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Collaborating Authors
Results
Nanopore-Structure Analysis and Permeability Predictions for a Tight Gas Siltstone Reservoir by Use of Low-Pressure Adsorption and Mercury-Intrusion Techniques
Clarkson, C.R.. R. (University of Calgary) | Wood, J.M.. M. (Encana Corporation) | Burgis, S.E.. E. (Encana Corporation) | Aquino, S.D.. D. (University of Calgary) | Freeman, M.. (University of Calgary)
Summary The pore structure of unconventional gas reservoirs, despite having a significant impact on hydrocarbon storage and transport, has historically been difficult to characterize because of a wide pore-size distribution (PSD), with a significant pore volume (PV) in the nanopore range. A variety of methods is typically required to characterize the full pore spectrum, with each individual technique limited to a certain pore size range. In this work, we investigate the use of nondestructive, low-pressure adsorption methods, in particular low-pressure N2 adsorption analysis, to infer pore shape and to determine PSDs of a tight gas silt-stone reservoir in western Canada. Unlike previous studies, core-plug samples, not crushed samples, are used for isotherm analysis, allowing an undisturbed pore structure (i.e., uncrushed) to be analyzed. Furthermore, the core plugs used for isotherm analysis are subsamples (end pieces) of cores for which mercury-injection capillary pressure (MICP) and permeability measurements were previously performed, allowing a more direct comparison with these techniques. PSDs, determined from two isotherm interpretation methods [Barrett-Joyner-Halenda (BJH) theory and density functional theory (DFT)], are in reasonable agreement with MICP data for the portion of the PSD sampled by both. The pore geometry is interpreted as slot-shaped, as inferred from isotherm hysteresis loop shape, the agreement between adsorption- and MICP-derived dominant pore sizes, scanning-electron-microscope (SEM) imaging, and the character of measured permeability stress dependence. Although correlations between inorganic composition and total organic carbon (TOC) and between dominant pore-throat size and permeability are weak, the sample with the lowest illite clay and TOC content has the largest dominant pore-throat size and highest permeability, as estimated from MICP. The presence of stress relief-induced microfractures, however, appears to affect laboratory-derived (pressure-decay and pulse-decay) estimates of permeability for some samples, even after application of confining pressure. On the basis of the premise of slot-shaped pore geometry, fractured rock models (matchstick and cube) were used to predict absolute permeability, by use of dominant pore-throat size from MICP/adsorption analysis and porosity measured under confining pressure. The predictions are reasonable, although permeability is mostly overpredicted for samples that are unaffected by stress-release fractures. The conceptual model used to justify the application of these models is slot pores at grain boundaries or between organic matter and framework grains.
- North America > United States (1.00)
- North America > Canada > Alberta (1.00)
- North America > Canada > British Columbia (0.93)
- Geology > Geological Subdiscipline > Geochemistry (0.94)
- Geology > Mineral > Silicate (0.88)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.52)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > New Mexico > San Juan Basin (0.99)
- North America > United States > Colorado > San Juan Basin (0.99)
- (9 more...)
Abstract Various forms of shale gas (SG) material balance equations (MBE) have been developed in the past several decades, dating back to the first round of coalbed methane (CBM)/SG development in North America. These equations attempt to incorporate various aspects of SG storage mechanisms and reservoir characteristics; simple to complex forms exist, depending on the number of assumptions made in their derivation. All of the equations account for adsorbed gas storage, but may or may not include corrections for pore volume (PV) and fluid compressibility, water influx etc. In higher-permeability fractured SG and CBM plays, application of material balance using static (shut-in) pressures to derive original gas-in-place (OGIP) and drainage area estimates has proven useful. With the current development of ultra-low permeability SG (and shale liquids) plays, shut-in times for wells is impractically long so as to preclude the use of static material balance (SMB) methods. Use of rate-transient analysis (RTA) techniques, such as the flowing material balance (FMB), is much more common for original gas-in-place (OGIP) derivations in ultra-low permeability reservoirs, yet some form of MBE is often required for application of these methods. For example, pseudo-time and material balance pseudo-time is commonly used in advanced RTA methods, and hence the form of MBE could impact reservoir and/or hydraulic fracture properties derived from the analysis. In this work, we first summarize the MBEs that have been derived specifically for SG and/or CBM, with an emphasis on the assumptions, limitations and applications of each equation. We then derive a new MBE that dynamically adjusts free-gas storage volume during depletion according to the amount of volume occupied by sorbed gas, as recently suggested by Ambrose et al. (2010) for volumetric gas-in-place determination. Finally, we examine the impact of MBE selection on quantitative rate-transient analysis (for estimation OGIP). Two simulated cases for SG reservoirs are used to demonstrate the impact of the selected MBE. Finally, a modified transient productivity index (PI) using average pressure in the region of influence was developed and is compared to conventional transient PI. The results of this study are of interest to those engineers performing unconventional reservoir characterization work using RTA and for reserves estimators.
- North America > United States > Texas (0.93)
- North America > Canada > Alberta (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline (1.00)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Michigan > Michigan Basin > Antrim Shale Formation (0.99)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation Field > Montney Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation Field > Montney Formation (0.99)
Electrical Property Estimation For Complex Carbonate Reservoirs Using Wireline Logs
Al-Ghamdi, Ali (University of Calgary) | Aguilera, Roberto (University of Calgary) | Clarkson, Christopher (University of Calgary)
ABSTRACT: Carbonate rocks are usually characterized by a variety of porosity types resulting from depositional and diagenetic processes. The variation of the pore geometry, connectivity and size controls the electrical properties of carbonate rocks. The cementation exponent (m) is controlled by various properties including pore connectivity and tortuosity whereas the water saturation exponent (n) is more controlled by the pore size and wettability. For exploratory wells in carbonates, it is essential to estimate electrical properties for appropriate formation evaluation. Instead of using only analogues, the models developed in this study are shown to be valid for the evaluation of different rock types in exploration wells. This increases the confidence level in initial estimates of water saturation and hydrocarbons-in-place. A triple porosity model is used to calculate m of complex carbonate reservoirs in the Middle East using conventional well log data. The emphasis is on exploration wells as the uncertainty associated with m generally decreases during the development and production stages of the reservoirs. The carbonate rocks in this study are characterized by a combination of interparticle, fracture and non-connected porosity (e.g., vuggy and fenestral) that changes continuously with depth. This increases uncertainty in the estimation of m because, for this complex composite carbonate system, m can be larger, equal to, or smaller than the cementation exponent of the single porosity matrix blocks (mb). The variation in m depends on the relative contribution of natural fractures, interparticle porosity and non-touching vugs to the total porosity of the triple porosity reservoir. The validity of the model is demonstrated through comparison of porosity types calculated from well logs and from direct sources including core samples and thin sections. A continuous curve of m for the whole carbonate reservoir is obtained using this approach.
- North America > United States > Texas (0.47)
- Asia > Middle East > Saudi Arabia (0.28)
Nanopore Structure Analysis and Permeability Predictions for a Tight Gas/Shale Reservoir Using Low-Pressure Adsorption and Mercury Intrusion Techniques
Clarkson, C. R. (University of Calgary) | Wood, J. M. (Encana Corporation) | Burgis, S. E. (Encana Corporation) | Aquino, S. D. (University of Calgary) | Freeman, M.. (University of Calgary) | Birss, V.. (University of Calgary)
Abstract The pore structure of unconventional gas reservoirs, despite having a significant impact on hydrocarbon storage and transport, has historically been difficult to characterize due to a wide pore size distribution, with a significant pore volume in the nanopore range. A variety of methods are typically required to characterize the full pore spectrum, with each individual technique limited to a certain pore size range. In this work, we investigate the use of non-destructive, low-pressure adsorption methods, in particular low pressure N2 adsorption analysis, to infer pore shape, and to determine pore size distributions of a tight gas/shale reservoir in Western Canada. Unlike previous studies, core plug samples, not crushed samples, are used for isotherm analysis, allowing an undisturbed pore structure to be analyzed. Further, the core plugs used for isotherm analysis are subsamples (end pieces) of cores for which MICP and permeability measurements were previously made, allowing a more direct comparison with these techniques. Pore size distributions determined from two isotherm interpretation methods (BJH Theory and Density Functional Theory), are in reasonable agreement with MICP, for that portion of the pore size distribution sampled by both. The pore geometry is interpreted to be slit-shaped, as inferred from isotherm hysteresis loop shape, the agreement between adsorption- and MICP-derived dominant pore sizes, SEM imaging and the character of measured permeability stress-dependence. Although correlations between inorganic composition and total organic carbon (TOC) and dominant pore throat size and permeability are weak, the sample with the lowest illite clay and TOC content has the largest dominant pore throat size and highest permeability, as estimated from MICP. The presence of stress-relief-induced microfractures, however, appears to affect lab-derived (pressure-decay and pulse-decay) estimates of permeability, even after application of confining pressure. Based on the premise of slit-shaped pore geometry, fractured rock models (matchstick and cube) were used to predict absolute permeability, using dominant pore throat size from MICP/adsorption analysis and porosity measured under confining pressure. The predictions are reasonable, although permeability is mostly over-predicted for samples that are unaffected by stress-release fractures. The conceptual model used to justify the application of these models is slot pores at grain boundaries.
- North America > Canada (0.87)
- North America > United States > Texas (0.28)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.72)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Field > Barnett Shale Formation (0.98)