIas*H) maps, derived from the raw density porosity log, used to qualitatively assess and map reservoir quality and quantity. What is unique in the approach of this paper is that no rock calibration is done to correct for total organic carbon (TOC), a common industry practice. The second method is the neutron gas effect. In many gas shales, the neutron and density logs exhibit approach sometimes to the point of a corssover response, similar to the well-documented effect in gas reservoirs in sandstone or carbonate. All currently commercial gas shales in North America exhibit the gas effect, suggesting that it can be used as a direct detection technique for commercial gas shale.

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    Successful production performances from shale resources in North America have generated broad interests in several intriguing properties, such as organic-matter pore network, wettability, connate-water saturation, geopressure gradient, and brittleness. Although poorly understood, unique characteristics of these properties can have profound impacts on storage capacity, fluid flow, and production. Objectives of this study were to investigate potential effects of organic-matter pore network, wettability, low connate-water saturation, geopressure gradient, and effective stress on properties of organic-rich shales as well as fluid flow through shale reservoirs.

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