Mehran Pooladi-Darvish

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.

Predicting PVT data for CO2-brine mixtures for black-oil simulation of CO2 geological storage

Accurate modeling of the storage or sequestration of CO2 injected into subsurface formations requires an accurate fluid model. This can be achieved using compositional reservoir simulations. However, sophisticated equations of state (EOS) approaches used in current compositional simulators are computationally expensive. It is advantageous and possible to use a simple, but accurate fluid model for the very specific case of geological CO2 storage. Using a black-oil simulation approach, the computational burden of flow simulation can be reduced significantly. In this work, an efficient and simple algorithm is developed for converting compositional data from EOS into black-oil PVT data. Our algorithm is capable of predicting CO2‐brine density, solubility, and formation volume factor, which are all necessary for black-oil flow simulations of CO2 storage in geological formations. Numerical simulations for asimple CO2storage case demonstrate that the black-oil simulationruns are atleast fourtimes fasterthan thecompositional oneswithout lossof accuracy. Theaccuracy in prediction of CO2‐brine black-oil PVT properties and higher computational efficiency of the black-oil approach promote application of black-oil simulation for large-scale geological storage of CO2 in saline aquifers.

Comparison of different numerical Laplace inversion methods for engineering applications

Abstract Laplace transform is a powerful method for enabling solving differential equation in engineering and science. Using the Laplace transform for solving differential equations, however, sometimes leads to solutions in the Laplace domain that are not readily invertible to the real domain by analytical means. Numerical inversion methods are then used to convert the obtained solution from the Laplace domain into the real domain. Four inversion methods are evaluated in this paper. Several test functions, which arise in engineering applications, are used to evaluate the inversion methods. We also show that each of the inversion methods is accurate for a particular case. This study shows that among all these methods, the Fourier transform inversion technique is the most powerful but also the most computationally expensive. Stehfest’s method, which is used in many engineering applications is easy to implement and leads to accurate results for many problems including diffusion-dominated ones and solutions that behave like e − t type functions. However, this method fails to predict e t type functions or those with an oscillatory response, such as sine and wave functions.

Analytical solution to evaluate salt precipitation during CO2 injection in saline aquifers

Abstract Carbon dioxide sequestration in deep saline aquifers is a means of reducing anthropogenic atmospheric emissions of CO 2 . Among various mechanisms, CO 2 can be trapped in saline aquifers by dissolution in the formation water. Vaporization of water occurs along with the dissolution of CO 2 . Vaporization can cause salt precipitation, which reduces porosity and impairs permeability of the reservoir in the vicinity of the wellbore, and can lead to reduction in injectivity. The amount of salt precipitation and the region in which it occurs may be important in CO 2 storage operations if salt precipitation significantly reduces injectivity. Here we develop an analytical model, as a simple and efficient tool to predict the amount of salt precipitation over time and space. This model is particularly useful at high injection velocities, when viscous forces dominate. First, we develop a model which treats the vaporization of water and dissolution of CO 2 in radial geometry. Next, the model is used to predict salt precipitation. The combined model is then extended to evaluate the effect of salt precipitation on permeability in terms of a time-dependent skin factor. Finally, the analytical model is corroborated by application to a specific problem with an available numerical solution, where a close agreement between the solutions is observed. We use the results to examine the effect of assumptions and approximations made in the development of the analytical solution. For cases studied, salt saturation was a few percent. The loss in injectivity depends on the degree of reduction of formation permeability with increased salt saturation. For permeability-reduction models considered in this work, the loss in injectivity was not severe. However, one limitation of the model is that it neglects capillary and gravity forces, and these forces might increase salt precipitation at the bottom of formation particularly when injection rate is low.

Simulation of Depressurization for Gas Production From Gas Hydrate Reservoirs

Gas hydrates as a significant resource of natural gas have attracted considerable attention in recent years. However, the severe environmental conditions of gas hydrate reservoirs and the solid form of hydrates require extensive technological development before commercial gas production becomes possible. Numerical studies often give useful information for predicting the potential and technical viability of a recovery process. This paper presents a 2D cylindrical simulator for gas production from hydrate reservoirs. The model includes the equations for gas-water two-phase low, conductive and convective heat transfer, and intrinsic kinetics of hydrate decomposition The simulator is used to model a hydrate reservoir where the hydrate-bearing layer overlies a free gas zone, such as those discovered in the arctic. A well is drilled and completed in the free gas zone. Pressure reduction in the free gas zone leads to the decomposition of the overlying hydrate and subsequent production of the generated gas. In this paper, we study the impact of the overlying hydrate in improving the production performance of the underlying gas reservoir and investigate the effect of various parameters on gas production behaviour. The rate of gas generated and produced. pressure, temperature, and saturation distributions are studied to investigate the sensitivity of results on individual input parameters. The results suggest that the development of gas reset voirs with overlying hydrates can lead to significant production rates and that the top hydrates have a large impact on increasing the reserve and improving the productivity of the underlying gas reservoir.

Modelling of Convective Mixing in CO Storage

Accurate modelling of the fate of injected CO 2 is necessary if geological storage is to be used at a large scale. In one form of geological storage, CO2 is injected into an aquifer that has a sealing caprock, forming a CO2 cap beneath the caprock. The diffusion of CO2 into underlying formation waters increases the density of water near the top of the aquifer, bringing the system to a hydro-dynamically unstable state. Instabilities can arise from the combination of an unstable density profile and inherent perturbations within the system, e.g., formation heterogeneity. If created, this instability causes convective mixing and greatly accelerates the dissolution of CO2 into the aquifer. Accurate estimation of the rate of dissolution is important for risk assessments because the timescale for dissolution is the timescale over which the CO2 has a chance to leak through the caprock or any imperfectly sealed wells. A new 2D numerical model which has been developed to study the diffusive and convective mixing in geological storage of CO2 is described. Effects of different formation parameters are investigated in this paper. Results reveal that there are two different timescales involved. The first timescale is the time to onset the instability and the second one is the time to achieve ultimate dissolution. Depending on system Rayleigh number and the formation heterogeneity, convective mixing can greatly accelerate the dissolution of CO2 in an aquifer. Two field scale problems were studied. In the first, based on the Nisku aquifer, more than 60% of the ultimate dissolution was achieved after 800 years, while the computed timescale for dissolution in the same aquifer in the absence of convection was orders of magnitude larger. In the case of the Glauconitic sandstone aquifer, there was no convective instability. Results suggest that the presence and strength of convective instability should play an important role in choosing aquifers for CO2 storage. risk of leakage of CO2 from a storage formation may need to analyze leakage mechanisms and their likelihood of occurrence during the full-time period over which mobile free-phase CO 2 is expected to remain in the reservoir. Once dissolved, risk assessments may well ignore the leakage pathways resulting from the very slow movement of CO2-saturated brines. An accurate assessment of the timescales for dissolution are therefore of the first order of importance. The CO2 injected into a saline reservoir is typically 40 – 60% less dense than the resident brines (4) . Driven by density contrasts, CO 2 will flow horizontally (in a horizontal aquifer) spreading under the caprock, and flow upwards, potentially leaking through any high permeability zones or artificial penetrations, such as abandoned wells. The free-phase CO2 (usually supercritical fluid) slowly dissolves in the brines. The resulting CO2-rich brines are slightly denser than undersaturated brines, making them negatively buoyant, and thus greatly reducing or eliminating the possibility of leakage. The rate of dissolution depends on the rate at which diffusion or convection brings undersaturated brine in contact with CO2. Convective mixing enhances the dissolution rate as compared to diffusion by distributing the CO2 into the aquifer (5) . Therefore, the role of convective mixing in CO2 sequestration and the timescales involved in the process are important. The dissolution time of the injected CO2 into brine is important because during this time the injected CO2 has a chance to leak into the atmosphere through the caprock and wellbores. Accurate modelling of the convective mixing in heterogeneous porous media plays a central role in predicting the fate of CO2 injected into aquifers. In this paper, geological CO2 storage is modelled by solving the convection-diffusion equation while considering the CO2-brine interface as a boundary condition. Geochemical reactions that can reduce the timescale of sequestration of CO2 are not included, since they generally occur on longer timescales (6) . The paper is organized as follows. First, the mathematical model for simulating density-driven flow through porous media is briefly presented. The model is validated with a benchmark problem for density-driven flow in porous media. Then, the geological CO2 sequestrations both in small and field scale are simulated using the model. Two important timescales, the effect of formation properties, as well as sensitivity to temporal and spatial discretisations, are discussed. Finally, the results are summarized and their relevance to geological storage of CO 2 in aquifers is discussed.

SAGD Operations in the Presence of Overlying Gas Cap and Water Layer—Effect of Shale Layers

The technical and commercial success of SAGD projects over the past decade has opened the door to the development of a large number of bitumen reservoirs in Canada, previously thought uneconomical to produce. Some of these reservoirs have overlying gas caps and/or water zones. Some studies have suggested that gas-cap production might “sterilize” the underlying bitumen. Many such studies however, assumed rather thick continuous pays with high permeability, and considered an infinite gas-cap. In this work, a simulation study was conducted to examine the feasibility of bitumen production from a certain project area in Alberta, using the SAGD process, and to study the effect of production from the gas cap. A decision needed to be made as to whether gas production should be delayed until after bitumen production. The large well spacing did not allow a detailed description of the connectivity of the shale layers. The uncertainty was compounded by the geological setting of the study area, a system of channel sands cut through the original marine sand and shale deposits. Since the actual shale connectivity and thickness was unknown, a methodology was developed to incorporate different geological descriptions using the available core and log data. Five reservoir models were developed. Bitumen recovery, average oil production rate, and cumulative steam-oil ratio (SOR) obtained from thermal simulation were the three main parameters used for evaluation of the attractiveness of bitumen recovery operations. These numbers were compared with some of the corresponding values reported and/or forecast for economically feasible operations such as the UTF and Christina Lake projects. The effect of pressure reduction (caused by gas-cap production) on production rate and SOR was also investigated. The results indicated that for conditions considered in this study the effect of gas production on bitumen recovery was minor, and appeared as a small deceleration of the recovery and a small increase in SOR. PAPER: 2001-178

Type Curves for Dry CBM Reservoirs With Equilibrium Desorption

The purpose of this work is to model the single-phase radial gas flow in coalbed methane including equilibrium sorption phenomena in the coal matrix and Darcy flow in the natural fracture network. Considering a control volume, the gas desorption rate as a function of time and space is incorporated into the radial continuity equation as a source term. Using Langmuir type sorption isotherm, gas desorption rate is determined at any radius of the reservoir. Introducing the definition of pseudo-pressure and pseudo-time, the resulting continuity equation is converted into the linearized diffusivity equation by modification of total gas compressibility. It is shown how the traditional definition of the material balance pseudo-time is modified for dry CBM reservoirs. With the help of these transformations, the traditional (PTA and RTA) type curves can be employed for analysis of production data of dry CBM reservoirs. The model developed here is validated against Fekete’ s numerical CBM simulator over a wide range of reservoir parameters. In addition, one set of field data from Horseshoe Canyon coals of the Western Canadian Sedimentary Basin is analyzed using the solution procedure presented in this paper.

Reservoir engineering to accelerate dissolution of stored CO2 in brines

Publisher Summary Deep aquifers are a particularly important class of geologic storage system because of their ubiquity and large capacity. Two important uncertainties in assessing CO2 storage in aquifers are storage efficiency and security, where efficiency denotes the fraction of total aquifer capacity that can be accessed for storage, and security refers to the possibility that stored CO2 will escape the aquifer system by migrating upwards through natural or artificial weaknesses in the capping formation. It is possible to engineer CO2 storage in aquifers by accelerating the dissolution of CO2 in brines to reduce the long term risk of leakage. Such reservoir engineering includes: optimizing the geometry of injection wells to maximize the rate at which buoyancy-driven flow of CO2 and brines drives dissolution; or use of wells and pumps to transport CO2 or brines within the reservoir to increase contact between CO2 and undersaturated brines accelerating the rate of dissolution and residual gas trapping.

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.