Common Themes in the Formation and Preservation of Intrinsic Porosity in Shales and Mudstones - Illustrated with Examples Across the Phanerozoic
- Juergen Schieber (Indiana University)
- Document ID
- Society of Petroleum Engineers
- SPE Unconventional Gas Conference, 23-25 February, Pittsburgh, Pennsylvania, USA
- Publication Date
- Document Type
- Conference Paper
- 2010. Society of Petroleum Engineers
- 5.3.4 Integration of geomechanics in models, 1.2.3 Rock properties, 5.2 Reservoir Fluid Dynamics, 1.6.9 Coring, Fishing, 5.4.10 Microbial Methods, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 5.1 Reservoir Characterisation, 5.8.2 Shale Gas, 4.3.4 Scale, 1.6 Drilling Operations, 4.2.3 Materials and Corrosion, 4.6 Natural Gas, 5.1.4 Petrology, 5.6.1 Open hole/cased hole log analysis, 1.14 Casing and Cementing, 5.1.1 Exploration, Development, Structural Geology
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In shales, intrinsic porosity is considered a direct outcome of those processes that are active during deposition and early compaction of a shale succession. They are typically in the micrometer to nanometer size range, and unrelated to processes that produce fragmentation-related porosity later on in burial history.
An examination of six shale successions, ranging in age from Cambrian to Cretaceous shows that, in spite of considerable variability of composition, depositional setting, and compaction history, there are several pore types that seem universal. Three types of pores that recur are phyllosilicate framework (PF) pores, carbonate dissolution (CD) pores, and organic matter (OM) pores. PF-pores are defined by a framework of platy phyllosilicates and range in size from 5 nm to more than 1000 nm. CD-pores typically occur along the periphery of dolomite and calcite grains and range in size from 50 nm to more than 1000 nm. OM-pores occur within kerogen blebs and organo-clay aggregates, and range in size from 10 nm to several 100 nm.
When organic matter content and shale maturity are considered, the following relationships emerge: 1) at high organic matter content (>10% TOC) many PF-pores are filled with kerogen/bituminite in immature shales; 2) in mature shales these same fills contain abundant OM pores or are partially removed; 3) organic matter that has seen partial degradation before compaction (e.g. bituminite) develops abundant OM pores in shales that have reached maturity; but 4) non-degraded organic matter (e.g. alginite, inertinite) does not develop pores. In shales with comparatively low TOC (less than 7%) a large proportion of the PF-pores are open, likely connected, and potentially able to transmit gas. PF-pores are also more common as clay content increases, but more critically, their abundance hinges on the presence of pressure shadows generated adjacent to "hard" grains (quartz, feldspar, dolomite, calcite, pyrite) that resist compaction. They also occur in compaction resistant cavities (e.g. foram tests). CD-pores appear to form late in diagenetic history. The requisite pH drop was likely due to the formation of carboxylic and phenolic acids when kerogens reacted with silicates in a briny solution at elevated temperatures (~ 80° to 120° C). When carbonate content is low (a few %), CD-pores constitute only isolated porosity. However, in shale intervals that contain abundant carbonate, and where carbonate grains are concentrated into laminae, CD-pores probably are an important facilitator of gas migration.
In many shale gas plays natural fracture systems are considered a key aspect in the assessment of producibility. Yet, with a typical fracture spacing at the decimeter scale, gas still has to migrate some distance to these fractures. Thus, the intrinsic porosity of the shale is a crucial variable that needs to be understood for a realistic evaluation of long term production. Petrographic evaluation of shale porosity provides a much needed "reality check?? for "method driven?? measurements (mercury injection, nitrogen adsorption) of porosity and permeability.
Typical shales are terrigenous clastic dominated sedimentary rocks with a dominant grain size below 63 microns, and constitute approximately two thirds of the sedimentary rock volume (Schieber, 1998). Whereas most of these have long functioned as the seals that prevent hydrocarbons from escaping from their reservoir, a subset of carbonaceous (organic-rich) shales has for many years also served as a source of natural gas. In fact, the first natural gas well in the US that tapped Devonian black shales beneath Fredonia, New York, was drilled in 1821, almost four decades before the much better known Drake Oil Well near Titusville, Pennsylvania, considered the birthplace of the oil industry. Yet, although shale gas has been produced in the eastern US for more than a century, for most of that time its contribution to the overall production has been marginal.
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