Luke D. Connell

Non-isothermal flow of carbon dioxide in injection wells during geological storage

Abstract During sequestration, carbon dioxide within injection wells is likely to be in a dense state and therefore its weight within the wellbore will play an important role in determining the bottomhole pressure and thus the injection rate. However, the density could vary significantly along the well in response to the variation in pressure and temperature. A numerical procedure is formulated in this paper to evaluate the flow of carbon dioxide and its mixtures in non-isothermal wells. This procedure solves the coupled heat, mass and momentum equations with the various fluid and thermodynamic properties, including the saturation pressure, of the gas mixture calculated using a real gas equation of state. This treatment is particularly useful when dealing with gas mixtures where experimental data on mixture properties are not available and these must be predicted. To test the developed procedure two wellbore flow problems from the literature, involving geothermal gradients and wellbore phase transitions are considered; production of 97% carbon dioxide and injection of superheated steam. While these are not typical carbon dioxide injection problems they provide field observations of wellbore flow processes which encompass the mechanisms of interest for carbon dioxide injection, such as phase transition, temperature and density variations with depth. These two examples show that the developed procedure can offer accurate predictions. In a third application the role of wellbore hydraulics during a hypothetical carbon dioxide injection application is considered. The results obtained illustrate the potential complexity of carbon dioxide wellbore hydraulics for sequestration applications and the significant role it can play in determining the well bottomhole pressure and thus injection rate.

Laboratory study of gas permeability and cleat compressibility for CBM/ECBM in Chinese coals

Coal permeability is regarded as one of the most critical parameters for the success of coalbed methane recovery. It is also a key parameter for enhanced coalbed methane recovery via CO2 and/or N2 injection. Coal permeability is sensitive to stress and cleat compressibility is often used to describe how sensitive the permeability change to stress change for coal reservoirs. Coalbed methane exploration and production activities and interest of enhanced coalbed methane recovery increased dramatically in China in recent years, however, how permeability and cleat compressibility change with respect to gas species, effective stress and pore pressure have not been well understood for Chinese coals, despite that they are the key parameters for primary and enhanced coalbed methane production. In this work, two dry Chinese bituminous coal samples from Qinshui Basin and Junggar Basin are studied. Four gases, including He, N2, CH4 and CO2 are used to study permeability behaviour with respect to different effective stresses, pore pressures, and temperatures. The effective stress is up to 5 MPa and pore pressure is up to 7 MPa. Permeability measurements are also carried out at highest pore pressures for each adsorbing gas, at three temperatures, 35, 40 and 45°C. The experimental results show that gas species, effective stress and pore pressure all have significant impact on permeability change for both coal samples. Moreover, the results demonstrate that cleat compressibility is strongly dependent on effective stress. More importantly, the results show that cleat compressibility is also strongly dependent on pore pressure. Cleat compressibility initially decreases with pore pressure increase then it increases slightly at higher pore pressures. However, temperature only has marginal impact on permeability and cleat compressibility change.

Effects of pressure and temperature on gas diffusion and flow for primary and enhanced coalbed methane recovery

Due to the rapid increase of coalbed methane (CBM) exploration and development activities in China, gas adsorption and flow behavior for Chinese coals are of great interest for the industry and research community. How pressure and temperature affect the gas adsorption and flow on different rank coals are not only important for CBM recovery but also important for CO2 or N2 enhanced CBM recovery, since gases are often injected at a temperature different to the reservoir temperature. In this work, gas adsorption and permeability of three different rank Chinese coals are measured using CH4, N2 and CO2 at three temperatures, 20°C, 35°C and 50°C. Gas diffusivity and permeability with respect to gas species, pore pressure, effective stress and temperature are studied. The three coals are SQB-1 from Southern Qinshui Basin, JB-1 from Junggar Basin and OB-1 from Ordos Basin. Gas adsorption results show that both pressure and temperature have significant impact on adsorption behavior for SQB-1 and JB-1 using CH4. For higher rank coal SQB-1, adsorption isotherm tends to reach adsorption capacity quicker with respect to pressure. However, the maximum adsorption capacity is higher for the lower rank coal JB-1. Moreover, temperature has a stronger effect on reducing adsorption capacity for lower rank coal. Gas diffusivity results for OB-1 and JB-1 show that CO2 diffusivity is generally higher than that of CH4 and then N2. This could be related with their different kinetic diameters and their interaction with the coal. Both pressure and temperature have impact on gas diffusivity. In general, gas diffusivities increase with pressure and temperature. Permeability results show that it varies greatly with respect to coal rank with highest rank coal having the lowest permeability. Permeability is also strongly sensitive to effective stress and pore pressure. Temperature has a noticeable impact on permeability change. Permeability changes differently with temperature increase for the different rank coal samples studied. This may be attributed to the combined effect of coal strain change due to gas adsorption and thermal expansion. These results have significant implications for the design of enhanced CBM recovery and CO2 storage for different rank coals as injecting gas at different temperature and pressure would affect the CO2 injectivity and the CBM production rate.

Laboratory and modeling study on gas diffusion with pore structures in different-rank Chinese coals

The coalbed methane production rate is mainly controlled by two parameters: diffusivity in the coal matrix and permeability in the cleat system. As one key parameter, diffusion plays an important role in coalbed methane producing process. However, till now there is no systematic study on the relationship of diffusivity, pore size and coal ranks. In this work, three Chinese coal samples which belong to low, middle and high rank, respectively, were studied using experimental and modeling methods. Four gases, H2, N2, CH4 and CO2, are used to study the diffuse characters at four different pressures steps. The experimental results showed that the adsorption balance time varies with different testing gas type and it is closely related with coal rank. Balance time testing with CO2 is the longest, and then is CH4, while He is the slowest. Moreover, high rank coal takes the longest time to reach balance, while low rank coal takes the least. Generally, the sorption balance time for JCC-01 is about 150–350 S 0.5, it is about 250–400 S 0.5 for CZ-1, while it is about 900–1200 S 0.5 for JCC-01. Modeling results showed that for all these three ranked Chinese coals, the bidisperse model can be used to model the diffuse process. The β value, which is the ratio of macropore adsorption/desorption to the total adsorption/desorption, increases with the increasing of pore pressure, except for sample JCC-01 when measured using CO2. There is no regular law for both micropore and macropore diffusion coefficient. In order to study the relationship of diffusivity, pore structure and coal ranks, the experiments of mercury injection test and low-temperature liquid nitrogen experiment were done to analyse the relationship. The results show that, for the low rank coal sample TCG-1, the mesopore takes the majority while the macropore also takes part of the pore distribution, there are few even no micropore. For middle rank sample CZ-1, the mesopore also takes the majority and the macorpore accounts for a small percentage. While for high rank coal sample JCC-01, micropore takes the majority, and mesopore and macropore take small part of the pore structure distribution. The conclusion drawn from these testing results can be used to explain the adsorption and diffusion laws found before.

Impact of thermal processes on CO2 injectivity into a coal seam

The objective of this study is to investigate how thermal gradients, caused by CO2 injection, expansion and adsorption, affect the permeability and adsorption capacity of coal during CO2 sequestration. A new permeability model is developed in which the concept of elastic modulus reduction ratio is introduced to partition the effective strain between coal matrix and fracture. This model is implemented into a fully coupled mechanical deformation, gas flow and heat transport finite element simulator. To predict the amount of CO2 sequested, the extended Langmuir sorption model is used, with parameters values taken from the literature. The coupled heat and gas flow equations, are solved in COMSOL using the finite element method. The simulation results for a constant volume reservoir demostrate that thermal strain acts to significantly reduce both CO2 injectivity and adsorption capacity. These impacts need to be considered in the calculation of the optimum injection rate and the total sequestration capacity.

CO2 storage in coal to enhance coalbed methane recovery: a review of field experiments in China

ABSTRACT Coal reservoirs especially deep unminable coal reservoirs, are viable geological target formations for CO2 storage to mitigate greenhouse gas emissions. An advantage of this process is that a large amount of CO2 can be stored at relatively low pressure, thereby reducing the cost of pumping and injection. Other advantages include the use of existing well infrastructure for CO2 injection and to undertake enhanced recovery of coalbed methane (ECBM), both of which partially offset storage costs. However, ECBM faces difficulties such as low initial injectivity and further permeability loss during injection. Although expensive to perform, ECBM field experiments are essential to bridge laboratory study and large-scale implementation. China is one of the few countries that have performed ECBM field experiments, testing a variety of different geological conditions and injection technologies. These projects began more than a decade ago and have provided valuable experience and knowledge. In this article, we review past and current CO2 ECBM field trials in China and compare with others performed around the world to benefit ECBM research and inform future projects. Key aspects of the ECBM field projects reviewed include the main properties of target coal seams, well technologies, injection programmes, monitoring techniques and key findings.

Measurement of shale anisotropic permeability and its impact on shale gas production

Gas shales act as both the source rock and reservoir for the petroleum. One of the important characteristics of the reservoir is its low permeability, making gas production difficult. Although economic shale gas production has been achieved through horizontal drilling and multistage hydraulic fracturing, shale reservoir permeability is still one of the critical parameters in the evaluation of a shale gas play. In the present work, experimental measurement of shale anisotropic permeability is determined using a cubic shale sample in a triaxial cell. Anisotropic permeability was measured at a series of gas pressures and confining pressures. A permeability model incorporating stress and Klinkenberg effect was applied to describe the data. The model was applied in the reservoir simulator SIMED IITM to investigate the impact of anisotropic permeability and its change on shale gas production. Results are compared between using the vertical permeability, horizontal permeability, or anisotropic permeability as the reservoir permeability. The results show that using vertical permeability will significantly underestimate the gas production rate. This demonstrates that measuring directional permeability and using the most appropriate one is important for evaluating shale gas production and development of shale gas assets.

A Multi-Component Dual-Porosity Model for Gas Reservoir Flow With Adsorption Behaviour

This study presents a modified dual-porosity model for multispecies gas flow with adsorption behaviour, which is formulated from an exact formal solution of a linear multicomponent gas diffusion process within a porous matrix block. Therefore, the coupling effects of mutual-diffusion are included in the representation. This new respresentation, in its first order form, exhibits to be a simple algebraic expression that is of an equivalent computational efficiency in comparison with the traditional Warren and Root. Yet, the mutual-diffusion effect is not present in the latter one. A numerical algorithm is also developed for this model when the full form of it, which is of an integral form with history-dependency, is incorporated into a set of multi-phase and multi-species flow equations. A numerical example with the proposed model for a two-phase and three gas-species flow is performed in light of a parametric study, demonstrating that multi-component gas species interactions have significant influences on the flow profile. For instance, even if the offdiagonal diffusion coefficients are smaller by one order of magnitude in comparison to their diagonal counterparts, the resultant effect on model predictions can still be 10~35%. Ignoring the diffusional interactions between the gas species, as is done with the Warren-Root, will introduce considerable deviations. Introduction Gas flow in certain types of geological formations, such as coal or naturally fractured porous media, may involve two physically different migration processes; one is related to larger scale distributed networks of natural fractures, and the other one is associated with the much finer porous structures of local matrix blocks between the fractures (Kolesar and Ertekin, Shi and Durucan). It is normally believed or, more exactly, assumed that the movement of a gas through the larger scale fractures is a permeability flow which can be described by the Darcy law and mainly driven by pressure gradients. While that of the gas inside the matrix blocks are diffusion processes which may involve several different mechanisms, subject to the pore size (Shi and Durucan, Gray). For these diffusion processes, the concentration gradient is the primary driving force. In addition, in some geological materials, particularly in coal, the gas within the matrix may be stored as an adsorbed phase where the adsorption process can also play an important role. To deal with a flow problem in such porous media which have two greatly different spatial scales, dual-porosity models (also called matrix-fracture transfer functions) have been developed following the concept proposed by Barenblatt and Zheltov (Warren and Root, De Swann, Najuriteta, Dykhuizen, Zimmerman and Bodvarson, Zimmerma, et al, Lim and Aziz, Civan and Rasmussen, Babadagli, and Zeidain, Rasmussen and Civan, Civan and Rasmussen, etc.). Of these the Warren-Root model is a popular approach and is incorporated into a variety of commercial gas-reservoir simulation codes. However, while single component flow models in dual porosity media have received considerable attentions, studies on multi-component dual-porosity models have been much more limited, even though this problem is relevant to a wide range of problems of interest. For example, one area of interest is coal bed methane and CO2 sequestration in coal, where multi-component gas migration within the dual porosity coal structure is central to interpreting the reservoir behaviour. Actually, a common approach for explaining such flow profiles in dual porosity formations in reservoir simulators (e.g. Stevenson and Pinczewski) often utilizes an immediate extension of the Warren-Root model combining a pseudo steady-state assumption of adsorption behavior on the surfaces of the matrix blocks (Kolesar 18, , et al, King, et al). With this approach, the Warren and Root model is applied to each individual component. For each component representation, an independent constant, called characteristic “adsorption time” or “diffusion time”, is introduced, which accommodates matrix geometry and diffusion characteristics. However, this treatment is mathematically equivalent to considering the selfdiffusion process of each component in the porous medium merely, while the interactions between gases are omitted. Theoretically, these interactions (Allen, et al, Cussler, and Bear).can however have significant impacts to flow.

A Note on the Characteristic Length/Time of Dual-Porosity Models for Geologically Fractured Media

This short note presents a discussion on the characteristic length that appears in dualporosity models for fractured geological media, via which the empirical characteristic diffusion time is defined. The physical meaning of it is further interpreted here from a more rigorous mathematical point of view, relating the so-called characteristic length or, equivalently, the characteristic time, to a statistically averaged quantity over a local representative volume element that contains numerous matrix blocks. Each of these matrix blocks will be of distinct characteristic lengths or times unless the geometrical shapes and sizes (in an effectively volume-equivalent way) of them are identical. Theoretically, those characteristic lengths could be statistically determined through measurement of their typical distributions. Thus, the discussion presented in this article may permit one to have greater insight into the nature of these two parameters, and may also allow a laboratory approach to measure them to be developed.

Predictions of fracture growth in Walloon coals using a layer fracture model

Individual low-permeability Walloon coal seams are separated by the stiffer beds of carbonaceous shales, mudstone, siltstone and sandstone in the Surat basin. Considering the thin nature of Walloon coals, the fracture growth across the stiffer beds becomes a key issue in assessing the fracture treatment efficiency and in determining the impacts of fracture stimulation on groundwater resources. A hydraulic fracture model considering the elastic property difference across layers is developed to obtain the fracture growth behaviours in a multiple layer formation. A case study was performed where the in situ stress across beds is of similar magnitudes to highlight the effect of property difference. The fracture initiates at the targeted lower coal seam and the complex footprints generated by fracture growth are obtained. In contrast to the assumed constant fracture height and the large fracture height to length ratio obtained by other layer models, the vertical fracture growth is limited in the propagation speed by the alternating stiff and compliant rocks. The alternating growth in lateral and vertical directions results in an oscillating pressure, which is an indicative for fracture height growth.