- Bioregional Assessment Program
- Maranoa-Balonne-Condamine subregion
- 2.3 Conceptual modelling for the Maranoa-Balonne-Condamine subregion
- 2.3.4 Baseline and coal resource development pathway
- 188.8.131.52 Developing the coal resource development pathway
- 184.108.40.206.1 Baseline coal resource developments
Baseline coal mines
Five coal mines are included in the baseline in the Maranoa-Balonne-Condamine subregion, four of which are still in operation as of 16 July 2015. The operational mines are open-cut developments and include the Cameby Downs Mine, Commodore Mine, Kogan Creek Mine and New Acland Coal Mine Stage 2. Additionally, there is one open-cut mine, Wilkie Creek Mine, which ceased operation in December 2013.
All five mines are located in the eastern part of the Maranoa-Balonne-Condamine subregion (Figure 27). The Commodore Mine and New Acland Stage 2 Coal Mine extract coal from the Walloon Coal Measures of the Clarence-Moreton Basin, whereas the Cameby Downs, Kogan Creek, and Wilkie Creek mines target seams of the Walloon Coal Measures in the Surat Basin. The mines were described in detail in companion product 1.2 for the Maranoa-Balonne-Condamine subregion (Sander et al., 2014) and key details are summarised in Table 11. This section provides a brief summary of this information.
Cameby Downs Mine
The Cameby Downs Mine is currently owned and operated by Syntech Resources Pty Ltd and managed by Yancoal Australia Ltd. The mine commenced coal production in 2010 (Yancoal, 2015). The capacity of the project’s Stage 1 is limited by environmental approvals to up to 2.3 Mt/year of run-of-mine (ROM) coal (Yancoal, 2015) extracted from the Juandah Coal Measures, which translates to about 1.8 Mt/year of thermal coal (Yancoal, 2015). Resources at the mine comprise 208 Mt measured, 247 Mt indicated and 233 Mt inferred and proved plus probable (2P) reserves of 440 Mt (proved 189 Mt and probable 251 Mt). On-site facilities at the mine include coal handling and preparation plants.
The Commodore Mine is an open-cut mine majority owned by InterGen Australia Pty Ltd and Marubeni Corporation with Downer EDI Limited providing mining services. The mine commenced production in 2002 supplying about 3.5 Mt/year of raw coal to the Millmerran power station (Weeden et al., 2007, InterGen, 2015). The coal is extracted from the Kooroongarra, Commodore and Bottom Rider seams of the Walloon Coal Measures. Overburden and waste from mining activities are stored to later backfill pits and develop the final landform, with progressive rehabilitation already underway (InterGen, 2015).
Kogan Creek Mine
Kogan Creek Mine is an open-cut mine owned by Aberdare Collieries Pty Ltd, a subsidiary of CS Energy Ltd which is owned by the Queensland Government. The total coal resource (measured and indicated) reported at the mine is 400 Mt (CS Energy, 2013). Production commenced in 2007 at a rate of 2.8 Mt/year of thermal ROM coal extracted from the M, N, and O seams of the Juandah Coal Measures. The voids resulting from the open-cut mining operations are backfilled using spoil dumps in preparation for land rehabilitation (CS Energy, 2013).
New Acland Coal Mine Stage 2
The New Acland Coal Mine Stage 2 is currently operated by New Hope Group. The project’s Stage 2 consists of a 64 Mt coal resource within the Acland-Sabine, Waipanna, and Balgowan sequences of the Walloon Coal Measures (EPA, 2006). Mining commenced in 2002 and was estimated to occur at a rate of 4 Mt/year of product coal for a ROM coal production rate of up to 7.5 Mt/year with reserves being forecasted to be depleted by 2017 (Queensland Government EPA, 2006). However, product coal production has been quoted to be about 5 Mt/year by New Hope Group (New Hope Group, 2012a, 2014a).
Approximately 10% of the New Acland mining lease area is mined at any one time, while agricultural activities continue on remaining land. Land rehabilitation is ongoing to ensure the land is returned to a commercially viable agricultural state (EPA, 2006; New Hope Group, 2013). On-site facilities include two coal handling and preparation plants.
Wilkie Creek Mine
The Wilkie Creek Mine commenced coal mining operations in 1994 and was acquired by Peabody Energy Inc. (Peabody Energy) in 2002 (MiningLink, 2015). The mine produced approximately 2.3 Mt/year of thermal coal from the Tarcoola, Braemar, and Kogan coal seams (MiningLink, 2015). Areas that were disturbed during coal mining were progressively rehabilitated after they had been mined out (MiningLink, 2015).
In 2009, Peabody Energy announced plans for the Wilkie Creek Expansion Project, which involved coal mining in new areas of the lease and thus an extension of the life of the mine (WDRC, 2011a). This project, however, did not eventuate and in December 2013 the mine ceased coal production (Peabody Energy, 2013). As of July 2015 the Wilkie Creek Mine has been sold to Exergen Pty Ltd with the deal expected to be closed in the third quarter of 2015 (MiningLink, 2015).
Baseline coal seam gas developments
Based on the OGIA numerical groundwater model (see Section 220.127.116.11), CSG operations included in the baseline are predominantly the large-scale gas field developments supporting the three liquefied natural gas (LNG) projects on Curtis Island near Gladstone: Australia Pacific LNG (APLNG) Project, Queensland Curtis LNG (QCLNG) Project and Santos Gladstone LNG (GLNG) Project in combination with the Santos GLNG Gas Field Development Project. In addition, the Surat Gas Project, whose gas resource may be developed to support the other LNG projects, as well as the smaller-scale Ironbark Project, are part of the baseline. The footprint of the baseline gas field developments in the subregion is indicated in Figure 27.
Since gas field development is a progressive process, the tenements presented in Figure 27 will not all be developed and produced at the same time, but the process will occur in stages. Some of the tenements contain producing gas fields, some of which have been in production since before construction of the LNG projects commenced (such as the Talinga, Berwyndale, Kenya, Argyle, Kogan, Tipton and Daandine gas fields (for details see companion product 1.2 for the Maranoa-Balonne-Condamine subregion (Sander et al., 2014)), some tenements have pilot testing, some have appraisal activity and some have exploration activities. The timing of gas field commencement and cessation used in the groundwater model follows that used in the 2014 annual report for the OGIA numerical groundwater model, which is described in more detail in companion product 2.6.2 for the Maranoa-Balonne-Condamine subregion (Janardhanan et al., 2016).
The baseline CSG developments are described in detail in companion product 1.2 for the Maranoa-Balonne-Condamine subregion (Sander et al., 2014). This section provides a brief summary of that information with key details summarised in Table 11. However, as the projects progress, specific details and figures quoted are likely to be subject to change as current understanding and conditions evolve.
Australia Pacific LNG Project
Australia Pacific LNG Pty Limited (APLNG) is a joint venture between Origin Energy Limited (37.5% ownership), ConocoPhillips Company (37.5%), and China Petroleum & Chemical Corporation (25%). The APLNG Project comprises the development of CSG fields, the gas from which is to be transported to Curtis Island via a newly constructed pipeline to be processed for export (Origin Energy, 2013). Two LNG trains are being built on Curtis Island (Origin Energy, 2013) with capacities of 4.5 Mt/year each. Two additional trains are proposed to be built later in the project which would bring the total capacity to 18 Mt/year (APLNG, 2010). Construction of the APLNG Project was reported to be more than 90% complete by 31 March 2015 (Origin Energy, 2015). The project is expected to run for 30 years and will include the development of up to 10,000 CSG wells (to service four LNG trains; 5,000 wells are needed for the first two LNG trains) at a rate of up to 600 wells per year (APLNG, 2010). The gas for the project (11.5 Mt/year to supply two LNG trains) is to be mostly supplied by further developing APLNG’s gas fields, with the remainder being sourced from APLNG’s existing operations (outside the Walloon gas fields), exploration areas and equity in tenures operated by other gas producers (APLNG, 2010). Construction of the gas fields commenced in 2011 and the first gas was delivered to Curtis Island in February 2015 (Origin Energy, 2015). During Phase 1, which covers the initial five years of the project, a total of 1100 production wells are expected to be drilled (Origin Energy, 2013). By March 2015, 1069 development wells (including 121 wells at Spring Gully in the Bowen Basin, outside the Maranoa-Balonne-Condamine subregion) had been drilled to serve the APLNG Project.
Santos Gladstone LNG and Santos Gladstone LNG Gas Field Development projects
The GLNG Project is a joint venture between Santos Ltd (Santos) (30%), Petroliam Nasional Berhad (27.5%), TOTAL S.A. (27.5%) and Korea Gas Corporation (15%) with Santos acting as operator (Santos, 2015a). The project includes the development of CSG resources in the Bowen and Surat basins in south-east Queensland, construction of an underground gas pipeline to Gladstone and two LNG trains with a total capacity of 7.8 Mt/year on Curtis Island. The nominal project life is 30 years, though the project may remain operational beyond that point. Construction of the project is about 95% complete (as of 30 June 2015, Santos, 2015b) and the first LNG production was shipped on schedule in October 2015. For the Santos GLNG Project, Santos’ existing CSG fields at Fairview and Roma are being further developed, while the Arcadia Valley gas field is a new development (Santos, 2009). Only the Roma gas fields are located in the Maranoa-Balonne-Condamine subregion.
A total of 2650 wells are planned for the Santos GLNG Project. An additional 6100 wells are estimated as part of the Santos GLNG Gas Field Development Project, a continuation of the Santos GLNG Project. This means up to 8750 wells will be drilled at Roma, Fairview, and Arcadia. By 30 June 2015, 478 CSG wells were online of which 120 are located at Roma (Santos, 2015b). The producing life of a well is estimated to be 5 to 15 years, so that wells will be replaced over time with new wells drilled in different locations to continue sufficient supply of CSG. The schedule of well development will be dictated by field performance and the drilling programme will be adjusted accordingly. The specific locations of exploration and development wells and associated infrastructure are determined incrementally based on the outcome of ongoing exploration programmes (Santos, 2009).
Queensland Curtis LNG Project
The QCLNG Project is owned and operated by QGC Pty Limited (QGC) and involves expansion of QGC’s existing CSG operations and development of new gas fields in the Surat Basin in southern Queensland. The gas is transported via an underground pipeline to Curtis Island where it is converted to LNG for export (QGC, 2009). The LNG facility comprises two trains which are designed to produce a combined 8.5 Mt/year of LNG (QG, 2009). In order to meet this demand, 1414 TJ/day of gas are required (707 TJ/day per train). Construction of the QCLNG Project commenced in 2010 (QGC, 2012). The first gas for LNG production was delivered to Curtis Island in December 2013 (Hough, 2013); LNG production commenced in December 2014 from the first train, while the second LNG train began commercial operation in May 2015 (Kovacs, 2015). By July 2015, more than 1.5 Mt of LNG had already been shipped with LNG plateau production anticipated by mid-2016 (Kovacs, 2015). Although the minimum project life is expected to be 20 years, the approval conditions allow development over a 50-year period up to 2060 (QGC, 2013). Development of the gas fields is set to occur as a continuous process with some development occurring simultaneously. It is estimated that 6000 CSG production wells are to be drilled over the life of the project, with individual well life estimated to range from 15 to 20 years or longer. By mid-2014 more than 2350 wells had been drilled for the QCLNG Project (GasFields Commission Queensland, 2015). The remaining wells will be phased in over the life of the project to supplement declining wells (QGC, 2009); starting in 2015, 300 wells a year are forecasted to be drilled to keep production levels steady (GasFields Commission Queensland, 2015). Approximately 5000 wells are expected to be in production at any one stage (QGC, 2013).
Surat Gas Project
The Surat Gas Project is owned and operated by Arrow Energy Pty Ltd (Arrow Energy). The project includes expansion of production at Arrow Energy’s existing CSG fields Stratheden, Kogan North, Daandine and Tipton West and development of other Arrow Energy tenures in the Surat Basin. To optimise production over the life of the project, development of the resources will be staged and will be concurrent in several areas as Arrow Energy incrementally expands its current operations and develops new gas fields (Arrow Energy, 2012). Sustained gas production is forecasted at 1215 TJ/day for which more than 1500 wells are estimated to be required in the first five years to achieve this (Arrow Energy, 2012). A maximum of 6500 wells are to be drilled throughout the project life (Department of the Environment, 2013), which is estimated to be 35 years. Well production rates are expected to be sustainable for about nine years before they start to decline; the total well life is estimated to be between 15 and 20 years (Arrow Energy, 2012). New wells will continue to be drilled at an average rate of 400 per year (Arrow Energy, 2013a) to maintain the required production when the initial wells start to decline and are eventually phased out and replaced.
Origin Energy’s Ironbark Project currently consists of a number of pilot CSG wells, appraisal wells and monitoring wells. The Duke 2 and Duke 3 pilots, which have five operating wells each, began production in July 2012 and May 2013 respectively and successfully completed pilot production by December 2014. Six wells have been drilled as part of a third production pilot, Duke 7 (Origin Energy, 2014, pers. comm.). The 2P reserves were 259 PJ as of 31 December 2014. An environmental impact statement (EIS) for the Ironbark Project is in preparation (as of July 2015). Though still in the pilot testing phase with no EIS having been submitted, the Ironbark Project is included in the baseline rather than the CRDP to be consistent with the OGIA numerical groundwater model used to predict groundwater interactions in the subregion and beyond (QWC, 2012; OGIA, 2014) (see companion product 2.6.2 for the Maranoa-Balonne-Condamine subregion (groundwater numerical modelling; Janardhanan et al., 2016).
Product Finalisation date
- 2.3.1 Methods
- 2.3.2 Summary of key system components, processes and interactions
- 2.3.3 Ecosystems
- 2.3.4 Baseline and coal resource development pathway
- 18.104.22.168 Developing the coal resource development pathway
- 22.214.171.124 Water management for the coal resource developments
- 126.96.36.199 Gaps
- 2.3.5 Conceptual model of causal pathways
- 188.8.131.52 Methodology
- 184.108.40.206 Hazard analysis
- 220.127.116.11 Causal pathways
- 18.104.22.168 Gaps
- Contributors to the Technical Programme
- About this technical product