Beach Ups Contingent Resources of Nappamerri Trough Project, Chevron Quits

Beach Energy Ltd. disclosed Friday the outcomes of DeGolyer and MacNaughton’s (D&M) review of contingent resources in ATP 855 (Beach 46.9 percent and operator, Icon Energy Ltd. 35.1 percent, Chevron Exploration 1 Pty Ltd. 18 percent) in Queensland, Australia.

D&M, an independent resource estimating firm based in Dallas, Texas, was engaged to evaluate well results from the Nappamerri Trough Natural Gas (NTNG) program following completion of the fourwell fracture stimulation and flow testing campaign undertaken in ATP 855 in the latter half of 2014.

The previous assessment of contingent resources, dated June 30, 2013, was made following the stimulation and flow testing of Halifax‐1. In the current assessment, D&M has assigned contingent resources to the areas around Etty‐1, Hervey‐1, Redland‐1 and Geoffrey‐1, incorporating results from fracture stimulation and flow testing undertaken, as summarized below.

ATP 855 Gross Gas Contingent Resources (Bcf)

  • June 30, 2013: 1C - 318; 2C - 629; 3C - 1,115
  • Dec. 31, 2014: 1C - 343; 1,572; 3C - 5,841
  • Increase: 1C - 25; 2C - 943; 3C - 4,726

Target intervals assessed by D&M are Permian‐age lacustrine and fluvial sediments of the Murteree and Roseneath shales, and the Epsilon, Toolachee, Daralingie and Patchawarra formations. Primary data used for D&M’s assessment included cores, logs, 2‐D seismic data and flow test data from ATP‐855 wells and available offset wells. Logs from these wells were calibrated to cores and used to generate ranges of thickness, porosity and gas saturation in the Epsilon, Toolachee, Daralingie and Patchawarra formations. For the Murteree and Roseneath shales, ranges for these same parameters were estimated, along with desorbed gas storage capacity and shale bulk density. Initial gas expansion factors and carbon dioxide shrinkage for all reservoir intervals were provided by Beach. The core, log and production data demonstrate the presence of a significant quantity of potentially moveable hydrocarbons at each of these wells.

Gross interval thickness ranged from approximately 984 feet (300 meters) to 4,429 feet (1,350 meters) at depths between 9,186 feet (2,800 meters) to 13,779 feet (4,200 meters). The size of the area for the contingent resource estimate was based on PRMS guidance utilising the technique of well spacing units away from each discovery well. This methodology and the resultant range in the areal extent of 2C bookings in stacked formations has been previously described by Beach1. With the additional production testing data obtained, the 2C booking area now covers between 6,500 and 13,000 acres around each of the five wells tested.

Key contingencies for commercialising the estimated resource include establishing longer‐term deliverability, reducing well costs with scale of activity, gas sales agreements and connection to adjacent facilities. Subject to improved macro‐economic conditions, Beach’s internal capital allocation policies and joint venture approval, geological studies such as 3D seismic or other imaging techniques may be undertaken to refine areas of higher potential. Appraisal wells may then be drilled over the longer‐term to assess deliverability and move the project towards commercialization.


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