Sample Size Effects on the Application of Mercury Injection Capillary Pressure for Determining the Storage Capacity of Tight Gas and Oil Shales
- Joseph Thomas Comisky (Apache Corp.) | Michael Santiago (Poro-Labs Inc.) | Bruce McCollom (Poro-Labs Inc.) | Aravinda Buddhala (University of Oklahoma) | Kent Edward Newsham (Apache Corp.)
- Document ID
- Society of Petroleum Engineers
- Canadian Unconventional Resources Conference, 15-17 November, Calgary, Alberta, Canada
- Publication Date
- Document Type
- Conference Paper
- 2011. Society of Petroleum Engineers
- 4.3.4 Scale, 5.5.2 Core Analysis, 5.6.2 Core Analysis, 5.8.2 Shale Gas, 5.8.4 Shale Oil, 1.2.3 Rock properties, 5.1.1 Exploration, Development, Structural Geology, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 1.6.9 Coring, Fishing, 4.6 Natural Gas, 2.4.3 Sand/Solids Control, 5.4.2 Gas Injection Methods, 5.8.1 Tight Gas, 5.6.1 Open hole/cased hole log analysis, 5.2.1 Phase Behavior and PVT Measurements, 5.1 Reservoir Characterisation
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We measured Mercury Injection Capillary Pressure (MICP) profiles on tight shale samples with a variety of sample sizes. The goal was to optimize the rock preparation and data reduction workflow for determining the storage properties of the rock, particularly porosity, from MICP measurements. The rock material was taken from a whole core in the Cretaceous Eagle Ford Formation in the form of a puck or disc. A horizontal 1 inch core plug was cut from this disc and the remaining material was subsequently crushed and sieved through various mesh sizes. MICP profiles up to 60,000 psia were then measured on the 1 inch plug and all of the various crushed and sieved rock particle sizes. In parallel we subsampled the plug material to measure bulk volume, grain volume, and porosity using a crushed rock helium pycnometry method. These additional measurements provided a comparison set of standard petrophysical properties from which we could compare the MICP results.
In general our MICP profiles show a very strong dependence on sample size due to two reasons: pore accessibility and conformance. We verify the conformance correction approach of Bailey (2009) which specifically accounts for the pore volume compression of the sample before mercury has been injected into the largest set of interconnected pore throats. This new method is preferred over the traditional method of conformance correction when compared to crushed rock helium
porosity since the latter is performed at unstressed conditions. Our results using Bailey's (2009) method reveals that the - 20+35 sample size is optimal for determining porosity in the Eagle Ford, and potentially other tight oil and gas shales. We use mercury injection for determining the various storage properties of tight shale because helium porosimetry is not always possible on fine cuttings samples. There are many instances when limited cuttings may be the only source of rock information available before a whole core is taken. Cuttings profiles also provide a key insight over long formation intervals that may not be available from whole core. Cuttings and core profiles for use in calibrating well logs have proven to be a requirement in these ultra-low perm systems.
The emergence of shale and oil plays in North America has caused the industry to re-examine the methods which we use to quantify the resource and recoverable reserves in place. We recognize that unconventional gas and oil reservoirs are geologically and petrophysically heterogeneous at a variety of scales. This calls for a continuum of measurements to be used that are generally challenged due to the nano-scale pore nature of these rocks. A sampling of recent studies (Sondergeld et al., 2010; Passey et al., 2010; Spears et al., 2011) point out the lack of a standardized protocol such as that established for conventional and tight gas sand (microDarcy) systems in the API-RP40 (API, 1998). There is some common ground in that most laboratories follow a variation of the procedures established by Luffel and Guidry (1992) for determining storage capacity (crushed rock or GRI porosity) and flow capacity (pressure or pulse decay permeability). Other tools such as image analysis via focused ion-beam milling (FIB) and scanning electron microscopy (SEM) (Loucks et al. 2009; Curtis et al.,
2010), and direct nuclear magnetic resonance (NMR) detection of fluids in place (Sigal and Odusina, 2010; Ramirez et al., 2011) are currently being researched by both industry and academia alike.
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