The validity of the cubic law for laminar flow of fluids through open fractures consisting of parallel planar plates has been established by others over a wide range of conditions with apertures ranging down to a minimum of 0.2 µm. The law may be given in simplified form by Q/Δh = C(2b)3, where Q is the flow rate, Δh is the difference in hydraulic head, C is a constant that depends on the flow geometry and fluid properties, and 2b is the fracture aperture. The validity of this law for flow in a closed fracture where the surfaces are in contact and the aperture is being decreased under stress has been investigated at room temperature by using homogeneous samples of granite, basalt, and marble. Tension fractures were artificially induced, and the laboratory setup used radial as well as straight flow geometries. Apertures ranged from 250 down to 4µm, which was the minimum size that could be attained under a normal stress of 20 MPa. The cubic law was found to be valid whether the fracture surfaces were held open or were being closed under stress, and the results are not dependent on rock type. Permeability was uniquely defined by fracture aperture and was independent of the stress history used in these investigations. The effects of deviations from the ideal parallel plate concept only cause an apparent reduction in flow and may be incorporated into the cubic law by replacing C by C/ƒ. The factor ƒ varied from 1.04 to 1.65 in these investigations. The model of a fracture that is being closed under normal stress is visualized as being controlled by the strength of the asperities that are in contact. These contact areas are able to withstand significant stresses while maintaining space for fluids to continue to flow as the fracture aperture decreases. The controlling factor is the magnitude of the aperture, and since flow depends on (2b)3, a slight change in aperture evidently can easily dominate any other change in the geometry of the flow field. Thus one does not see any noticeable shift in the correlations of our experimental results in passing from a condition where the fracture surfaces were held open to one where the surfaces were being closed under stress.

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VALIDITY OF CUBIC LAW FOR FLUID FLOW IN A DEFORMABLE ROCK FRACTURE - eScholarship

Background
Engineering student team projects are frequently used to meet professional learning outcomes. Industrial and organizational psychologists study teams in the industry settings for which we prepare students, yet this research does not effectively inform engineering education.

Purpose
This research review sought to demonstrate the relevance of literature on teams literature from industrial and organizational psychology to engineering education and to identify implications for practice and future directions for research.

Scope/Method
Phase 1 systematically reviewed 104 articles published from 2007 to 2012 describing engineering and computer science student team projects and sought to answer the following questions: What professional learning outcomes have been met by team projects? What negative student team behaviors have faculty sought to minimize? What literature has been used to inform development of teamwork outcomes? Phase 2 reviewed five team effectiveness constructs selected according to the results of Phase 1: social loafing, interdependence, conflict, trust, and shared mental models. Examples from Phase 1 articles and our own work explain how this research informs facilitation and assessment of engineering student teams.

Conclusions
Engineering faculty sought to achieve a variety of outcomes through team projects, including teamwork, communication, sustainability, and consideration of global/societal design context. They sought to avoid social loafing and conflict while building trust to ensure equal team effort. That few Phase 1 articles engaged the literature about team effectiveness indicates there is great opportunity to apply industrial and organizational psychology research to engineering education.

Team Effectiveness Theory from Industrial and Organizational Psychology Applied to Engineering Student Project Teams: A Research Review

Thermo-hydro-mechanical-chemical couplings controlling CH4 production and CO2 sequestration in enhanced coalbed methane recovery

Porosity and permeability characterization of coal: A micro-computed tomography study

A critical review of low salinity water flooding: Mechanism, laboratory and field application

Numerical simulations are widely used to investigate the performance of simultaneous water and gas (SWAG) injection in the field scale. However, they usually use two-phase water and gas relative permeability functions (kr) and one of the existing correlations (e.g., Stone, Baker) to calculate oil relative permeability in a three-phase displacement. Moreover, the same krg is used for all SWAG injections at different miscibility conditions and fraction of gas injected (FGI).The recent experimental work has shown that gas relative permeability functions in three-phase SWAG are significantly different from the conventionally used two-phase functions. This paper presents a field scale simulation study to investigate the co-optimization of CO2 storage and EOR using experimentally estimated gas relative permeability functions.A three-dimensional, layered reservoir model initially saturated with oil phase and connate water is used to examine different injection schemes for co-optimizing oil recovery and CO2 storage efficiency. A mixture of hexane and decane (0.65 and 0.35 mole fraction hexane and decane, respectively) is used for the oil phase. Numerical simulations are run at 70°C and three different pressures (1300, 1700 and 2100 psi) to represent immiscible, near-miscible and miscible displacements for the given fluids. A FGI of 0.5 is used for SWAG displacements run at immiscible, near-miscible and miscible displacements. Then the effect of FGI dependent relative permeability on co-optimization of CO2 storage and EOR is investigated in the near-miscible condition for FGI values equal to 0.25, 0.5, 0.75 and 1.0.The field scale simulation results, run using experimentally estimated three-phase gas relative permeability are compared with the results when two-phase gas relative permeability is used. The numerical simulation results show that oil recovery rate is underestimated if two-phase relative permeability is used. This effect is more prominent in near-miscible and miscible displacements than immiscible. CO2 storage efficiency and therefore co-optimization function is significantly increased when estimated three-phase gas relative permeability functions are used. Therefore, the accurate description of co-optimization of CO2 storage and EOR in SWAG requires laboratory estimated three-phase relative permeability functions.

Field Scale Co-Optimisation of CO2 Enhanced Oil Recovery and Storage Through Swag Injection Using Laboratory Estimated Relative Permeabilities

Simultaneous water and gas (SWAG) injection is known as an efficient enhanced oil recovery method. Numerical simulations generally use the two-phase gas relative permeability (krg) to model three-phase SWAG processes where the same krg is used for different fractional gas injected (FGI) values. This approach does not account for the reduction in krg in presence of water. In this paper, we investigate the impact of FGI on krg for predicting SWAG flood performance through an experimental and simulation methodology. Core flooding experiments are performed at different FGI values on a sandstone sample. A mixture of hexane and decane is used as the oil phase and CO2 and water as injectants. Experiments are run at 70oC and 1700 psi which represents the near-miscible displacements for the given fluids. Oil recovery, differential pressure and compositions are recorded during experiments. Then history matching is conducted to estimate the FGI-dependent relative permeability function. Numerical simulations show that accurate modelling of SWAG displacement requires FGI dependent relative permeability. Considerable reduction in krg in SWAG, compared to conventional two-phase functions, improves the vertical sweep efficiency of CO2. The highest reduction is obtained in displacement with FGI=0.75.

Furqan Hussain

Papers

Field Scale Co-Optimisation of CO2 Enhanced Oil Recovery and Storage Through Swag Injection Using Laboratory Estimated Relative Permeabilities

Effect of Fractional Gas Injected on Gas Relative Permeability in Near-miscible SWAG Flood

Tertiary oil recovery and CO2 storage from laboratory injection of CO2 or water-saturated CO2 into a sandstone core

Testing Tutorial-Lecture Swapping Technique in Reservoir Engineering Course to Enhance Students’ Learning Experience