Investigation of increasing hydraulic fracture conductivity within producing ultra-deep coal seams using time-lapse rate transient analysis: A long-term pilot experiment in the Cooper Basin, Australia

Abstract

Ultra-low permeability, inertinite-rich, poorly cleated, dehydrated, overpressured coal seams deeper than 9000 ft (2740 m) in the Cooper Basin of central Australia represent a fundamentally different play type to shallow and “deep” coal seam gas reservoirs. Proof-of-concept gas flow was achieved in 2007. Four Patchawarra Formation coal seams were subjected to low-proppant concentration slick-water hydraulic fracture stimulation within a dedicated vertical wellbore at a depth of 9500 ft (2900 m). Gas was produced for 81/2 years at a slowly increasing base flow rate, averaging 0.1 MMscfd (2.8 Mscmd). Experimental data were gathered for characterising dynamic reservoir behaviour. This included multiple extended pressure build-up tests. The authors have previously investigated the three largest of these using time-lapse pressure transient analysis. The published results reveal a dominant bilinear flow regime, associated with an isolated domain of increasing coal fabric permeability surrounding the hydraulic fracture.This paper builds upon the time-lapse pressure transient analysis study by specifically investigating conductivity of the hydraulic fracture, which the authors postulate to have also increased. The hypothesis is tested by applying time-lapse rate transient analysis to the two specially designed pressure drawdown tests to atmospheric pressure that immediately follow the first two pressure build-up tests of the time-lapse pressure transient analysis. Between the two pressure drawdown tests, spaced 586 days apart, the wellbore flowed gas continuously for 327 days, at an average flowing bottom-hole pressure of 580 psig (4.0 MPag). Hence, there was ample opportunity for hydraulic fracture conductivity to change between the tests.Both pressure drawdown tests were monitored for 24 h using high-resolution surface pressure gauges. Each was initiated from the same surface shut-in pressure of 2500 psig (17.2 MPag). The flow pressure data are initially used to construct “diagnostic plots” that clearly identify the hydraulic fracture linear flow regime, early in each test, immediately after the dissipation of wellbore storage. Hydraulic fracture properties are then extracted using “specialty plots” that display rate-normalised pseudo-pressure difference versus linear superposition time.Comparing the slopes of the two speciality plot trends indicates that the hydraulic fracture flow property bfkf∅f increased during the 327-day gas flow period by a factor of 4. This is supported by a 60% increase in the initial gas flow rate from “hydraulic fracture storage”, from 7.5 to 12.0 MMscfd (212.4 to 340.0 Mscmd). Additionally, despite a significantly larger volume of “hydraulic fracture storage” gas being produced to surface during the second test, the duration of the hydraulic fracture linear flow regime is less than for the first. These observations are consistent with an increasingly more conductive hydraulic fracture over flowback time that allows compressed gas within it to discharge more rapidly.