Several CSG projects are currently under construction in the Maranoa-Balonne-Condamine subregion to supply gas to three large scale liquefied natural gas (LNG) projects on Curtis Island: the Queensland Curtis LNG (QCLNG) Project, the Gladstone LNG (GLNG) Project, and the Australia Pacific LNG (APLNG) Project. The Stratheden gas field, a comparatively small scale project, is expected to supply gas to the domestic market. The petroleum tenures of the proposed CSG field developments are presented in Figure 12 which also highlights the network of gas pipelines in the subregion and the pipelines to Gladstone. In Queensland the petroleum tenures that cover areas of CSG exploration and production are called ‘authority to prospect’ (ATP) and ‘petroleum lease’ (PL). The ATP grants the holder the right for petroleum exploration, the PL gives its holder the right to explore for, test for, and produce petroleum (DNRM, 2014c).
Source data: DNRM (2014a), viewed 21 August 2014
Stratheden
The Stratheden gas field is owned by Arrow Energy and located in PL 252, 20 km north-west of Dalby in the Surat Basin. Its location in the subregion is indicated in Figure 12. The gas field has been drilled and commissioned (Arrow Energy, 2014a) and is currently in a water production stage to enable commercial gas production (Arrow Energy, 2014, pers. comm.). Arrow Energy’s Stratheden and Daandine (see Section 1.2.2) gas fields are contracted to supply a combined 11.5 PJ of gas to Arrow Energy’s Braemar 2 Power Station and 2.2 PJ to Energy Infrastructure Investments’ (EII) Daandine Power Station (Arrow Energy, 2014a). The total proved and probable (2P) reserves at Stratheden were 285 PJ as of 31 December 2013 (DNRM, 2014d). Under the proposed Surat Gas Project (one of five components of the Arrow LNG project), the Stratheden gas field would be expanded to also supply CSG for LNG export (Arrow Energy, 2014, pers. comm.).
Queensland Curtis Liquefied Natural Gas Project
The QCLNG Project is owned and operated by QGC and involves expansion of QGC’s existing CSG operations and development of new gas fields in the Surat Basin in southern Queensland. The location of the project in the Maranoa-Balonne-Condamine subregion is indicated in Figure 12. The gas is to be transported via an underground pipeline to a gas liquefaction and export facility on Curtis Island, near Gladstone, where it will be converted to LNG for export (QGC, 2009). The facility at Curtis Island comprises two LNG trains which are to produce a combined 8.5 million tonnes (Mt) of LNG per year (QG, 2009). Construction of the QCLNG Project commenced in 2010 (QGC, 2012a) and the project is well on track for first LNG delivery in the final quarter of 2014 (Gladstone Observer, 2014). The minimum project life is expected to be 20 years, though the approval conditions allow development over a 50 year period up to 2060 (QGC, 2013).
The gas fields approved to be developed for the QCLNG Project are in the Walloon Fairway, between the towns of Moonie in the south, Wandoan and Miles in the north, Condamine and Tara in the west, and Chinchilla and Kogan in the east (QGC, 2009), as shown in Figure 13. A list of the individual CSG petroleum tenures containing the gas field developments is in Table 5. The total proved plus probable (2P) reserves of the proposed gas field developments in the Maranoa-Balonne-Condamine subregion are 9499 PJ as of 31 December 2013 (DNRM, 2014d) (see Table 5). Gas is extracted from the Juandah Coal Measures and the Taroom Coal Measures within the Walloon Coal Measures. QGC has reported average properties of the Walloon Coal Measures as net coal thickness of 30 m, gas content of 5 m3/t, gas saturation of 80%, and a methane content of 97%.
Source data: DNRM (2014a), viewed 21 August 2014
ATP = authority to prospect; PL = petroleum lease
Table 5 Petroleum tenures containing Queensland Curtis Liquefied Natural Gas coal seam gas developments within the Maranoa-Balonne-Condamine subregion
2P = proved plus probable reserves; ATP = authority to prospect; PL = petroleum lease; PLA = petroleum lease application; PCA = potential commercial area; PCAA = potential commercial area application
The 2P reserves are as of December 2013 (DNRM, 2014d). NA means ‘data not available’
Development of the gas fields is set to occur as a continuous process with some development occurring simultaneously. In October 2014 PL 276 (Ross, Northern Gas Field), PL 211 (Berwyndale, Central Gas Field), and PL 275 (RubyJo, Southern Gas Field) are scheduled to commence production for the QCLNG Project (QGC, 2013) (see Figure 13). A forecast of drilling activity over the duration of the project is in Table 6.
Table 6 Wells forecast to be drilled for development of the gas fields in the Maranoa-Balonne-Condamine subregion
|
Stage |
Year |
Cumulative Well Number |
|---|---|---|
|
1 |
2010 |
600 |
|
2 |
2013 |
2000 |
|
3 |
2020 |
4300 |
|
N |
2030 |
6000 |
Source data: QGC (2009)
Table 6 highlights that 6000 CSG production wells are estimated to be drilled over the life of the project. In addition, 300 exploration and appraisal wells are predicted to be drilled (estimate based on 5% of total well number (QGC, 2010)). By mid 2014, more than 2150 wells had already been drilled to provide gas for the LNG project (GasFields Commission Queensland, 2014). The basis for the QCLNG Project is the delivery of 1414 terajoules per day (TJ/day) to the LNG plant (QGC, 2009) – the facility at Curtis Island comprises two LNG trains requiring 707 TJ/day each to produce a combined 8.5 Mt of LNG per year. Individual well life is estimated to range from 15 to 20 years or longer, thus, the remaining 4000 wells will be phased in over the life of the project to supplement declining wells (QGC, 2009) and keep production levels steady. Approximately 5000 wells are expected to be in production at any one stage (QGC, 2013).
In the past QGC drilled vertical wells to intersect the target coal seams. However, QGC does not exclude the use of horizontal wells, drilling of multiple wells from a single location (multi-well pads), and hydraulic fracturing for future gas field developments (QGC, 2009). By the end of 2013 14 wells drilled by QGC for the QCLNG Project were hydraulically stimulated. Up to 33 wells are forecasted to undergo stimulation in 2014. QGC’s current stimulation program is focused on trialling, developing, and optimising stimulation techniques prior to full scale stimulation activities expected to commence in 2018 (QGC, 2013). It is estimated that approximately 1900 wells may be stimulated throughout the life of the QCLNG Project (QGC, 2013).
Wells are typically drilled to a depth of 200 to 700 m to intersect the target coals of the Walloon Coal Measures (QGC, 2009). The mean well spacing is estimated at 750 m to optimise production. Individual well locations will be finalised throughout the course of the project as exploration and development continues (QGC, 2009). The proposed gas field will entail a cumulative well lease and infrastructure disturbance between 8,000 and 15,500 ha of land (not accounting for decommissioning and rehabilitation). The location of associated infrastructure, such as compression facilities, water treatment and water storage, is dependent on well location, but is expected to be evenly distributed across the tenures (QGC, 2009). Twenty-four compression stations, six central processing plants (at RubyJo, Woleebee Creek, Bellevue, Jordan, Kenya, and Berwyndale South), 6700 km of underground gas and water pipelines, and water management facilities are estimated to be required to manage the produced fluids (QGC, 2010, 2012c). Compression stations and processing plants are required early on in the project so that the produced gas can be transported via pipelines to the LNG facility at Gladstone.
Due to the characteristics of CSG recovery, CSG production typically does not peak immediately but requires depressurisation of the seams through water production and only peaks after months or even years of recovery. Therefore, gas extraction commences before commissioning of the LNG facility to allow time to ramp-up production. QGC estimates that from 2010 to 2014 between 200 and 300 PJ of ramp-up gas will be available before start of the LNG operation. Strategies considered by QGC to manage ramp-up gas are (QGC, 2009, 2010):
QGC’s CSG fields are currently at various stages of exploration, development, and operation as the company is preparing to meet the gas demand of the LNG plant. Infrastructure at the gas fields and gas processing facilities are nearing completion (Business Spectator, 2014) and more than 2150 wells had been drilled by the end of June 2014 (GasFields Commission Queensland, 2014) with QGC drilling at a rate of over 50 wells per month (Hough, 2013). Initially, to be able to supply the required gas volume for the LNG trains (707 TJ/day per train), additional gas is contracted from a third party supplier while QGC’s CSG fields are still ramping up (Swanepoel, 2014). The third party gas is estimated to contribute 10 to 20% to the total LNG gas supply. At production plateau this fraction is expected to be only around 5%. In July 2013 Santos GLNG and QGC signed an industry collaboration deal to support plant operation flexibility and efficiency for the GLNG and the QCLNG projects. The agreement links both projects’ major pipelines in two places, thus enabling gas flow from one project to another (Santos, 2013a).
The QCLNG Project is on track for its first LNG production in the final quarter of 2014 with the first train currently being commissioned (GasFields Commission Queensland, 2014). Commissioning of the gas turbine generators began in the second quarter of 2014 and gas was introduced to the plant in the third quarter, allowing commissioning of the refrigeration turbines and compressors to start (GasFields Commission Queensland, 2014). The second train is expected to come online by mid-2015. First gas for LNG production was delivered to Curtis Island in December 2013 (Hough, 2013). Plans for a third LNG train to further expand the project have been dropped for the near term (Swanepoel, 2014).
Other QGC held petroleum tenures within the Maranoa-Balonne-Condamine subregion that were not included in the gas field development described in the EIS of the QCLNG Project are in Table 7. Appraisal is currently occurring in ATP 795 (PLA 311 and PLA 312) and ATP 767. Gas produced from these tenures in the future is likely to be used to further support the LNG project. Including these in the 2P reserves presented above (Table 5) increases QGC’s total 2P reserves in the Maranoa-Balonne-Condamine subregion to 9629 PJ as of 31 December 2013 (DNRM, 2014d).
Table 7 Additional QGC Limited petroleum tenures in the Maranoa-Balonne-Condamine subregion not included in the EIS of the Queensland Curtis Liquefied Natural Gas Project
2P = proved plus probable reserves, ATP = authority to prospect, ATPA = authority to prospect application, PL = petroleum lease, PLA = petroleum lease application, EIS = environmental impact statement
The 2P reserves are as of December 2013 (DNRM, 2014d). NA means ‘data not available’
Santos Gladstone Liquefied Natural Gas Project
The GLNG Project is a joint venture between Santos (30%), Petroliam Nasional Berhad (PETRONAS) (27.5%), TOTAL S.A. (TOTAL) (27.5%), and Korea Gas Corporation (KOGAS) (15%) with Santos acting as operator (Santos, 2014a). The project includes the development of CSG resources in the Bowen and Surat Basins in south-east Queensland, construction of a 420 km underground gas transmission pipeline to Gladstone, and two LNG trains with a total capacity of 7.8 Mt/year on Curtis Island. The project received approval from the Queensland Government and the Australian Government in 2010. The final investment decision was announced in January 2011 (Santos, 2011). The nominal project life is 30 years, though the project may remain operational beyond that point. Santos’ existing CSG resources to be further developed for the GLNG Project are the Fairview and the Roma gas fields, while the gas field Arcadia Valley is to be newly developed (Santos, 2009). Only the Roma gas fields, targeting the Walloon Coal Measures of the Surat Basin, are located in the Maranoa-Balonne-Condamine subregion; their location and extent within the subregion is in Figure 12, while the individual petroleum tenures approved for the Roma gas field development as part of the GLNG Project are in Table 8 (Santos, 2012). The combined 2P reserves of the GLNG Project at Roma are 2745 PJ as of 31 December 2013 (DNRM, 2014d) (see Table 8).
Table 8 Petroleum tenures of the Gladstone Liquefied Natural Gas Project at Roma in the Maranoa-Balonne-Condamine subregion
Source data: Santos (2012)
2P = proved plus probable reserves, ATP = authority to prospect, PL = petroleum lease, PLA = petroleum lease application
The 2P reserves are as of December 2013 (DNRM, 2014d). NA means ‘data not available’
The GLNG Project comprises two trains with a total capacity of 7.8 Mt/year (Santos, 2014b). Part of the gas requirements for these LNG trains will be supplied by the Roma CSG fields. The Roma area was initially developed by Santos as a conventional gas field which has been in production for over 50 years (Santos, 2014a), but the shallower coals are now targets for CSG. As part of the GLNG Project the existing field development will be expanded. Since 2009 more than 290 (appraisal, exploration, and development) wells are estimated to have been drilled at Roma (IRTM, viewed 21 August 2014) of which 52 wells are now on production (as of June 2014) (Santos, 2014c). Another 23 pilot wells are currently online to assess potential future development areas (Santos, 2014c). So far, development around Roma has predominantly occurred in PL 309, 310, 314, and 315 (IRTM, viewed 21 August 2014).
Production wells are estimated to have a production life of 5 to 15 years and will be replaced over time with newly drilled wells in different locations to continue to provide sufficient CSG for the GLNG Project. 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). Many of the wells to be drilled at Santos’ CSG fields will be vertical wells. However, alternative drilling techniques such as directional drilling will also be used for some areas. Directional drilling techniques have the advantage of drilling multiple wells from one lease, accessing resources that are laterally displaced from the lease area (Santos, 2009). Approximately 50% of the wells at Roma are estimated to be fractured over the life of the GLNG Project based on current knowledge of the geology and the permeability characteristics (Santos, 2013b). To the end of 2013, 18 wells at Roma had been hydraulically stimulated (Santos, 2014d). For the years 2014 and 2015, 10 and 73 wells respectively are forecasted to be hydraulically fractured at Roma (Santos, 2014d).
Gas produced from the Roma gas fields will be processed and compressed for delivery to Gladstone at the Roma Hub 2, which is currently under construction (97% complete as of June 2014) (Santos, 2014b). The Roma Hub 2 has a capacity of 145 TJ/d.
During the ramp-up period, before CSG is delivered and processed in the LNG facility, the produced gas will be supplied to domestic markets and/or stored underground in the depleted conventional gas reservoirs at Roma. The depleted gas fields at Roma have a storage capacity of more than 50 PJ. Currently seven injection wells are online with a combined injection/withdrawal rate of 75 TJ/d (Santos, 2014b). Additionally, production is managed by throttling gas flow at the wellhead where practicable (Santos, 2009).
By mid 2014 the GLNG Project was more than 85% complete and on track for LNG delivery from its first train in 2015 (Santos, 2014e). The second train is expected to come online six to nine months after the first train (Santos, 2014b). To further develop their gas resources, Santos has proposed the GLNG Gas Field Development for which an EIS is currently in preparation. The GLNG Gas Field Development is described in Section 1.2.3.2.2 – Proposed Projects.
Australia Pacific Liquefied Natural Gas Project
Australia Pacific LNG Pty Limited (APLNG) is a joint venture between Origin Energy (37.5% ownership), ConocoPhillips Company (ConocoPhillips) (37.5%), and China Petroleum and Chemical Corporation (Sinopec) (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 520 km pipeline to be processed for export (Origin Energy, 2013). If fully completed, this LNG project will be the largest of its kind in Australia, with a capacity to produce approximately 18 Mt/year from four LNG trains (capacity of 4.5 Mt/year per train) (APLNG, 2010a). Currently, two LNG trains are being built on Curtis Island (Origin Energy, 2013). The project is expected to run for 30 years and will include the development of up to 10,000 CSG wells (APLNG, 2010a). Key features of the project are described below using the most current publically available information. As the project progresses, specific details and figures quoted below are likely to be subject to change as current understanding and conditions evolve.
The gas for the project (11.5 Mt/year) 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, 2010a). The gas field development areas are highlighted in Figure 14 and the corresponding petroleum tenures and their 2P reserves are summarised in Table 9 . The gas field developments Combabula-Ramyard and Woleebee are located partially outside the subregion (see Figure 14) and only petroleum permits of these developments that are in or on the border of the Maranoa-Balonne-Condamine subregion are considered here. The location of the APLNG gas field developments in the subregion is presented in Figure 12. The combined 2P reserves of the APLNG Project in the Maranoa-Balonne-Condamine subregion are 8977 PJ as of 31 December 2013 (DNRM, 2014d) (see Table 9).
Source data: DNRM (2014a), viewed 21 August 2014
Table 9 Petroleum tenures containing the gas field development of the Australia Pacific Liquefied Natural Gas Project for the Maranoa-Balonne-Condamine subregion
2P = proved plus probable reserves; ATP = authority to prospect; PL = petroleum lease
The 2P reserves are as of December 2013 (DNRM, 2014d). NA means ‘data not available’
Up to 10,000 wells are expected to be drilled throughout the project at a rate of up to 600 wells per year (APLNG, 2010a) (150 to 400 wells per year in the initial five years (APLNG, 2010b)). There are 5000 wells forecasted to be drilled between 2011 and 2021 to meet the demand of the first two trains of the LNG plant. Another 5000 wells are estimated to be drilled over the remaining years to provide gas for the upgrade of the LNG plant from two to four trains (APLNG, 2010a). Construction of the gas fields commenced in 2011, with the development occurring in stages to meet the demand of the LNG plant (Origin Energy, 2011a). Phase 1, which covers the initial five years of the project, focuses on the gas fields Talinga-Orana, Condabri, and Combabula in the Maranoa-Balonne-Condamine subregion. During Phase 1, a total of 1100 production wells are expected to be drilled (Origin Energy, 2013). By March 2014, APLNG had drilled 680 Phase 1 development wells, of which 600 are in the gas fields Condabri (343 wells), Combabula (189 wells), and Orana (68 wells). The remaining 80 wells were drilled at Spring Gully, outside the subregion (Origin Energy, 2014a). An indicative development plan for gas fields in the Maranoa-Balonne-Condamine subregion is outlined in Table 10 (APLNG, 2014). Based on this plan, 6034 wells are estimated to be drilled in the subregion.
Table 10 Indicative Australia Pacific Liquefied Natural Gas field development plan for gas fields in the Maranoa-Balonne-Condamine subregion
Source data: APLNG (2014)
ATP = authority to prospect; PL = petroleum lease
The typical well spacing in the APLNG gas fields is estimated at 750 m, though actual well spacing may vary (APLNG, 2010a). The wells are proposed to be conventional vertical wells drilled to depths between 600 and 1000 m with some wells requiring stimulation through hydraulic fracturing or cavitation to improve gas recovery (APLNG, 2010a). Wells will only be hydraulically fractured in lower permeability areas (APLNG, 2014). Wells drilled in Phase 1 will be drilled in areas of higher permeability and productivity and are not planned to undergo stimulation (APLNG, 2014). Hydraulic fracture stimulation will be integrated into Phase 2, which is to start in the second half of 2016 (APLNG, 2014). Hydraulic fracture stimulation during Phase 2 is to begin after 2019 and finish before 2036. An indicative hydraulic fracturing schedule for Phase 2 is in Table 11, based on which 1770 wells are currently expected to be hydraulically stimulated (APLNG, 2014).
Table 11 Indicative Australia Pacific Liquefied Natural Gas Phase 2 hydraulic fracturing schedule for the Maranoa-Balonne-Condamine subregion
Source data: APLNG (2014)
ATP = authority to prospect; PL = petroleum lease, PLA = petroleum lease application
The APLNG Project is on track for first LNG production by mid-2015 (Gladstone Observer, 2013; Origin Energy, 2013). The second train is expected to follow six months later. Trains 3 and 4 are to commence later – depending on the LNG market and the development programme of the APLNG gas fields (APLNG, 2010a). The trains are being built to have a capacity of 4.5 Mt of LNG per train per year (Origin Energy, 2013). Ramp-up gas produced before commissioning and operation of the LNG plant is supplied to the Darling Downs Power Station and the Wallumbilla gas hub for use in the domestic market (APLNG, 2012).
An agreement to build two pipeline connection points between GLNG and APLNG infrastructure and to undertake a gas swap to minimise gas movements and operational costs was signed between Santos GLNG and APLNG in October 2013. Santos GLNG and APLNG are joint venture partners in a number of Santos operated petroleum tenures in the Surat Basin within the Maranoa-Balonne-Condamine subregion (Santos, 2013c).
Other APLNG held tenures in the Maranoa-Balonne-Condamine subregion that were not included in the gas field development described in the EIS of the APLNG Project are in Table 12. Potential gas production from these tenures is likely to be used to further support the APLNG Project.
Table 12 Additional Australia Pacific Liquefied Natural Gas (LNG) petroleum tenures in the Maranoa-Balonne-Condamine subregion not included in the environmental impact statement of the Australia Pacific LNG Project
2P = proved plus probable reserves, PL = petroleum lease
The 2P reserves are as of December 2013 (DNRM, 2014d). NA means ‘data not available’
