Experimental Approach To Enhanced Coal Bed Methane Using CO2 Sequestration And Validation With Computer Modelling Group

Coalbed methane (CBM) is unconventional natural resources that are deposit in coal. it is a naturally adsorbed to the pore space in the coal matrix which is viewed as triple porosity and can be partially displaced as a result of depletion in reservoir pressure while the remaining recoverable methane-in-place are recovered by injection of fluid with the overall objective to increase recovery. In this study, the experimental analysis will be conducted with the coal core samples collected from different basins and prepared and arranged base on their basin location. This will be followed by saturating each core sample at a time with methane gas, followed by injection of compositions at the upstream end of the core while the corresponding methane displaced from each sample is measured. This process is repeated by varying composition of used for injection and corresponding displacement rate is recorded. The amount that is sequestered into each core sample will be determined by measuring the difference in composition of injected and in the effluent.

The desorption rate of methane from each coal sample as well as sorption rate of the composition relative to time will be measured; confining pressure, production rate, percentage recovery and displacement efficiency from each sample will be observed under the same condition of pressure and temperature. To further validated the experimental results Langmuir isotherm embedded in computer modeling group that is functionally efficient to model the desorption and adsorption of the gas mixture will be used for history matching purpose. Consequently, the expected outcome is to determine the composition of that can optimally displace methane from the coal core samples by overcoming the effect of heterogeneity that always hinders recovery by trapping the methane.

Literature review

In recent time, global-warming of the world is on the increase because greenhouse-gases entrapment in the atmosphere; and is viewed as the most important environmental challenge with harmful consequences that are threatening both human life and other living organisms; hence requires urgent attention to mitigate the rise. Available data suggested that anthropogenic emission of gases as a result of oil and gas exploration and production activities are the major contributors of greenhouse, while the balance is from other sources such as chlorofluorocarbon (CFC) and additional human-related activities.

In order to reduce or eliminate environmental hazards caused by greenhouse gases that are always entrapped in space resulting to intense heating of the earth, there is a need for the sequestration of that is produced during exploration and production of oil and gas for either geological storage, sequestered or injected into a coalbed methane (CH4) reservoir to improve gas-in-place recovery.

Coal seam gas is one of the unconventional resources that are commercially present in coals across the world especially Australia, China, US and other countries in large quantity and primarily produced by dewatering process. To exploit and produce methane from coal; it involves dewatering process to partially reduce the reservoir pressure in order to release adsorbed methane and the process is technically known as the primary recovery mechanism.

In contrast to the conventional resources heterogeneous reservoirs with single porosity network; coal seam is fractured naturally with dual porosity coal matrix (microspores) functions as the main gas storage system whilst the cleat (macrospores) functions as flow path for adsorbed methane to undergo desorption due to reduction in reservoir pressure(depressurisation techniques) by dewatering processes. The associated recovery quantity is about of the gas- in- place. However, the recovery of the remaining gas-in-place that could not be produced due to the limitations of the primary recovery mechanism requires an alternative process that can improve recovery and boost production of this earth resources.

Invariably, injection of flue gases, nitrogen (N2) and carbon dioxide(CO2) as a second gas into coal formation or coal bed methane reservoir maintain the overall reservoir pressure while partially reducing the pressure of the coalbed methane to free(methane) gas. Coal has high affinity for both. Zhu et al. (2002) concluded that CO2 injection can increase recovery by of coal bed methane (CBM) relative to the natural depletion mechanism briefly described the molecular dynamics that takes place within high coal matrix (meso, micro and macro) as an integrated block – like fractured network that functions as a pathway for counter – diffusivity and absorption mechanism of molecules initiated by injected, hence this incoming, flowing and diffusive molecule of is anticipated to activate and displace methane molecules on the coal matrix.

Mukherjee & Misra (2018) suggested that there are various factors that can affect successful CO2 injection such as geological parameters (depth, nature and location of coal seam gas) as well as their interaction with other processes such as desorption and adsorption; matrix and grain compression; swelling and shrinkage of coal resulting in permeability alteration.

Furthermore, permeability reduction occurs at the initial stage due to the induced strain caused by adsorption and increment in injection caused by pushback phenomenon leading to rebound of permeability. It is suggested that the flow of gas during injection including the breakthrough time as well as effluent concentration and recovery is affected by the gas composition.

The study on the composition of injected Nitrogen(N2) and carbon dioxide (CO2) mixture was conducted on the core sample to determine the optimum recovery on methane from coal. However, this study did not consider the effect of continuous increment in the composition of on the displacement of methane in the heterogeneous reservoir under the same temperature and pressure. Furthermore, Wang et al. (2015) evaluated the impact of injector length and quantity of CO2 sequestered with the corresponding volume of methane recovered for isotropic coal with different cleat spacing.

Yi et al. (2006) showed that gas can be recovered from coal particles if additional gas component with larger adsorption capacity is used. He further observed that the high-velocity rate of gas diffusivity made it practically impossible to be measured, hence unavailability data for further study on the consequences of high gas velocity during adsorption and desorption. Kumar et al. and Anggara et al. (2012) concluded in their study that variations in permeability are caused by induced stress as a result of the injection. The study, however, did not explain how variation in the composition can cause induced strain and did not explain the thermal effect on composition variation. They performed a numerical simulation with the Langmuir model for multicomponent gas adsorption and permeability response to gas adsorption and displacement efficiency induced by injection.

This study will focus experimental analysis of how variation in the composition of composition can enhance Methane recovery coal core samples and application of numerical simulation using computer modeling software to validate the experimental results.

Objective of the proposal

This proposal will focus on the experimental analysis of how variation in the composition of composition can enhance Methane recovery from coal core samples and application of numerical simulation using computer modeling software to validate the experimental results.

Hypothesis

To determine optimum composition required to completely displace methane without trapping of methane in core samples caused by heterogeneous effects.

Method of apparatus units

ECBM test is carried out with an apparatus which consists of three (3) main parts, namely:

• The Injection Unit: This unit comprises of a high-pressure Ruska Gas Cylinder which is initially with Injection gas at a recommended pressure; pump will be used to inject water into the gas cylinder from the under point (bottom). The water and gas will be separated by the floating piston in the gas cylinder, which is also equipped with a circular- ring to keep the safety seal intact during the piston movement to avoid leakage.
• The Core – Holder Unit: This unit will positioned horizontally and houses an oven maintained at a constant temperature of about This temperature is approximately the field temperature of coal seam under study. To ensure proper flow within the coal seam samples, a confining or an enclosed pressure is applied to the core.
• The Production Unit: This unit will be made up of or comprises of a regulator called Back Pressure Regulator (BPR) which maintains pre – adsorption pressure; a metre will be used to record total gas flow rate; Gas Chromatograph (GC) used to measure the composition of the produced gas.

A gas sample is collected at atmospheric pressure using a syringe and a vial, and input to Gas Chromatograph. The gas compositions will be determined using a column HP – Plot Q Gas Chromatograph known as Agilent 7890. Its calibrations with pure gases demonstrate different retention time of Methane and Carbon IV Oxide respectively.

Experimental method / procedure

An experimental method similar to that reported by Connell et al. (2011) applied for the ECBM experiments. Connell et al. (2011) used both nitrogen and carbon dioxide as an injection fluid while we will use the only as injection fluid with continuous variation in composition and concentration.

Outlined Procedures: To ensure good results, the outlined experimental procedures include:

1. Locate the coal core sample to be used into the Core – holder unit. Then set and maintain the oven temperature.
2. Remove the residual air from the coal sample for about 12 hours using the vacuum method.
3. Apply the recommended confining pressure on the sleeve that covers the coal sample.
4. Maintain the pore pressure in the core sample, then inject pure Methane and allow gas adsorption to reach equilibrium. Set the pump to inject water into the Ruska gas Cylinder at the same pressure. Measure the volume of water injected and should be approximately equivalent to the amount of Methane adsorbed into the coal sample.
5. Maintain the pore pressure using the BPR and inject pure into the coal samples. The gas in the cylinder is displaced by water injection at a constant rate. Monitor the gas inflow and outflow (with an accuracy of the flow rate). Then measure the effluent gas composition using the GC. Record the injection pressure with a precision of 35 KPa. f. At a steady – state concentration when the outflow concentration and rates are equal to the inflow, hence terminate the experiment.
6. The procedure is repeated for other for other core samples until optimal recovery is reached.
7. The experiment will be controlled by the following parameters such as gas injection rate and downstream or outflow pressure during the flooding of the core samples.

Conclusion

The core samples collected from different basins will be used for the experiments, these samples will be saturated with methane after which the flooding of compositions at the upstream part of the core in the core holder to displace the gas from the cores. The amount of sequestered will be measured. Other time-dependent parameters such as sorption rate, desorption rate as well as the rate of production will all be estimated during the experiment. The experimental results will be correlated using excel workbook. Subsequently, CMG-GEM simulator will be used for the experimental results validation by matching it with simulation data and the expected outcome will be the optimal recovery of coalbed methane with CO2 injection by overcoming heterogeneity effect.