Michael B. Kowalsky

TOUGH+Hydrate v1.0 User's Manual: A Code for the Simulation of System Behavior in Hydrate-Bearing Geologic Media

TOUGH+HYDRATE v1.0 is a new code for the simulation of the behavior of hydrate-bearing geologic systems. By solving the coupled equations of mass and heat balance, TOUGH+HYDRATE can model the non-isothermal gas release, phase behavior and flow of fluids and heat under conditions typical of common natural CH{sub 4}-hydrate deposits (i.e., in the permafrost and in deep ocean sediments) in complex geological media at any scale (from laboratory to reservoir) at which Darcys law is valid. TOUGH+HYDRATE v1.0 includes both an equilibrium and a kinetic model of hydrate formation and dissociation. The model accounts for heat and up to four mass components, i.e., water, CH{sub 4}, hydrate, and water-soluble inhibitors such as salts or alcohols. These are partitioned among four possible phases (gas phase, liquid phase, ice phase and hydrate phase). Hydrate dissociation or formation, phase changes and the corresponding thermal effects are fully described, as are the effects of inhibitors. The model can describe all possible hydrate dissociation mechanisms, i.e., depressurization, thermal stimulation, salting-out effects and inhibitor-induced effects. TOUGH+HYDRATE is the first member of TOUGH+, the successor to the TOUGH2 [Pruess et al., 1991] family of codes for multi-component, multiphase fluid and heat flow developed at the Lawrence Berkeley National Laboratory. It is written in standard FORTRAN 95, and can be run on any computational platform (workstation, PC, Macintosh) for which such compilers are available.

Effects of physical and geochemical heterogeneities on mineral transformation and biomass accumulation during biostimulation experiments at Rifle, Colorado

Electron donor amendment for bioremediation often results in precipitation of secondary minerals and the growth of biomass, both of which can potentially change flow paths and the efficacy of bioremediation. Quantitative estimation of precipitate and biomass distribution has remained challenging, partly due to the intrinsic heterogeneities of natural porous media and the scarcity of field data. In this work, we examine the effects of physical and geochemical heterogeneities on the spatial distributions of mineral precipitates and biomass accumulated during a biostimulation field experiment near Rifle, Colorado. Field bromide breakthrough data were used to infer a heterogeneous distribution of hydraulic conductivity through inverse transport modeling, while the solid phase Fe(III) content was determined by assuming a negative correlation with hydraulic conductivity. Validated by field aqueous geochemical data, reactive transport modeling was used to explicitly keep track of the growth of the biomass and to estimate the spatial distribution of precipitates and biomass. The results show that the maximum mineral precipitation and biomass accumulation occurs in the vicinity of the injection wells, occupying up to 5.4vol.% of the pore space, and is dominated by reaction products of sulfate reduction. Accumulation near the injection wells is not strongly affected by heterogeneities present in the system due to the ubiquitous presence of sulfate in the groundwater. However, accumulation in the down-gradient regions is dominated by the iron-reducing reaction products, whose spatial patterns are strongly controlled by both physical and geochemical heterogeneities. Heterogeneities can lead to localized large accumulation of mineral precipitates and biomass, increasing the possibility of pore clogging. Although ignoring the heterogeneities of the system can lead to adequate prediction of the average behavior of sulfate-reducing related products, it can also lead to an overestimation of the overall accumulation of iron-reducing bacteria, as well as the rate and extent of iron reduction. Surprisingly, the model predicts that the total amount of uranium being reduced in the heterogeneous 2D system was similar to that in the 1D homogeneous system, suggesting that the overall uranium bioremediation efficacy may not be significantly affected by the heterogeneities of Fe(III) content in the down-gradient regions. Rather, the characteristics close to the vicinity of the injection wells might be crucial in determining the overall efficacy of uranium bioremediation. These findings have important implications not only for uranium bioremediation at the Rifle site and for bioremediation of other redox sensitive contaminants at sites with similar characteristics, but also for the development of optimal amendment delivery strategies in other settings.

Challenges, Uncertainties, and Issues Facing Gas Production From Gas-Hydrate Deposits

Challenges, Uncertainties and Issues Facing Gas Production From Gas Hydrate Deposits G.J. Moridis, SPE, Lawrence Berkeley National Laboratory; T.S. Collett, SPE, US Geological Survey; M. Pooladi- Darvish, SPE, University of Calgary and Fekete; S. Hancock, SPE, RPS Group; C. Santamarina, Georgia Institute of Technology; R. Boswell, US Department of Energy; T. Kneafsey, J. Rutqvist and M. B. Kowalsky, Lawrence Berkeley National Laboratory; M.T. Reagan, SPE, Lawrence Berkeley National Laboratory; E.D. Sloan, SPE, Colorado School of Mines; A.K. Sum and C. A. Koh, Colorado School of Mines Abstract The current paper complements the Moridis et al. (2009) review of the status of the effort toward commercial gas production from hydrates. We aim to describe the concept of the gas hydrate petroleum system, to discuss advances, requirement and suggested practices in gas hydrate (GH) prospecting and GH deposit characterization, and to review the associated technical, economic and environmental challenges and uncertainties, including: the accurate assessment of producible fractions of the GH resource, the development of methodologies for identifying suitable production targets, the sampling of hydrate-bearing sediments and sample analysis, the analysis and interpretation of geophysical surveys of GH reservoirs, well testing methods and interpretation of the results, geomechanical and reservoir/well stability concerns, well design, operation and installation, field operations and extending production beyond sand-dominated GH reservoirs, monitoring production and geomechanical stability, laboratory investigations, fundamental knowledge of hydrate behavior, the economics of commercial gas production from hydrates, and the associated environmental concerns. Introduction Background. Gas hydrates (GH) are solid crystalline compounds of water and gaseous substances described by the general chemical formula G•N H H 2 O, in which the molecules of gas G (referred to as guests) occupy voids within the lattices of ice- like crystal structures. Gas hydrate deposits occur in two distinctly different geographic settings where the necessary conditions of low temperature T and high pressure P exist for their formation and stability: in the Arctic (typically in association with permafrost) and in deep ocean sediments (Kvenvolden, 1988). The majority of naturally occurring hydrocarbon gas hydrates contain CH 4 in overwhelming abundance. Simple CH 4 - hydrates concentrate methane volumetrically by a factor of ~164 when compared to standard P and T conditions (STP). Natural CH 4 -hydrates crystallize mostly in the structure I form, which has a hydration number N H ranging from 5.77 to 7.4, with N H = 6 being the average hydration number and N H = 5.75 corresponding to complete hydration (Sloan and Koh, 2008). Natural GH can also contain other hydrocarbons (alkanes C  H 2+2 ,  = 2 to 4), but may also contain trace amounts of other gases (mainly CO 2 , H 2 S or N 2 ). Although there has been no systematic effort to map and evaluate this resource on a global scale, and current estimates of in-place volumes vary widely (ranging between 10 15 to 10 18 m 3 at standard conditions), the consensus is that the worldwide quantity of hydrocarbon within GH is vast (Milkov, 2004; Boswell and Collett, 2010). Given the sheer magnitude of the resource, ever increasing global energy demand, and the finite volume of conventional fossil fuel resources, GH are emerging as a potential energy source for a growing number of nations. The attractiveness of GH is further enhanced by the environmental desirability of natural gas, as it has the lowest carbon intensity of all fossil fuels. Thus, the appeal of GH accumulations as future hydrocarbon gas sources is rapidly increasing and their production potential clearly demands technical and economic evaluation. The past decade has seen a marked acceleration in gas hydrate R&D, including both a proliferation of basic scientific endeavors as well as the strong emergence of focused field studies of GH occurrence and resource potential, primarily within national GH programs (Paul et al., 2010). Together, these efforts have helped to clarify the dominant issues and challenges facing the extraction of methane from gas hydrates. A review paper by Moridis et al. (2009) summarized the status of the effort for production from gas hydrates. The authors discussed the distribution of natural gas hydrate accumulations, the status of the primary international research and development R&D programs (including current policies, focus and priorities), and the remaining science and technological challenges facing commercialization of production. After a brief examination of GH accumulations that are well characterized and appear to be models for future development and gas production, they analyzed the role of numerical simulation in the assessment of the hydrate production potential, identified the data needs for reliable predictions, evaluated the status of knowledge with regard to these needs, discussed knowledge gaps and their impact, and reached the conclusion that the numerical simulation capabilities are quite advanced and that the related gaps are either not significant or are being addressed. Furthermore, Moridis et al. (2009) reviewed the current body of literature relevant to potential productivity from different types of GH deposits, and determined that there are consistent indications of a large production potential at high rates over long periods from a wide variety of GH deposits. Finally, they identified (a) features, conditions, geology and techniques that are desirable in the selection of potential production targets, (b) methods to maximize production, and (c) some of the conditions and characteristics that render certain GH deposits undesirable for production.

Physicochemical Heterogeneity Controls on Uranium Bioreduction Rates at the Field Scale

It has been demonstrated in laboratory systems that U(VI) can be reduced to immobile U(IV) by bacteria in natural environments. The ultimate efficacy of bioreduction at the field scale, however, is often challenging to quantify and depends on site characteristics. In this work, uranium bioreduction rates at the field scale are quantified, for the first time, using an integrated approach. The approach combines field data, inverse and forward hydrological and reactive transport modeling, and quantification of reduction rates at different spatial scales. The approach is used to explore the impact of local scale (tens of centimeters) parameters and processes on field scale (tens of meters) system responses to biostimulation treatments and the controls of physicochemical heterogeneity on bioreduction rates. Using the biostimulation experiments at the Department of Energy Old Rifle site, our results show that the spatial distribution of hydraulic conductivity and solid phase mineral (Fe(III)) play a critical role in determining the field-scale bioreduction rates. Due to the dependence on Fe-reducing bacteria, field-scale U(VI) bioreduction rates were found to be largely controlled by the abundance of Fe(III) minerals at the vicinity of the injection wells and by the presence of preferential flow paths connecting injection wells to down gradient Fe(III) abundant areas.

Hydrogeophysical parameter estimation approaches for field scale characterization

Radio magnetotellurics (RMT), crosshole ground penetrating radar (GPR), and crosshole electrical resistance tomography (ERT) were applied in a range of hydrogeological applications where geophysical data could improve hydrogeological characterization. A profile of RMT data collected over highly resistive granite was used to map subhorizontal fracture zones below 300m depth, as well as a steeply dipping fracture zone, which was also observed on a coinciding seismic reflection profile. One-dimensional inverse modelling and 3D forward modelling with displacement currents included were necessary to test the reliability of features found in the 2D models, where the forward models did not include displacement currents and only lower frequencies were considered. An inversion code for RMT data was developed and applied to RMT data with azimuthal electrical anisotropy signature collected over a limestone formation. The results indicated that RMT is a faster and more reliable technique for studying electrical anisotropy than are azimuthal resistivity surveys. A new sequential inversion method to estimate hydraulic conductivity fields using crosshole GPR and tracer test data was applied to 2D synthetic examples. Given careful surveying, the results indicated that regularization of hydrogeological inverse problems using geophysical tomograms might improve models of hydraulic conductivity. A method to regularize geophysical inverse problems using geostatistical models was developed and applied to crosshole ERT and GPR data collected in unsaturated sandstone. The resulting models were geologically more reasonable than models where the regularization was based on traditional smoothness constraints. Electromagnetic geophysical techniques provide an inexpensive data source in estimating qualitative hydrogeological models, but hydrogeological data must be incorporated to make quantitative estimation of hydrogeological systems feasible.

A truncated Levenberg-Marquardt algorithm for the calibration of highly parameterized nonlinear models

We propose a modification to the Levenberg-Marquardt minimization algorithm for a more robust and more efficient calibration of highly parameterized, strongly nonlinear models of multiphase flow through porous media. The new method combines the advantages of truncated singular value decomposition with those of the classical Levenberg-Marquardt algorithm, thus enabling a more robust solution of underdetermined inverse problems with complex relations between the parameters to be estimated and the observable state variables used for calibration. The truncation limit separating the solution space from the calibration null space is re-evaluated during the iterative calibration process. In between these re-evaluations, fewer forward simulations are required, compared to the standard approach, to calculate the approximate sensitivity matrix. Truncated singular values are used to calculate the Levenberg-Marquardt parameter updates, ensuring that safe small steps along the steepest-descent direction are taken for highly correlated parameters of low sensitivity, whereas efficient quasi-Gauss-Newton steps are taken for independent parameters with high impact. The performance of the proposed scheme is demonstrated for a synthetic data set representing infiltration into a partially saturated, heterogeneous soil, where hydrogeological, petrophysical, and geostatistical parameters are estimated based on the joint inversion of hydrological and geophysical data.

Long-term electrical resistivity monitoring of recharge-induced contaminant plume behavior.

Geophysical measurements, and electrical resistivity tomography (ERT) data in particular, are sensitive to properties that are related (directly or indirectly) to hydrological processes. The challenge is in extracting information from geophysical data at a relevant scale that can be used to gain insight about subsurface behavior and to parameterize or validate flow and transport models. Here, we consider the use of ERT data for examining the impact of recharge on subsurface contamination at the S-3 ponds of the Oak Ridge Integrated Field Research Challenge (IFRC) site in Tennessee. A large dataset of time-lapse cross-well and surface ERT data, collected at the site over a period of 12 months, is used to study time variations in resistivity due to changes in total dissolved solids (primarily nitrate). The electrical resistivity distributions recovered from cross-well and surface ERT data agrees well, and both of these datasets can be used to interpret spatiotemporal variations in subsurface nitrate concentrations due to rainfall, although the sensitivity of the electrical resistivity response to dilution varies with nitrate concentration. Using the time-lapse surface ERT data interpreted in terms of nitrate concentrations, we find that the subsurface nitrate concentration at this site varies as a function of spatial position, episodic heavy rainstorms (versus seasonal and annual fluctuations), and antecedent rainfall history. These results suggest that the surface ERT monitoring approach is potentially useful for examining subsurface plume responses to recharge over field-relevant scales.

Gas Hydrates as a Potential Energy Source: State of Knowledge and Challenges

Gas hydrates are a vast energy resource with global distribution in the permafrost and in the oceans, and its sheer size demands evaluation as a potential energy source. Here we discuss the distribution of natural gas hydrate (GH) accumulations, the status of the international R&D programs. We review well-characterized GH accumulations that appear to be models for future gas production, and we analyze the role of numerical simulation in the assessment of their production potential. We discuss the productivity from different GH types, and consistent indications of the possibility for production at high rates over long periods using conventional technologies. We identify (a) features, conditions, geology, and techniques that are desirable in production targets, (b) methods to maximize production, and (c) some of the conditions and characteristics that render GH deposits undesirable. Finally, we review the remaining technical, economic, and environmental challenges and uncertainties facing gas production from hydrates.

The effect of reservoir heterogeneity on gas production from hydrate accumulations in the permafrost

The Effect of Reservoir Heterogeneity on Gas Production from Hydrate Accumulations in the Permafrost Matthew T. Reagan 1 , SPE, Michael B. Kowalsky 1 , George J. Moridis 1 , SPE, and Suntichai Silpngarmlert 2 , SPE Lawrence Berkeley National Laboratory, 1 Cyclotron Rd., Berkeley, CA 94720 ConocoPhillips, 600 North Dairy Ashford, Houston, TX 77252 Abstract The quantity of hydrocarbon gases trapped in natural hydrate accumulations is enormous, leading to significant interest in the evaluation of their potential as an energy source. Large volumes of gas can be readily produced at high rates for long times from methane hydrate accumulations in the permafrost by means of depressurization-induced dissociation combined with conventional technologies and horizontal or vertical well configurations. Initial studies on the possibility of natural gas production from permafrost hydrates assumed homogeneity in intrinsic reservoir properties and in the initial condition of the hydrate-bearing layers (either due to the coarseness of the model or due to simplifications in the definition of the system). These results showed great promise for gas recovery from Class 1, 2, and 3 systems in the permafrost. This work examines the consequences of inevitable heterogeneity in intrinsic properties, such as in the porosity of the hydrate-bearing formation, or heterogeneity in the initial state of hydrate saturation. Heterogeneous configurations are generated through multiple methods: 1) through defining heterogeneous layers via existing well-log data, 2) through randomized initialization of reservoir properties and initial conditions, and 3) through the use of geostatistical methods to create heterogeneous fields that extrapolate from the limited data available from cores and well-log data. These extrapolations use available information and established geophysical methods to capture a range of deposit properties and hydrate configurations. The results show that some forms of heterogeneity, such as horizontal stratification, can assist in production of hydrate-derived gas. However, more heterogeneous structures can lead to complex physical behavior within the deposit and near the wellbore that may obstruct the flow of fluids to the well, necessitating revised production strategies. The need for fine discretization is crucial in all cases to capture dynamic behavior during production. Introduction Objective. This investigation is part of an effort led by the U.S. Department of Energy to identify appropriate targets for a long-term field test of production from permafrost-associated hydrate deposits (Boswell et al, 2008). The main objective of this study is to determine through sensitivity analysis the possible effects of deposit heterogeneity on productivity, and assess the production strategies required to achieve economically viable production. Background. Gas hydrates are solid crystalline compounds in which gas molecules (referred to as guests) occupy the lattices of host ice crystal structures. Their formation and dissociation is described by the general equation: G + N H H 2 O = G•N H H 2 O, where N H is the hydration number, and G is a hydrate-forming gas. Natural hydrates in geological systems contain G = CH 4 as their main gas ingredient, and occur in two distinctly different geologic settings where the necessary conditions of low T and high P exist for their formation and stability: in the permafrost and in deep ocean sediments. The quantity of CH 4 contained hydrates is the subject of continuing debate, and estimates vary widely between 10 15 and 10 18 ST m 3 (Sloan and Koh, 2008; Milkov, 2004; Klauda and Sandler, 2005). The general consensus is that this quantity is huge, easily exceeding the total energy content of the known conventional fossil fuel resources. Even if only a fraction of the most conservative estimate of the resource is recoverable, the quantities involved are large enough motivate further evaluation of hydrates as an energy source (Makogon, 1987; Dallimore et al., 1999; 2005). As result, many studies have evaluated the technical and economic feasibility of gas production from natural hydrate accumulations (Moridis, 2003; Sun and Mohanty, 2005; Moridis and Sloan, 2007; Moridis and Reagan, 2007a;b;c; Kurihara et al., 2009; Moridis et al., 2009). Gas can be produced from hydrates by inducing dissociation using any of the three main dissociation methods (Makogon, 1997): (1) depressurization below the hydration pressure P e at the temperature T, (2) thermal stimulation, based on raising T above the hydration temperature T e at the prevailing pressure P, and (3) the use of inhibitors (such as salts and alcohols) that shift the P e -T e equilibrium. However, multiple studies (Moridis and Reagan, 2007a;b; Reagan et al., 2008) have demonstrated the depressurization is typically the most effective, efficient, and economically viable method to dissociate hydrates in situ and enable production of hydrate-derived methane. Thermal stimulation is reserved for localized control of secondary hydrate or ice formation, or for the initial dissociation of hydrate around the well production interval (Moridis and Reagan, 2007b), as

Feasibility of Monitoring Gas-Hydrate Production With Time-Lapse Vertical Seismic Profiling

Summary Many studies involving the application of geophysical methods in the field of gas hydrates have focused on determining rock-physics relationships for hydrate-bearing sediments, with the goal being to delineate the boundaries of gas-hydrate accumulations and to estimate the quantities of gas hydrate that such accumulations contain using remote-sensing techniques. However, the potential for using time-lapse geophysical methods to monitor the evolution of hydrate accumulations during production and, thus, to manage production has not been investigated. In this work, we begin to examine the feasibility of using time-lapse seismic methods—specifically, the vertical-seismic-profiling (VSP) method—for monitoring changes in hydrate accumulations that are predicted to occur during production of natural gas. A feasibility study of this nature is made possible through the coupled simulation of large-scale production in hydrate accumulations and time-lapse geophysical (seismic) surveys. We consider a hydrate accumulation in the Gulf of Mexico that may represent a promising target for production. Although the current study focuses on one seismic method (VSP), this approach can be extended easily to other geophysical methods, including other seismic methods (e.g., surface seismic or crosshole measurements) and electromagnetic surveys. In addition to examining the sensitivity of seismic attributes and parameters to the changing conditions in hydrate accumulations, our long-term goals in this work are to determine optimal sampling strategies (e.g., source frequency, time interval for data acquisition) and measurement configurations (e.g., source and receiver spacing for VSP), while taking into account uncertainties in rock-physics relationships. The numerical-modeling strategy demonstrated in this study may be used in the future to help design cost-effective geophysical surveys to track the evolution of hydrate properties. Here, we describe the modeling procedure and present some preliminary results.