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Type: Thesis
Title: Controls on Gas Production from Permian Ultra-deep Coal Seams of the Cooper Basin: Expanding Reservoir Boundary Theory
Author: Dunlop, Erik Christopher
Issue Date: 2019
School/Discipline: Australian School of Petroleum
Abstract: This thesis reveals atypical dynamic reservoir behaviour within Cooper Basin ultra-deep coal seams during gas production that calls for a paradigm shift in gas extraction technology, diametrically opposed to the evolutionary path of current drilling, wellbore completion, and reservoir stimulation practices. An anomalous geomechanical reservoir boundary condition is detected that is, by definition, mostly restricted to ultra-deep coal seams. The discovery has resulted in the formulation of a new coal seam reservoir concept - “Expanding Reservoir Boundary Theory”. Ultra-deep Permian coal seams of the Cooper Basin in central Australia represent a nascent thermogenic source rock reservoir play. Proof-of-concept gas flow occurred in 2007. The vast (100+ Tscf) potential resource is comparable in commercial significance, and technical challenge, to the shale gas plays of North America. As with shale, full-cycle, standalone commercial gas production from Cooper Basin ultra-deep coal seams requires a large, complex, permeable “stimulated reservoir volume” (SRV) domain having high fracture / fabric face surface area for gas desorption. This goal has not yet been achieved after 13 years of trials because, owing to the bipolar combination of coal-like geomechanical properties and shale-like reservoir properties, these poorly cleated, inertinitic coal seams exhibit “hybrid” characteristics. This is problematic for achieving effective reservoir stimulation, and poses the greatest immediate challenge. Stimulation techniques adopted from other play types are incompatible with the highly unfavourable combination of nanoDarcy-scale permeability, “ductility”, and high stress. The Cooper Basin Deep Coal Gas (CBDCG) Play commences 6,000 feet (1,830 metres) below the “commercial permeability depth limit” for most shallow coal seam gas (CSG) reservoirs but this does not reduce gas flow potential. Shale gas industry technologies have, in principle, eliminated the requirement for naturally occurring coal fabric permeability. Optimum reservoir conditions occur at depths beyond 9,000 feet (2,740 metres), driven by very low water saturation, high gas content, gas oversaturation, overpressure, rigid host rock strata, and high deviatoric stress. The limited literature does not yet adequately characterise the physical response of ultra-deep coal seams, and the surrounding host rock strata, to production pressure drawdown. It remains to be established how artificial fracture and coal fabric aperture width change as a consequence of the dynamic, diametric competition between gas desorption-induced coal matrix shrinkage and the omnipresent tendency for reservoir compaction caused by increasing production pressure drawdown-induced effective stress. This technical impasse, inhibiting commercialisation, is addressed by analysing the atypical flowback behaviour of hydraulically fracture stimulated coal seams within a dedicated vertical wellbore at 9,500 feet (2,900 metres). High-resolution, non-classical flowback analysis is performed on the pure dataset of Australia’s first ultra-deep coal gas well. Wellhead and fracture network pressures are recorded continuously for 8 1/2 years, at a 10-minute sample interval, while flowing to atmosphere. Natural flowback behaviour is analogous to that of a mechanical gas plunger artificial lift system. A low but gradually increasing quasi-steady state base gas flow, free of produced formation water, is overprinted by a non-steady state, cyclical pressure signature that is diagnostic of dynamic reservoir behaviour during gas production. A total of 114 high-rate, “geyser-like” gas surge events, gradually increasing in duration from 2 hours to 2 weeks, and in reservoir equivalent volume from 360 to 20,000 rcf (10 to 570 rcm), suggest the gas headspace compartment of a “down-hole void space domain” is steadily increasing in size. The gas surge events result from intermittent release of fracture network gas, hydrostatically compressed by flowback fluid slowly accumulating within the wellbore. A production “history match” for the gas surge event pressure profile is obtained by designing, fabricating, operating, and data logging a computer-controlled hydraulic apparatus within The University of Adelaide’s experimental wellbore, at a depth of 230 feet (70 metres). This physically simulates open-ended flowing manometer-like hydrodynamic behaviour of the wellbore-reservoir system. A postulated geological trigger mechanism for surge initiation is tested and validated; “wellbore hydrostatic back-pressure and reservoir stress-dependent leak-off”. Time-lapse pressure transient analysis (PTA) is performed on three extended wellbore pressure build-up tests, lasting 157, 259, and 295 days respectively. Increasing permeability is recognised within coal fabric surrounding the initial fracture network SRV domain. Time-lapse rate transient analysis (RTA) performed on the first two subsequent wellbore pressure “blow-down to atmosphere” (BDTA) gas flow rate decline profiles indicates that hydraulic fracture flow conductivity increased during the intervening 327-day flowback period. Interpreted dilation of hydraulic fracture apertures is supported by a 60% increase in the initial BDTA gas flow rates, from 7.5 to 12.0 MMscfd (212.4 to 340.0 Mscmd). Cooper Basin ultra-deep coal gas reservoirs behave differently to other deep, thermogenic source rock reservoirs, and require a paradigm shift in reservoir stimulation technology that does not rely exclusively upon hydraulic fracture stimulation and the “brittleness factor”. Pressure arching may fill this role by neutralising the omnipresent tendency for reservoir compaction caused by increasing production pressure drawdown-induced effective stress. The combined, mutually sustaining actions of desorption-induced coal matrix shrinkage and sympathetic pressure arch “stress shield” evolution generate an “expanding reservoir boundary and decreasing confining stress” condition that allows producing ultra-deep coal seams, and adjacent strata indirectly (which may include other reservoir types), to progressively de-stress and “self-fracture” in an overall state of endogenous tensile failure. As with underground coal mine excavations, pressure arching will deflect maximum stress vectors around the dilating “dispersed coal fabric void space” domain of a growing fracture network SRV domain that has developed reduced bulk structural integrity, and reduced bulk compressive strength, compared to the surrounding native coal seam and host rock strata. Size and effectiveness of pressure arching increases with depth. Cooper Basin ultra-deep coal seams, and adjacent “non-coal” reservoirs indirectly, may be effectively stimulated to flow gas on a large scale by harnessing this self-perpetuating, depth-resistant mechanism for creating coal fracture / fabric permeability and surface area for gas desorption. They may be induced to pervasively “shatter”, or “self-fracture”, naturally during gas production, independent of the lack of “brittleness”, analogous to the manner in which shrinkage crack networks slowly form, in a state of intrinsic, endogenous tension, within desiccating clay-rich surface sediment. Full-cycle, standalone commercial gas production is considered likely to occur when “Expanding Reservoir Boundary Theory” is applied, so as to replicate the very large, complex fracture network SRV domain of commercial shale gas reservoirs.
Advisor: McCabe, Peter
Salmachi, Alireza
Dissertation Note: Thesis (Ph.D.) -- University of Adelaide, Australian School of Petroleum, 2020
Keywords: Adsorption
coal matrix shrinkage
Cooper Basin
deep coal gas
deep coal seam
dynamic permeability
effective stress
fracture network
pressure arch
pressure transient analysis
rate transient analysis
source rock reservoir
stimulated reservoir volume
ultra-deep coal seam
unconventional reservoir
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