Skip to content

Optimisation of Soaking Time  In Coal Seam Gas Reservoirs

ISMAIL, Harris,  REZA, Norba Ayah Ahmad, YUNAS, Muhamad Farhan

Engineering Honours 2015

Australian School of Petroleum

University of Adelaide


Coal seam gas (CSG) reservoirs have large surface area and unique physical properties that enable them to adsorb gas up to 28 times its own volume. However, CSG reservoirs have low permeability that does not permit the economical production of methane without hydraulic fracturing. If there is no immediate flowback after the stimulation, the fracturing fluid will remain in the reservoir for some period of time. This interval of time is defined as soaking time in this project. Since the flowback behaviour of CSG formation is unpredictable during the soaking period, the consequences on the productivity of the reservoir are unknown. There are also concerns of the migration of the fracture fluids into the adjacent formation above and below the coal formation during the soaking time period. This environmental issue is important to be addressed as the fracture fluid could contaminate the nearest aquifer as CSG reservoirs are located at shallow depth. This project proposes the integration of different models generated by sophisticated reservoir simulators in order to understand the behaviour of the formation.

In this project, the reservoir input data from 3 different CSG wells in the Waukivory field in Gloucester Basin were analysed. The criteria of choosing the best well to be used in our project are based on the availability of standard logs and hydraulic fracturing job report for each fractured coal section in the well. The reservoir model was constructed by integrating two commercial softwares which is GOHFER for the 3D hydraulic fracturing model and ECLIPSE for reservoir simulation. The hydraulic fracturing properties obtained from the 3D hydraulic fracturing job are then used as the input data for the dynamic reservoir simulation model in ECLISPE. Sensitivity analyses are conducted by manipulating different geomechanical properties and overburden stress in neighbouring formation to evaluate the fracture propagation in confined and unconfined environment. Then the flowback performances are analysed by simulating the CSG model under multiple shut in periods after water which represents the fracturing fluid in ECLIPSE are injected.

The results show that different lithological and stress properties surrounding the coal formation determines the degree of confinement of the fracture job. Hence there are high chances that the fracture fluid would leak further into adjacent formation if the fracture job has poor confinement. Therefore immediate flowback is recommended to recover as much fracture fluid as possible. In terms of reservoir simulation, we have found that soaking the fracture fluid inside the formation for a long period of time in both confined and unconfined hydraulic fracture environment have insignificant effect to the flowback performances of the reservoir.

Australian School of Petroleum



T: +61 8 8313 8000
F: +61 8 8313 8030