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Oil & Gas
Reservoir Simulation of Primary and Enhanced Oil Recovery by Huff and Puff Gas Injection, and CO2 Storage in La Luna Shale of Colombia
Tellez, C. Herrera (Schulich School of Engineering, University of Calgary, Calgary, Alberta, Canada) | Fragoso, A. (Schulich School of Engineering, University of Calgary, Calgary, Alberta, Canada) | Aguilera, R. (Schulich School of Engineering, University of Calgary, Calgary, Alberta, Canada)
Abstract La Luna Shale in Colombia has significant oil and gas potential in the Middle Magdalena Valley and Catatumbo Basins that can be developed with the use of hydraulically fractured horizontal wells. This potential, however, has not been fully evaluated. Thus, this paper concentrates on estimating La Luna's primary and enhanced oil recovery, as well as the potential for CO2 storage with the use of reservoir simulation. Simulation of enhanced oil recovery is conducted in this study using CH4 and CO2 as injected gases during huff and puff (huff ‘n’ puff) operations. Simultaneously, the study simulates the viability of using La Luna Shale as a safe place for storing CO2 with negligible possibilities of unwanted leaks. The selection of La Luna Shale for this purpose stems from the observation of geologic containment in La Luna. Geologic containment is a concept developed by our research group at the University of Calgary. Our study concludes that geologic containment occurs in La Luna Shale, where natural gas, condensate and oil are upside down or in an inverted position in the structure. The paper demonstrates that if the hydrocarbons remain in the same position where they were generated, then the possibilities that the injected gases will leak beyond the volume that is hydraulically fractured are nil. Simulation results reveal that primary recovery from La Luna Shale for the investigated areas range between 23 to 25%. These recoveries are much larger than those reported for the Eagle Ford Shale of Texas, which range between 5 and 10%. Higher quality of La Luna shale is associated with these significant recoveries, which are supported by production data from La Luna and Eagle Ford shales. Simulation results show that these recoveries can be improved by huff ‘n’ puff gas CO2 injection. The simulation further shows that during successive cycles of huff ‘n’ puff with CO2, the volume of CO2 retained in La Luna is progressively larger. Once huff ‘n’ puff reaches its economic limit, CO2 can be injected continuously until reaching a maximum pressure equal to the initial reservoir pressure. CO2 injected is thus stored safely and permanently in La Luna Shale. The novelty of the paper is demonstrating that geologic containment exists in La Luna Shale in both the Middle Magdalena Valley and Catatumbo basins of Colombia. Under these conditions, and given the quality of La Luna Shale, reservoir simulation shows that La Luna primary oil recoveries can be significant and can be improved by huff ‘n’ puff CO2 injection. Furthermore, the advantage of using CO2 is that it can be stored safely and permanently with negligible possibilities of unwanted leaks. Thus, La Luna shale can contribute with two important segments of CCUS: (1) Utilization of CO2 for Enhanced Oil Recovery (EOR) and (2) Storage of CO2 as shown in this paper. The segment associated with Capture of CO2 can be accomplished from refineries and large industrial complexes. This, however, is beyond the purpose of the present study.
- South America > Colombia (1.00)
- North America > United States > Texas (1.00)
- North America > Canada > Alberta > Census Division No. 6 > Calgary Metropolitan Region > Calgary (0.25)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Oil Play (1.00)
- South America > Colombia > Tolima Department > Middle Magdalena Basin > La Luna Shale Formation (0.99)
- South America > Colombia > Santander Department > Middle Magdalena Basin > La Luna Shale Formation (0.99)
- South America > Colombia > Middle Magdalena Basin > La Luna Shale Formation (0.99)
- (19 more...)
Induced Flow Geometries During Steam Injection in Unconsolidated Sand in Heavy and Extra-Heavy OiI Fields in Mexico
Cinco-Ley, H. (Universidad Nacional Autonoma de Mexico and Consultant to Jaguar E&P, Mexico) | Chavez, S. (Pemex, Villahermosa, Mexico) | Aguilera, R. (Schulic School of Engineering, University of Calgary, Canada)
Abstract This objective of this paper is to demonstrate that transient linear flow is the dominant behavior in unconsolidated sands performing under steam injection in Mexico. It has been observed in the past and there is evidence from fall-off tests that all wells injecting water in unconsolidated sands that store heavy oil exhibit a condition similar to being fractured. Apparently, this is the result of high mobility around the fracture. Something similar can occur during the processes of cyclic steam and continuous steam injection in unconsolidated sands. This is investigated in detail in this paper with different types of transient pressure tests. The paper presents the analysis of falloff, injection and interference tests carried out in steam injection wells in an unconsolidated sand that stores extra-heavy oil. Subsequent to a series of steam injection cycles, the well exhibited a transient pressure behavior that is characteristic of linear geometry. The boundary of the linear flow behavior is associated with the extra-heavy oil zone not affected by steam. Furthermore, subsequent to a period of continuous gas injection (as opposed to the previous cyclic gas injection), it was observed that linear flow was prevalent again. In addition, an interference test was carried out between the injection well and another well producing from the same unconsolidated sand. The interference pressure signal at short times showed a behavior that corresponds to linear flow. The test also permitted to estimate the compressibility of the unconsolidated sandstone. Based on the evidence collected during the different tests, the conclusion is reached that during the processes of steam cyclic and steam continuous injection, a channel of high oil mobility was generated by the viscosity contrast of water and extra-heavy oil. This channel is limited by oil zones not affected by steam. The novelty of the paper is demonstrating that transient linear flow is prevalent throughout the fall-off, injection and interferences tests in the Mexican unconsolidated sand. It is likely that the same observation might have application is other unconsolidated sands undergoing steam injection.
- North America > Mexico (1.00)
- North America > United States > Texas (0.28)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline > Geomechanics (0.72)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.34)
Determination of Rock Compressibility in Unconsolidated Sand in Heavy and Extra-Heavy Oil Fields in Mexico
Fragoso, A. (Schulic School of Engineering, University of Calgary, Calgary, Alberta, Canada) | Aguilera, R. (Schulic School of Engineering, University of Calgary, Calgary, Alberta, Canada) | Cinco-Ley, H. (Universidad Nacional Autonoma de Mexico and Consultant, Mexico)
Abstract Unconsolidated sands in heavy and extra-heavy oil fields in Mexico have significant potential that has not been fully evaluated yet. Thus, this paper examines petrophysics and geomechanical aspects with a view to estimating rock compressibility. This is important since determining this parameter from cores has proved to be difficult many times as the samples tend to collapse easily during laboratory experiments. The proposed method uses an empirical correlation for estimating Biot coefficient (Li et al., 2020) and more established geomechanical equations written in such a way as to allow the estimation of several types of compressibilities including: bulk compressibility, uniaxial bulk compressibility, pore compressibility, uniaxial pore compressibility, and pore compressibility under hydrostatic load. The data are loaded on a Pickett plot (1966, 1973) to demonstrate the value of pattern recognition. There are several intermediate results from calculations leading to the compressibilities mentioned above. These include process speed (ratio of permeability and porosity), pore throat aperture in microns at 35 percent cumulative pore volume (rp35), water saturation (Sw), mercury-air capillary pressure (pc), pore throat apertures (rp) at different water saturations, Biot coefficient (α), Poisson's ratio (PR), shear modulus (G), Young's modulus (YM), and fluid compressibility (cf). An important observation is that although use of the equations presented in the paper are straight forward and lead to quick calculation of all parameters mentioned above, it is likely that calculations from well logs without using pattern recognition may lead to uncertain results. The novelty of the paper is developing a methodology for calculating diverse types of rock compressibilities in unconsolidated sandstone reservoirs. Application of the methodology can lead to improved calculated recovery factors of unconsolidated sandstone reservoirs in heavy and extra-heavy oil fields in Mexico by at least 10%.
- North America > Mexico (1.00)
- North America > Canada > Alberta (0.68)
- North America > United States > Texas (0.46)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- (2 more...)
Summary In Alberta and British Columbia, a huge amount of tight gas is trapped inrelatively low-permeability rock formations. Physical fracturing of theseformations could enhance the overall formation permeability and thus improvetight gas extraction. One of the outstanding issues in rock fracturing is todetermine the magnitude of applied effective stress. The generaleffective-stress law is defined as seff =sc - asp, where sc andsp are total confining stress and fluid pore pressure,respectively. Each physical quantity of rock responds to total stress and porepressure in a different way, and thus each quantity has its own unique Biot'seffective-stress coefficient. The main objective of this study is toexperimentally determine the Biot's coefficient for permeability of Nikanassinsandstone. A series of permeability measurements was conducted on Nikanassinsandstone core samples from the Lick Creek region in British Columbia undervarious combinations of confining stress and pore pressure. In addition,permeability values were measured both along and across bedding planes toinvestigate any anisotropy in the Biot's coefficient.
- North America > United States (1.00)
- North America > Canada > British Columbia (0.55)
- North America > Canada > Alberta (0.52)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.55)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Block BM-C-41 > Tubarao Tigre Field (0.89)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Block BM-C-41 > Tubarao Gato Field (0.89)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Block BM-C-41 > Pipeline Field (0.89)
- Europe > Spain (0.89)
ABSTRACT Normal-trend methods and explicit methods to predict pore pressure were implemented in the Deep Basin of the Western Canada Sedimentary Basin (WCSB). The WCSB corresponds to a continuous gas accumulation which is characterized by an abnormally sub-pressured distribution and very low permeability. The tight gas portion of the basin has an estimated OGIP of approximately 1500 tcf [1]. Eaton method [2] from sonic logs, the modified D Exponent [3], Holbrook method [4] from well logs and the Acoustic Formation Factor Approach (AFF) [5], as well as the Bowers method [6] for loading and unloading conditions were the base of this study. The implementation of these five different approaches was carried out in two vertical wells located in the WCSB. The Eaton method from sonic logs let to conclude that for this kind of conditions the most suitable Eaton’s exponent approaches a value of 1.0. Likewise the modified D Exponent approach showed a good match using an exponent of 1.0 and the pore pressure profile obtained from these two normal-trend methods followed a similar path. On the other hand, the Holbrook method from well logs, as well as the AFF and the Bowers methods were implemented to either corroborate the effectiveness of the normal-trend methods or to conclude that the explicit methods are the most suitable to apply in these kinds of conditions. From this study is concluded that intuition does not necessarily distinguish about which is the most effective indirect method to predict pore pressure in an abnormally sub-pressured basin. The normal-trend methods demonstrated to be the most effective. In addition, it was strongly evident that the calibration exponents of the normal-trends methods and explicit methods can vary significantly from region to region. As a result special attention has to be placed on the values that constitute the mathematical models. 1. INTRODUCTION The pore pressure is one of the most essential parameter to construct Geomechanical Earth Models (GEM) for wellbore stability, drilling optimization from ROP modeling, hydraulic fracturing, sanding, reservoir compaction, and fault reactivation into various applications. From the wellbore stability perspective, the pore pressure value is used to estimate the value of the true in-situ stresses helping the construction of the mud window and casing points selected. The pore pressure can be estimated either form “normal trend” or “explicit” methods [5,18]. The most commonly applied normal trend methods encompass the Eaton method from sonic and resistivity logs, D exponent and modified D exponent, Equivalent Depth Method [7], and the Hottman and Johnson (H&J) method [8]. On the other hand, the most recognized explicit methods include the Holbrook method, Bowers method [6], Alixant method [9], and Nygaard, et al method [10]. All these mentioned methods were initially developed to detect and model overpressures; in this application, the Eaton method from sonic logs, the modified D Exponent, the Holbrook method, and the Bowers method are implemented to predict pore pressure in two representative vertical wells: well A and well B in the WCSB.
- North America > Canada > British Columbia (1.00)
- North America > Canada > Alberta (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.49)
Abstract A tight gas reservoir is commonly defined as a reservoir having less than 0.1 milliDarcies permeability. Because of the very low permeability, hydraulic fracturing is usually carried out in efforts to establish commercial production. There are several basic concepts and field cases of different well tests in tight gas reservoirs in the literature. In this paper, we gather information and provide a guide to some of the most important tests. Generally because of low permeability, a well will not flow initially at measurable rates and conventional well testing cannot be applied. We review procedures for design of pre- and postfracture tests in single and dual porosity reservoirs. The prefracture test permits estimating preliminary values of reservoir permeability and initial pressure. The post-fracture test provides data for estimating fracture half length and conductivity. We also review the application of convolution/deconvolution methods to analyze well tests with significant wellbore storage. Because of economic and environmental reasons, short duration procedures are preferred. However, although effective in many instances, these methods also have their own limitations. Introduction Unconventional reservoirs (tight gas, coal bed methane, shales gas and gas hydrates) will be an important pat of the global energy mix for decades to come. Large reserves, long-term potential, costs and gas prices and some other factors account for the great influence of these resources on the future of energy. There is no formal definition for "tight gas." A commonly used definition, describes tight gas reservoirs as those having permeabilities smaller than 0.1 milliDarcies. Well testing is generally done as an aid to estimate gas in-place and recoverable volumes. Initial pressure (pi) is a critical parameter not only for estimating gas in-place, but also for determining how much field development is required and whether or not the field is overdeveloped. In addition to pi, well testing provides an estimate of permeability and skin. A problem associated with well testing in tight gas sands is that usually long times are required to reach radial flow, due to their extremely low permeabilities. Therefore, conventional well tests cannot be applied to these reservoirs. Because of initial uneconomic rates, fracturing is usually required. Lee(2) has suggested procedures for pre- and post-fracture tests design. In order to have measurable gas rates for pre-frac testing, often a breakdown with acid, KCl water or N2 is necessary.
- North America > United States (1.00)
- North America > Canada (0.69)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.54)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Tight gas (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Abstract Recent models show the means of estimating the petrophysical porosity exponent (m) of a reservoir when it is composed of different combinations of matrix, fractures and vugs. For both dual and triple porosity reservoirs, the system is modelled as a parallel resistance network (for matrix and fractures), a series resistance network (for matrix and non-connected vugs) or a combination of parallel/series resistance networks (for matrix, fractures and non-connected vugs). In the case of matrix/fractures, it has been assumed that the flow of the current is parallel to the fractures. This paper shows the effect on m of current flow that is not parallel to the fractures. This type of anisotropy is co-relatable with fracture dip. Maxwell Garnett mixing formula for calculating effective permittivity of a system with aligned ellipsoids and depolarization factors of 0 and 1 leads to the parallel and series resistance networks used in the paper. It is concluded that the change in fracture dip can have a significant effect on the value of m. Not taking this into account can lead, in some cases, to significant errors. The effect of the change of fracture dip on water saturation calculations is illustrated using two examples. Introduction The petrophysical analysis of fractured and vuggy reservoirs has been an area of abundant interest in the oil and gas industry. For example, a key ingredient for successful completion of wells in naturally fractured tight gas formations is the ability to distinguish gas from water-bearing intervals. Proper estimates of petrophysical parameters, including the porosity or cementation exponent m, play an important role in correct estimations of watersaturation (Sw). Towle gave consideration to some assumed pore geometries, as well as tortuosity, and noticed a variation in the porosity exponent m in Archie's equation ranging from 2.67 to 7.3+ for vuggy reservoirs and values much smaller than 2 for fractured reservoirs. Matrix porosity in Towle's models was equal to zero. Aguilera introduced a dual porosity model capable of handling matrix and fracture porosity. That research considered three different values of the porosity exponent: one for the matrix (mb), one for the fractures (mf = 1) and one for the composite system (m). It was found that as the amount of fracturing increased, the value of m became smaller. Rasmus and Draxler and Edwards presented dual porosity models that included potential changes in fracture tortuosity and the porosity exponent (mf) of the fractures. The models are useful, but must be used carefully as they calculate values of m > mb as the total porosity increases, even when the flow of current goes parallel to the fractures. Serra developed a graph of the porosity exponent (m) versus total porosity for both fractured reservoirs and reservoirs with non-connected vugs. The graph is useful, but must be employed carefully as it can lead to errors for certain combinations of matrix and non-connected vug porosities. The main problem with the graph is that Serra's matrix porosity is attached to the bulk volume of the 'composite system.'
- North America > United States (1.00)
- North America > Canada (1.00)
- Europe > Norway > Norwegian Sea (0.24)
- North America > United States > Wyoming > Bighorn Basin (0.99)
- North America > United States > Montana > Bighorn Basin (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Swan Hills Formation (0.99)
- Africa > Angola > South Atlantic Ocean > Lower Congo Basin (0.99)
LiDAR Technology as a Means of Improving Geologic, Geophysical and Reservoir Engineering Evaluations: From Rocks to Realistic Fluid Flow Models
Alfarhan, M. (University of Texas at Dallas) | Deng, J. Hui (University of Calgary) | White, L.S. (University of Texas at Dallas) | Meyer, R. (University of Calgary) | Oldow, J.S. (University of Texas at Dallas) | Krause, F. (University of Calgary) | Aiken, C.L. (University of Calgary) | Aguilera, R. (University of Calgary)
Abstract Outcrops of the Milk River Formation (sandstone, Cretaceous age) at the Writing on Stone Provincial Park in Alberta, Canada have been scanned using ground LiDAR (light detection and ranging) technology. Milk River outcrops represent a real 3D challenge for this technology because of the complexity of hoodoos emanating from pronounced erosion in the area as a result of wind, water and ice following the melting of ice at the end of the last ice age. In addition to the 3D complexity of the hoodoos, the Milk River Formation at Writing on Stone was selected for this project because the geology, studied in detail previously, is characterized by intervals that include a range of sand-rich lithofacies, and is distinguished primarily by subtle differences in grain size and current structures of the sandstones. Also present in the area are relatively flat 2D cliff faces and subvertical fractures. The outcrop exemplifies a challenge for realistic fluid flow modeling. This is of practical importance because these types of rocks develop significant hydrocarbon reservoirs in the Western Canadian sedimentary basin and throughout the world. When buried significant volumes of gas can be trapped in tight formations of similar age. This paper describes an evaluation sequence that includes the planning for LiDAR data collection, actual work and rock sample collection in outcrops, the interpretation and integration with geoscience in a 3D visualization room, and the potential for improved drilling and completion techniques, and reservoir simulation by using the concept ‘from rocks to realistic fluid flow models’. It is concluded that LiDAR provides a powerful technique for sound interpretation of reservoirs rocks and their integration with other sources of information. Introduction The present study was undertaken to test and evaluate the capabilities and limitations of ground-based laser scanning technology (LiDAR) for the construction of reservoir models based on surface outcrops. A multidisciplinary team of the University of Calgary has embarked on a project to investigate and better characterize tight gas/fractured reservoirs, in which the study of outcrop analogues is an integral part. The multidisciplinary research project is called GFREE, an acronym that stands for the integration of geoscience (G), formation evaluation (F), reservoir drilling, completion and stimulation (R), reservoir engineering (RE), and economics and externalities (EE). Before investing heavily in expensive, up-todate LiDAR hardware and software, and in the time and effort of researchers, a pilot study was deemed to be necessary to evaluate the feasibility and usefulness of LiDAR-based mapping/imaging methods. The University of Calgary and the University of Texas at Dallas joined forces to achieve this objective. Herein we report on this pilot study of the various phases in the use of LiDAR, that is, data acquisition, data and image processing, and possible qualitative and quantitative applications of the resulting model. The rocks chosen for the pilot study are the Virgelle Member sandstones at Writing-on-Stone Provincial Park (WOS) in southern Alberta, an area with relatively continuous, superbly exposed outcrops along the Milk River valley.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
Dominant Considerations for Effective Hydraulic Fracturing in Naturally Fractured Tight Gas Carbonates
Arukhe, J.O. (Schulich School of Engineering, University of Calgary) | Aguilera, R. (Schulich School of Engineering, University of Calgary) | Harding, T.G. (Schulich School of Engineering, University of Calgary)
Abstract This study examines the results of laboratory work to establish rock strength data, acid solubility, fracture fluid selection and mineral identification of a fractured tight gas carbonate reservoir. Basic to a successful acid fracture design are acid etching and rotating disc tests which show for a given acid system, conductivity at a given stress (etched width or how much rock is eaten away) and parameters necessary to determine acid reaction rate, reaction order, rate constant and energy of activation at a given temperature. These tests address the measurement of mass transfer and diffusion with or without leak off in carbonates, and also enable the prediction of reactivity versus temperature for various acid strengths. Dynamic fluid losses are measured experimentally and laboratory data are converted to an estimate of in-situ leak off. The leak off profile and wall building coefficients enable a consideration of fluid loss additives for fracturing fluids to build up pressure for fracture opening. In the fracture conductivity tests, closure stress is applied across a test unit for sufficient time to allow the proppant bed to reach a semi-steady state condition while test fluid is forced through the bed. At each stress level, pack width, differential pressure, and average flow rates are measured as fluid is forced through the proppant bed. The proppant pack permeability and conductivity are then evaluated and compared. Introduction A discussion of dominant considerations for effective hydraulic fracturing in naturally fractured tight gas carbonates is presented along with the results of laboratory work to establish rock mechanical properties data, acid solubility, fracture fluid selection and mineral identification for a selected naturally fractured tight gas carbonate reservoir. The carbonates under consideration are located in the Western Canadian Sedimentary Basin (WCSB) in what is usually known as the "Deep Basin" of Alberta (Figure 1). The core samples studied come from the Savannah Creek field (Figures 2) and correspond to the Rundle group Mississippian Mount Head and Livingston carbonates (Figure 3). These carbonates were deposited in a shallow marine ramp setting. These are upward-shallowing cycles ranging from crinoid / bryozoan shoals to lagoonal mud facies. The reservoirs comprise dolomudstones and wackstones with an average pay of approximately 35 m. Reservoir zones can be discontinuous due to lateral facies changes and minor faulting. The presence of natural fractures in the tight formations considered in this research is corroborated by cores and thin sections. Notice the presence of calcite cemented fractures in the whole core and plugs displayed in Figure 4. The thin section shown on Figure 5 presents calcite-filled fractures (pink strip running from upper left to lower right) that have been re-fractured (thin blue streak). The thin section work corroborates that it possible to re-fracture existing healed fractures. General Considerations There are many mechanisms that contribute to the final created geometry (fracture height, fracture width, hydraulic or created fracture length or effective fracture length)2–8 and its evolution in naturally fractured tight gas carbonates. Pump rate, volume injected, fluid viscosity, fluid loss and proppant scheduling combine with static and dynamic rock properties.
- North America > Canada > British Columbia (1.00)
- North America > Canada > Alberta (1.00)
- North America > United States > Texas > Harris County > Houston (0.28)
- Geology > Rock Type (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Mineral > Carbonate Mineral > Calcite (0.45)
- North America > United States > Texas > Permian Basin > Delaware Basin > Sullivan Field (0.99)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (3 more...)
Determination of Biot's Effective Stress Parameter for Permeability of Nikanassin Sandstone
Qiao, L.P. (Schulich School of Engineering, University of Calgary) | Wong, R.C.K. (Schulich School of Engineering, University of Calgary) | Aguilera, R. (Schulich School of Engineering, University of Calgary) | Kantzas, A. (Schulich School of Engineering, University of Calgary)
Abstract In Alberta and British Columbia, a huge amount of tight gas is trapped in relatively impermeable rock formations. Physical fracturing of these formations could enhance the overall formation permeability and, thus improve tight gas extraction. One of the outstanding issues in rock fracturing is to determine the magnitude of applied effective stress. The general effective stress law is defined as: σ eff = σc – α σp, where σc and σp are total confining and fluid pore pressures, respectively. The Biot's constant α is not only a particular material property, but also markedly sensitive to the magnitude of applied confining and pore pressure. The main objective of this study is to experimentally determine stress dependency on the Biot's constant which controls fracturing mechanics in the tight gas formation and gas production rate from the formation at low and high effective stresses, respectively. A series of permeability measurements were conducted on Nikanassin Sandstone core samples from the Lick Creek region in British Columbia under various combinations of confining and pore pressures. In addition, permeability values were measured both along and across bedding planes to investigate any anisotropy in Biot's constant. Introduction Effective stress is the real item which actually controls the mechanical and hydraulic properties of porous rock and soil materials. Terzarghi first brought the effective stress principle, which is defined as σeff = σc – σp, into soil mechanics, where σc and σpare the total confining and fluid pore pressures, respectively. The effective stress principle, though basically very simple, is of fundamental significance in rock and soil mechanics. However, in rocks, especially, the fluid-related or petroleum-related rocks, Terzarghi's effective stress principle may not be always valid. Therefore, the Biot's constant a other than 1.0 was suggested to modify the effective stress principle, and the effective stress principle finally is given by σeff = σc – σp. The value of Biot's constant a for permeability has been found to be 0.9 for joints with polished surfaces and 0.56 for joints made from tension fracture , and 0.6-0.7 for intact Chelmsford granite . Keaney et al. estimated that the average value of Biot's constant α for permeability of Tennessee sandstones is 0.75. Berryman found that for a rock whose mineral phase consists of a single mineral, the value of Biot's constant α should not exceed unity. However, Zoback and Byerlee found that Biot's constant α of some clay-rich sandstones can be as high as 3–4. Walls and Nur found that α varies from 1.2 for clean sandstone to 7.1 for sandstone containing 20% clay. It turns out that the Biot's constant α is not only a mechanical property depending on many factors such as rock type, porosity, pore geometry, rock constituents and their geometrical arrangement, but also markedly sensitive to the magnitude of applied confining and pore pressure. In Alberta and British Columbia, a huge amount of tight gas is trapped in relatively impermeable rock formations.
- North America > United States (1.00)
- North America > Canada > British Columbia (0.65)
- North America > Canada > Alberta (0.56)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)