In the area of thermal oil production, we continue our active program on the flow of heat and high temperature fluids in porous media. An exciting growth area is the integration of solar thermal steam generation and heavy-oil recovery. This concept has garnered significant interest as a way to decrease the variability of steam generation costs arising from fluctuations in natural gas prices. Clearly, solar steam generation helps to reduce life-cycle CO2 emissions as well. The viability of a solar thermal steam generation system (with and without natural gas back-up) for enhanced oil recovery (EOR) in heavy oil sands is under evaluation. It appears that for equivalent average injection rates, comparable breakthrough times and recovery factors are achieved, indicating that daily cyclic fluctuations in steam injection rate do not greatly impact recovery for the reservoir setting under study. By this assessment, solar thermal based or supplemented steam generation systems for EOR appears to be a preferred alternative (or supplement) to fully conventional systems using natural gas (or higher carbon content fuels) in geographical areas with high solar insolation.
On the more traditional side, we continue to quantify through experiment and theory the speed and extent to which steam and hot water imbibition change the wettability, imbibition rate, permeability and ultimately, oil recovery from reservoir rocks such as diatomite. We quantify changes in wettability by measuring relative permeability and the Amott index to water. To date, we have found such changes to be quite beneficial for oil recovery.
In the case of diatomite, large internal surface area, substantial fine material and high steam and condensate temperatures lead to rearrangement of the rock. Hot steam condensate dissolves silica, the silica can then transport with the aqueous phase, and silica precipitates in a different portion of the reservoir as the condensate cools. Hence, permeability might increase near injectors and decrease within the reservoir. We have found that such changes are frequently associated with healing of natural fractures and improvement in rock quality. Our current plans call for conducting experiments with hot water injection into representative diatomite samples and to monitor the evolution of porosity with our CT scanner. Likewise the evolution of the pressure profile at a given rate is monitored. In this way, we will measure the time evolution of permeability and porosity in a well characterized and controlled environment.
We are also examining of the role of noncondensable gases, such as N2 and CO2, on the gravity drainage of viscous oil from heterogeneous media, such as vuggy carbonates.
Current projects in the area of steam injection and diatomite are:
- steady-state relative permeability of core samples as a function of temperature,
- X-ray CT scan visualization of fines mobilization and transport through core, and
- reservoir simulation of continuous-variable rate steam injection including geomechanical effects
Looking forward, there is general consensus that hydrocarbons shall continue to provide a large fraction of the world`s primary energy supply well throughout the 21st century. Hydrocarbon consumption in the next quarter century is likely to bifurcate into natural gas for its cleanliness and heavy hydrocarbons such as tar sands, heavy oil, and extra heavy oil. The latter are abundant and shall replace conventional oil as the source of liquid transportation fuels as conventional oil production declines and demand from expanding economies continues. Farther into the future, heavy hydrocarbons are a ready primary energy source to be utilized for production of gaseous fuels including hydrogen and methane. From an environmental standpoint, the world needs the energy embodied in heavy hydrocarbons, but not the carbon, sulfur, and heavy metals that include chromium, vanadium, and nickel.
In-situ combustion (ISC) possesses advantages over surface-generated steam for production of viscous and heavy oils. For example, steam injection is problematic for deep reservoirs in terms of wellbore heat losses and generation of heat above the critical point of water. ISC has drastically lower requirements for water and natural gas, and potentially a smaller surface footprint in comparison to steam. Additionally, ISC processes can be modified to upgrade crude oil in the reservoir. In spite of its apparent advantages, prediction of the likelihood of successful ISC is unclear. Our research is directed at improving predictability.
A workflow is under development that combines experimental measurements, full-physics mechanistic simulation, and upscaling to improve the predictability of successful and unsuccessful ISC at field scale. The development of useful simulation parameters is a natural feature of the workflow. Measurements of crude-oil combustion characteristics at lab scale are important to the overall effort and, importantly, the combination of ramped temperature oxidation (RTO) kinetics and combustion tube measurements suggests a high-resolution pseudo-reaction model that is predictive of combustion at lab scale. Successively, this high-resolution model is used to provide the oil saturation that is converted to fuel and subsequently burned as a function of oxygen partial pressure, oxygen flux, rock type and heterogeneities and so on. Field-scale simulations do not employ Arrhenius kinetics. As a result, significant stiffness is removed from the finite difference simulation of the governing equations. Accordingly, field-scale simulations run quickly in comparison to cases employing Arrhenius kinetics. Results employing the new upscaling methodology show very little sensitivity to grid block size.
Current projects in the area of in-situ combustion are:
- next generation ramped temperature oxidation (RTO) reactors for rapid measurement of combustion kinetics,
- mechanistic kinetic models of crude oil combustion,
- a workflow for upscaling from laboratory measurements to field-scale simulation of ISC, and
demonstration exercises of upscaled simulations at reservoir scale.
The area of enhanced recovery combines our longtime interest in multiphase flow and rock properties as well as renewed interest in the use of chemicals to enhance oil recovery and/or control the mobility of injected water or gas.
An area of significant current interest is unstable, multiphase flows in porous media. This interest has several motivations. First, water injection into a viscous oil results in a so-called high mobility ratio waterflood. Such dynamics are not fully described in a mechanistic or simulation framework. Second, given the possible opportunity of widespread carbon dioxide for enhanced oil recovery and the need for convincingly engineered disposal operations, the dynamics of gas/oil and gas/water displacements need to be elucidated fully.
Currently, we are investigating:
- the dynamics of unstable flows and
- the trapping of nonwetting phase at both the pore and core scale.
Chemical EOR processes are demonstrated to improve greatly imbibition efficiency, and such processes have undergone a renaissance. Three factors contributing to renewed interest are the relatively low price of chemicals in relation to the price of crude oil, the ease of implementation of chemical-based EOR compared to other EOR processes, and the documented success in enhancing recovery at Daqing oil field in China.
In our work, we do not focus on the development of chemicals nor on the selection of optimal systems. Rather we focus on improving the mechanistic understanding of enhanced recovery processes including
- alkali-surfactant and alkali-surfactant-polymer processes for enhanced recovery from carbonate reservoirs,
- foamed gas stabilized with surfactant to achieve mobility control of gas in fractured and unfractured porous media,
- polymers to reduce injected water mobility for displacement of viscous oil, and
- altering surface chemistry of siliceous and carbonaceous rocks to obtain wettability favorable to oil recovery.
Two-phase multiphase flow of miscible fluids in porous media is ultimately determined by pore-scale processes. Pore-level observations of fluid flow as well as oil and gas-trapping mechanisms are valuable to interpret observations at larger scale (i.e., core scale). Such observations also help us to deepen our mechanistic understandings and provide validation of pore network models and direct numerical simulations of fluid flow.
We create microfluidic devices, referred to as micromodels, using electronics grade silicon wafers and photolithographic techniques. Two-dimensional micromodels allow direct observation of pore-scale events. They contain an etched pore network pattern that is directly observable with a microscope. A first step is the imaging of representative pore features in rock thin sections. The end result is a two-dimensional medium with a precisely known pore network pattern and number of pores. To date, we have created micromodels of Berea sandstone, a heavy-oil sand, an idealized rough fracture, and a dual porosity limestone.
Current projects in the area of microfluidics are:
- pore-level mechanisms of surfactant polymer EOR,
- dynamics of unstable drainage displacement,
- mechanics of residual nonwetting phase trapping as applied to WAG and carbon sequestration, and
- visualization of aqueous wetting foams, for mobility control, in fractures.
Natural gas from shale has emerged as, potentially, the most important new energy resource of the 21st century. Once recovered from underground, shale gas is the same as conventional natural gas. Underground, methane in shale is different from conventional natural gas in that the gas may be adsorbed on the internal surface areas of shale and the gas may flow through pores that are roughly the same size as methane.
The over-arching objective within this area is to conduct a multiscale, multiphysics, interdisciplinary laboratory study that assesses the feasibility of enhancing shale gas recovery through gas injection and of using depleted organic-rich gas shale reservoirs for large-scale CO2 sequestration. Nitrogen, carbon dioxide or the mixture of the two gases (such as flue gas) are the gases usually considered to enhance recovery. The principal scientific objectives of this work are to determine how the physical and chemical processes associated with CO2 storage in organic-rich gas shales affect injectivity and storage capacity (over long periods of time), and the ability of the gas shale to sequester CO2 (as both a free and adsorbed phase) for thousands of years. We shall delineate the physical and chemical aspects of CO2/shale interactions, characterize transport processes and mobility of supercritical CO2 in hydrofracs, natural fractures, shale matrix, and pores.
Our efforts are directed towards the understanding of gas transport, adsorption and desorption for enhanced methane recovery and CO2 sequestration in gas shale. Experimental work is being carried out to image gas flow in shale. At the same time, we are working on the development of numerical models of gas diffusion and adsorption.
Current projects in the area of gas shale are:
- prediction of sorption phenomena using density functional theory to understand the short and long range interactions for a particle based approach and the Monte Carlo method to conduct adsorption isotherm calculations,
- imaging of gas shale structure and distribution of organic material using X-ray computed tomography (CT) at the micron and 20 nm scales,
- scanning electron microscope studies to complement the fine-scale X-ray CT imaging
- imaging of gas tracer transport through shale core samples using X-ray CT at the 0.25 mm scale,
- mechanistic simulation of gas transport through shale incorporating Klinkenberg effects, gas sorption, and multiscale transport.