Research

Reservoir Definition
Primary Recovery of Heavy Oil
High Mobility Ratio Waterflood
Artic and offshore
Thermal in low perm and fractures
In-Situ Upgrading

Capabilities

Technical Staff
Expertise
Facilities

Current SUPRI-A Scope and the Way Forward

Current research activities and accomplishments are laid out in our core areas of multiphase flow and rock properties, hot fluid injection, in-situ combustion, and reservoir definition.

While we have conducted projects with various objectives, these areas have described our core focus for at least the past 10 years. Our current research into the mechanisms of gas and water flow in coal beds is a logical outgrowth of our effort to understand flow properties in low permeability fractured rocks. A suite of recovery methods is needed to address the broad range of flow, rock, and geomechanical characteristics of unconventional hydrocarbon resources. Our core areas of research will remain unchanged, but significant new effort is envisioned. A common thread running through the experimental portion of our work is the use of the SUPRI X-ray computed tomography (CT) scanner to image oil, water, and gas saturation distributions. Thus, we obtain the position and shapes of displacement fronts in porous media. The CT equipment developed at Stanford is unique in that it allows both multi-energy scans for imaging of three phases and vertical or horizontal positioning.

The following description is intended to illustrate our vision for future research activities, but the list is not necessarily inclusive or exclusive.

Reservoir Definition

The central idea of reservoir definition is to apply reservoir engineering techniques to improve our ability to understand reservoir rock and fluid properties and reservoir architecture, and the flow paths and flow barriers that arise from this architecture. Our interest in this topic is not just reservoir information, such as the distribution of permeability, but how petrophysical properties and the resulting flow patterns determine the success of enhanced recovery processes. Reservoir definition efforts underpin all efforts at improved recovery.

History matching using reservoir simulators plays an important role in reservoir engineering. It is important for prediction and data interpretation. In many cases we have tracer or water breakthrough information at producers and pressure information. These data contain much information about the permeability distribution of the reservoir, but it is difficult to infer this distribution. Most approaches to this inverse problem begin with a conventional reservoir simulator and manipulate parameters at the grid-block level corresponding to conventional simulation grids. There are many grid blocks, thus the optimization is slow, and conventional finite difference reservoir simulators are slow. Streamline based reservoir simulators have been developed recently that execute much more rapidly, relative to conventional finite difference based simulation, and are quite accurate in that numerical dispersion is minimized. In streamline simulation, the three-dimensional flow simulation is broken down into a number of one-dimensional flow problems. We have applied the concepts of streamlines to infer permeability fields based on tracer breakthrough, water cut, and injection/production pressure information.

The basic idea is to switch the optimization to the streamline level rather than optimizing parameters associated with individual grid blocks. For instance, the effective permeability along a streamline, or a bundle of streamlines, might be adjusted to match reference data rather than the permeability of each grid block. With streamlines, we compute the time of flight of a fluid volume along a streamline, and so we also know the breakthrough times for each individual streamline. The streamline or series of streamlines that under or over predict reservoir performance are thus easily identified. The streamline properties, for instance permeability, are adjusted to match the reference production curve pressure histories. In this way, we dramatically reduce the size of the optimization problem. Work to date has been encouraging and will continue.

Cold Production: Primary Recovery of Heavy Oil

Heavy-oil recovery projects to date have focused largely on shallow, low-pressure reservoirs where steam is easily injected. The surface conditions above such reservoirs have been on-shore and free of permafrost or other Arctic conditions. While the cumulative oil production totals of heavy oil are on the order of billions of barrels this represents only a small fraction of the total oil in place. Cold production of heavy oils has substantially benefited from horizontal wells and the increased contact of well with reservoir and the relatively high depletion rates horizontal wells make possible. The objective of future research in this area is to complete the development of a conceptual model for heavy-oil solution gas drive and to translate this conceptual model into a numerical model. This objective is accomplished experimentally using representative crude oils in sands, conducting physical measurements, as well as model development to further the interpretation of experiments and to provide a means of scaling from laboratory to field conditions.

Our rationale is that optimum primary recovery of heavy oil is a key toward development of the resource. Effective cold production of heavy oil represents the first step in producing heavy oil efficiently. Significant cold production pays for the expense of well installation and delays the need to commit to sizeable capital outlays for steam injection facilities. Thus, if primary recovery is economic, and thereby attractive, further development of the resources follows.

We are answering these questions: (i)Are there easy to measure crude-oil properties that indicate significant stability of dispersed gas bubbles in crude oil and therefore significant cold production? (ii) What is the role of initial water saturation on the heavy-oil solution gas drive process and oil recovery? (iii) How is a mechanistic, full-featured simulator of cold production best formulated?

Cold Production: High Mobility Ratio Waterflood

The objective of our research is to establish the physics of high mobility ratio waterflood through the acquisition of a suite of laboratory data (in-situ saturation versus time) in a linear geometry. This suite of data provides the foundations for development of standardized laboratory practices to gauge the potential of waterflooding of heavy oil. By analogy to miscible flood, the sweep efficiency likely depends on the distribution of heterogeneity; because the displacement is immiscible, the local displacement efficiency must be less than 1. Beyond these generalizations, there is, apparently, little or no in-situ, fine-scale (order mm3) saturation versus time data for high mobility ratio water flood in extensively characterized porous media.

Our rationale is that immiscible, unfavorable mobility ratio displacements are little studied and summarily dismissed for heavy-oil recovery. Nevertheless, in Arctic or offshore conditions there are perceived to be relatively few recovery options following primary depletion. Waterflooding may be economic, sustain recovery, and prolong reservoir life until appropriate tertiary recovery options become available.

Evaluation of waterflooding field projects requires extensive simulation and for simulation to be accurate rock petrophysical properties, and especially relative permeability, must be representative. Nevertheless, porous media laden with viscous oil are difficult to analyze. This research answers two fundamental questions with respect to core analysis: (i) Are steady-state measurements representative of the dynamic displacement of viscous oil? (ii) Can a less viscous oil be used in place of the true oil viscosity during measurement of rock flow properties?

Thermal Recovery: Arctic and Offshore

This area lays the technical foundations of successful thermal recovery processes for heavy oil in Arctic or offshore conditions. That is, we will establish thermal recovery as a viable enhanced recovery process. Key components of this effort are cyclic steam injection and mobility control of steam using aqueous foams. Our rationale is that when viewed solely from a reservoir perspective, thermally enhanced oil production, and most likely steam injection, is clearly the option to employ for enhanced oil recovery. Heating reduces the oil viscosity substantially thereby improving flow rates and speeding up ultimate recovery. The presence of permafrost, however, to depths of roughly 2000 feet leads most to discount summarily thermal recovery for Arctic conditions. This task makes a complete case for thermal oil recovery by considering well completions through to mobility control. Accordingly, this work clearly benefits ``conventional'' thermal recovery efforts.

Key questions to be answered include: (i) What are the well completion options available to deliver surface generated steam to reservoirs in cold environments? (ii) When viewed on a common basis, such as volume of gas required, how much energy is required to achieve a given oil recovery? Options considered are surface-generated steam, electric resistive heating of reservoir volume, and miscible, or partially miscible gas injection. (iii) Can an accurate, semi-analytical model of cyclic steaming be developed? (iv) If not steam injection, then what effective heavy oil recovery techniques remain? (v) What functional relationships best describe foamed-gas mobility as a function of pressure gradient, rock permeability, and surfactant concentration?

Thermal Recovery: Low Permeability, Fractured Reservoirs

The ultimate goals of this work are (1) to improve our understanding of multiphase fluid and heat flow characteristics of low-permeability fractured rocks as obtained via laboratory experiments, (2) use this understanding to obtain more accurate constitutive equations, such as relative permeability,that describe fluid flow, and (3) to leverage laboratory results into an improved, steam-injection based recovery method for low permeability rocks containing medium and heavy crude oils. The main rock types examined will be diatomite, and perhaps a carbonate.

Of substantial interest is the pore structure and flow characteristics of diatomite, a low permeability (0.1 to 10 mD) and high porosity (0.4 to 0.7) siliceous shale. We desire a betterunderstanding of flow in the matrix of this rock and matrix to fracture transfer of fluids. Flow studies are naturally divided into experiments that probe behavior in the matrix, flow in fractures, and matrix/fracture interactions. At Stanford, we have designed and tested apparatus that allows visualization of displacement patterns and macroscopic fluid flow pathways in unfractured and fractured low-permeability media. The entire length of a core (up to 14 in) is imaged simultaneously with negligible X-ray CT artifacts. Experiments can be conducted under (i) free imbibition, (ii) forced imbibition, (iii) controlled imbibition, and (iv) counter-current imbibition conditions. Controlled imbibition is possible using high-pressure syringe pumps that can control either injection pressure or injection rate. To establish the similarity in flow mechanisms between diatomite and other rocks, we study simultaneously sandstone and to a lesser extent chalk.

Experiments are being conducted under flow and initial fluid saturation conditions that are relevant to the field and also under quasi-static conditions. Ideally, reservoir rock samples with varying wettability are characterized with respect to pore size, shape and frequency; then rock from the same or a similar sample will be subjected to imbibition/displacement tests. This work is necessary to further develop our understanding of oil/water location and transport in diatomite given different dynamic and quasi-static conditions. In particular, we will have measured the recovery efficiency and residual oil saturation under different dynamic conditions of imbibition. Once a sufficient base of spontaneous imbibition data is collected, we use a semi-analytical technique for obtaining relative permeability and capillary pressure from imbibition experiments.

Matrix to fracture interactions of porous media are much studied, but not well understood. In companion work, we study imbibition and oil production mechanisms to better understand matrix/fracture transport in fractured porous media. We use both the CT scanner with cores of prescribed fracture geometry and etched-silicon micromodels that allow direct visualization of flow processes under a microscope. Micromodels will be redesigned so that both countercurrent and cocurrent imbibition can be visualized. Hence, we will observe directly oil production from the matrix into the fracture and water imbibition into the matrix. Water flow rate through the fracture will also be varied to simulate fractures that are nearer or farther from a well. Companion experiments with similar matrix-fracture geometry will be conducted and monitored in the CT scanner. When complete, we will have a much clearer understanding of how factors such as flow rate in the fracture, fractional flow of water in the fracture, and fracture geometry affect matrix to fracture transfer of oil. We intend to develop more accurate formulations for the corresponding terms used in reservoir simulation

In-Situ Upgrading

This topic includes our longtime work regarding in-situ combustion as well as possible new effort. To date, we have demonstrated that combustion results in modest increases in the API gravity of crude oil as well as the reduction of sulfur in the oil produced. Our combustion research will continue.

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 that may 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. We intend to position ourselves to explore in-situ processes for transforming heavy oil.

Progress and support

To follow our research progress and to take an active part in supporting this work, please see our affiliation program.

Energy Resources Engineering Department, School of Earth Sciences, Stanford, CA
kovscek@stanford.edu