Our forty_first annual meeting will take place on April 19 - 20, 2018. Find the agenda here.
The meeting will take place at the Green Earth Sciences Building, at Stanford.
We are offering a Summer short course on Thermal recovery coming up this August, 20-23.
Summer Short Course: Thermal Recovery
Instructors: Anthony R. Kovscek & Louis M. Castanier
Steam injection, and thermal recovery in general, remains the most popular enhanced oil recovery method. This course is intended to cover thermal recovery principles and practice from analytical models for vertical wells to the latest information on horizontal wells. Both steam injection and in-situ combustion methods are examined. The course consists of lectures and examples worked in class.
Who should attend
This course is intended for engineers and geologists who wish to expand their knowledge of thermal recovery methods and heavy oil. Primarily a reservoir engineering viewpoint is taken. Prior experience with steam injection, in-situ combustion, and heat and mass transfer in porous media is not assumed.
TONY KOVSCEK is an Associate Professor of Energy Resources Engineering. He holds Ph.D. and B. S. degrees from the University of California, Berkeley and the University of Washington, respectively.
LOUIS CASTANIER holds Ph.D., M.E., and B.S degrees from Toulouse University.
My research aims to investigate the mechanisms of VRR < 1 in light oil water floods and understand the underlying physics using carbonate-like micromodels. VRR<1 process is a combination of both solution gas drive and waterflooding processes. Studies in the literature have to a large extent covered aspects pertaining to VRR<1 in heavy oil, but it is still short in similar work for light oil. Direct visualization of using micromodels will allow us to determine the benefits of the VRR<1, time at which the process should start and how to introduce further improvements to ultimately achieve higher oil recoveries.
My research focuses on studying the stability of foam against hydrocarbons in porous media. Foam can overcome some of the issues encountered by gas injection such as gravity segregation and viscous fingering of the gas by increasing the apparent gas viscosity and/or diverting some of the gas to the unswept areas in the reservoir. Without the stability of foam against fluids in the reservoir, specifically oil, the benefits of foam injection is never realized. Through conducting experiments of foam flow in micromodels that contain waterflood residual oil saturation, I try to identify and understand the various mechanisms causing foam instability due to the presence of oil.
My research aims to examine the behavior of energized fluids when applied in waterless shale fracturing; Specifically, to investigate the feasibility of utilizing CO2 as fracturing fluid in different phases. Limited amount of work is presented in the literature due to challenges introduced by the combination of triaxial loading and high pressure and temperature conditions . However, understanding energized fracturing is essential to identify conditions where energized fluids outperform other fracturing fluids thus enhancing oil recovery in shale reservoirs
My research focuses on nanocatalysis and nanoparticle transport in the porous media. We aim to understand better the effects of metallic nanoparticles on low-temperature oxidation, fuel formation, and combustion during thermal recovery. We also investigate novel nanoparticle delivery methods to the porous media through direct visualization experiments and established modeling techniques.
My research is focused on applying additive manufacturing to problems in petroleum recovery and microfluidic fluid flow. Specifically, I am interested in adapting existing 3D printing technologies such as stereolithography, electrophoretic deposition, and selective laser sintering and developing novel 3D printing technologies to constructing repeatable porous media samples.
My research aims to understand the fracture behavior of oil shale as a function of the thermal history. Samples are subjected to a reservoir setting through the application of anoxic conditions and confinement while heating. Also, continuous mass and temperature measurements are of interest for basic understanding of the kinetics at hand. This plays an important role in the understanding of oil shale and a first step in trying to commercialize the resource.
My work focuses on implementing innovative imaging techniques to probe in-situ pore-scale structures and phenomena in source rocks. I am mobilizing a wide spectrum of conventional techniques (X-RayCT, pycnometry, MICP, N2 sorption, SEM, XRD, XRF) to investigate shale samples and identify current limitations. Simultaneously, I am developing laboratory-scale microfluidic setups and methodologies for porosity mapping and in-situ fluid transport monitoring by μX-Ray Fluorescence and Nuclear Magnetic Resonance.
My research focus is on understanding how the micro- and nanoscale features in shale systems affect properties such as porosity and fluid transport. I am using a range of X-ray and electron microscopy characterization techniques in order to provide a more accurate representation of the mineralogy and pore networks in these materials. These findings can be used to improve estimations of hydrocarbon production and storage capacity in shale reservoirs.
My research aims to study the effect of injection water salinity on the wettability of carbonate surfaces. There are studies showing that oil recovery of the carbonates can be increased by altering the salinity and ionic content of the injected water. My current work is trying to understand the mechanisms for the increased oil recovery and the wettability alteration of the carbonates. My research involves electrokinetic study of the carbonate surfaces.
My research seeks to understand some of the mechanisms that govern in situ combustion in fractured reservoirs through simple experiments and through numerical simulations. Some of the mechanisms of interest include diffusion of oxygen from the fractures to the matrix and the propagation of the combustion front in the presence of fractures. The analysis is based on studying the interaction between the matrix and a single fracture, which can then be extrapolated qualitatively to effects when multiples fractures are present. The final objective is to identify a range of critical parameters for combustion to be successful in fractured reservoirs which will assist in the design of full field applications.
My research focuses on micro-visual study of foam behavior in fractures. Foam is a unique fluid applied in petroleum industry for decades. Specific properties of foam including its fantastic microstructure and its nature in controlling the unfavorable mobility contrast problems makes it a successful agent for these applications. Practical application of foam requires a predictive model for foam displacement in porous media. This model can incorporate pore-level analysis of different mechanisms in foam applications. The population balance method is applied to describe the foam behavior in fractures. This model considers the mass and energy balance equations to hold the reservoir simulation approaches. Hence, it is used to address the evolution of foam texture and reducing the gas mobility. This method provides a comprehensive framework to cover all relevant physics of foam generation and transport. Furthermore, the pore level events in foam generation, coalescence, and constitutive relations are well depicted in this method. Analyzing the experimental micromodel studies and the predicted results from simulation model, provides a thoroughgoing study of foam behavior in the fractures.
Numerical simulation of In-Situ Combustion processes has proven to be challenging due to the coupled nature of the governing equations, the many physical phenomena that need to be considered and the multi-scale nature of the problem, typically resulting in a large, ill-conditioned system of equations. I work on the simulation of 1D combustion tube experiments, and I am currently focusing on implementing, testing and improving a combustion capability in Stanford’s AD-GPRS reservoir simulator. This will provide the controlled numerical environment we need to better identify, understand and solve some of the numerical challenges of ISC.
My work focuses on implementing a reaction-model free kinetics (RMFK) approach in the simulation of in-situ combustion (ISC) of heavy oil. The RMFK approach directly uses kinetic cell experimental results to model the changes in compositions as the oil reacts in the presence of oxygen. This new method eliminates the painstaking evaluation of possible reaction schemes necessary to describe the chemical reactions occurring during ISC.
My goal is to improve oil recovery (increasing reserves) from offshore carbonate fields. Previous researches have accomplished it but with the current price of oil some of them would be not affordable; therefore, my work is focused to use raw materials like sea water to tailor less expensive solutions. Currently, I am involved in tridimensional tracking of wettability alteration using MicroCT scanning.
My research interests involve developing and using microfluidic platforms to visualize pore-scale flow phenomena relevant to reservoir engineering. Secondary and tertiary recovery can cause clay particles to detach from the rock matrix and block subsequent pore space, significantly reducing reservoir permeability. Currently, I am conducting experiments to visualize the impact of brine composition and salt concentration on the release of clay particles from the rock matrix.
My research aims at understanding the pore scale phenomena involved in wettability change in oil wet fractured reservoirs. The main mechanisms investigated are counter current imbibition and diffusion for chemical floods and low salinity applications. I am using two dimensional micro models to investigate the micro scale physics. The objective is to understand the underlaying mechanisms and find ways how to accelerate and upscale them.
Polymer flood is the one of the EOR (enhanced oil recovery) method to control the mobility ratio between displaced and displacing fluids. Improved mobility ratio by the polymer flood overcomes gravity overriding, viscous fingering, and channeling; hence, enhancing oil recovery. Significant mechanisms attributed to EOR in polymer flooding has not been fully understood because an in-situ rheology of polymer become more complex in geochemically heterogeneous porous media where polymer-related non-linear effects including viscoelasticity, degradation, and mechanical entrapment exist.
Therefore, my primary research project entails a contribution to the sparse body of knowledge on micro-pore scale fluid flow in geochemically heterogeneous porous media. To achieve the goal, my research is part of cutting-edge efforts to develop an advanced platform and methodology enabling the real-time monitoring of fluid dynamics. In addition, a finite-volume toolbox OpenFOAM, open source CFD solver, has been used to simulate non-linear effects in the flow of viscoelastic fluids (shear-thinning behavior) through porous media.
I study the effects of production methods (such as hot water imbibition and in-situ combustion) on reservoir rocks and provide analytical and geological support for SUPRI-A. I collect the following data: image analysis (typically pore structure), FTIR (composition), microprobe (composition), SEM (elemental composition, images, and texture characterization), mercury porosimetry, petrography (mineral composition and texture), silica analyses, and ICP (elemental composition). I analyze these data types as well as conventional core analyses, XRF (oxide composition), XRD (mineral composition), and wireline log data.
My main research interests involve porous media flows, enhanced oil recovery (EOR) techniques, modeling and simulations. In particular, I am currently developing a streamline-based computer code aiming at improving InSitu combustion prediction accuracy and efficiency. In this code we couple the strengths of streamline method to a non-Arrhenius reaction upscaling technique that has shown improved robustness and far less sensitivity to grid size.
My research interests relate to experimental investigation of oil recovery in low-permeability resources, such as diatomite. My research explores the impact of different variables related to the recovery method (such as temperature, injection mode, miscibility conditions, injected fluid) and/or rock properties and how these are altered (wettability, porosity and permeability) and how they affect the effectiveness of the total oil recovered. I use X-ray imaging as a supporting technology to complement and enhance the data and the simulation modelling of these processes.
I am also interested in shale rock characterization though X-ray imaging and through analog materials experimentation, as a fundamental step towards its profiling as a viable resource for CO2 sequestration, and as oil and gas source. In particular, I conduct meso and nano scale imaging on shale samples to help better understand its microstructure and how fluid flows through it.
I am studying enhanced oil recovery (EOR) and improved oil recovery (IOR) for heavy oil fields. Also, I have an interest on geological CO2 sequestration under aquifers and hydrocarbon fields to prevent and reduce CO2 emissions. In particular, I have studied the interfacial phenomena between brine and rock under oil and supercritical CO2 phase.
I am currently studying the viability of a solar thermal steam generation system (with and without natural gas back-up) for enhanced oil recovery (EOR) in diatomites. More specifically, I am focussed on the geomechanical effects arising due to the variability of solar enery for generating steam, using a numerical simulation based approach for analysis. Additionally, I am interested in understanding the fluid transport mechanisms in shale reservoirs, using dual/triple - porosity analyses for the same.
My research group and I examine the physics of oil recovery at length scales that vary from the pore to the laboratory the reservoir. The organizing themes are flow imaging to delineate the mechanisms of multiphase flow (oil, water, and gas) in porous media and the synthesis of models from experimental, theoretical, and field data. In all of our work, we strive to interweave physical observations (mainly experimental) and theory.
Gathering and Breakfast
Introductions and Overview
Spontaneous Emulsification During Low Salinity Water Floods Microvisualization Experiments
Advanced Wettability Alteration Characterization Using a 3D Carbonate Micromodel
Spontaneous Fractal Fingering at Miscible Fluid Interfaces
Imaging Microscale Asphaltene Deposition Using a Deep Bed Filtration Micromodel
Thermally Induced Nanoparticle Delivery to Porous Media Via Microemulsions
Transit to Green Earth Sciences Bldg.
GESB ARCO Courtyard
SPE DL Lecture
Torsten Clemens, rm. 104
Transit to Black Community Center
Study of Flow Mechanisms in Shale Using CT Imaging and Data Analysis
Impact of CO2 on Hydrocarbon Recovery and Carbonate Mineral Dissolution in Shale
A Systematic Study of Internal Gas Generation in Source Rocks Using Rock Analog Experiments
Numerical Modeling of Fluid-Driven Fracture Network Formation using the Phase-Field Method
In-Situ Porosity Mapping of Rock-based Microfluidic Models by mX-Ray Fluorescence
The Alteration of Diatomite Under Hot Fluids (steam/water) Injection
Continuous Variable Pressure Steam Injection for Enhanced Oil Recovery
Monitoring Thermal Recovery Field Projects Using Satellite Data
Poster Session and Reception, Tresidder West
Gathering, Posters and Breakfast
In_Depth Analysis of the Effect of Nanoparticles on In-Situ Combustion
RTO Experiments at Large Heating Rates and the Effects of Pressure on Oil Kinetics
Data-Driven In-Situ Combustion Simulations
Numerical Simulation of Combustion Tube Experiments
Latest Developments in the Energy-Conserving Streamlines Code Suitable for In-Situ Combustion
Break & Posters
Application Of Evidential Learning in the Polymer Pilot Of The Matzen Field in Austria
Experimental and Theoretical Study of Wettability of Calcite During Low Salinity Water Injection
Pore Network Investigation of Trapped Gas and Foam Generation mechanisms
Microvisual Study of Foam Behavior in Fractures
Monitoring Cryogenic Shale Fracturing Under Trixial Loads Using CT Scanning
Generating Accurate 3D Pore Structures of Shales Using FIB-SEM
Effects of Image Resolution on Porosity and Permeability Calculations
Oil Price Predictions, Open Discussion
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:
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:
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:
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
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:
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: