In December 2009, the EP389 joint venture (JV) – which, at the time, consisted of operator Empire Oil and Gas NL (68.75 per cent), ERM Gas Pty Ltd (21.25 per cent) and Wharf Resources (10 per cent) – made a gas and condensate discovery during the drilling of the Gingin West-1 well located near Gingin. This was followed by another discovery in February 2011 at the nearby Red Gully-1 well.
As of May 2013, the EP389 JV consists of operator Empire Oil & Gas (76.39 per cent) and ERM Gas (23.61 per cent) as Wharf Resources withdrew as a result of being in default of its obligations under the EP389 joint operating agreement.
The two discoveries, as well as the processing facility itself, are located within EP389 in Western Australia’s onshore Perth Basin, 18 km north of Gingin.
According to Mr Marshall, these back-to-back discovery wells boast the largest gas flow rates from an onshore well in the Perth Basin from Jurassic-aged reservoirs. “Gingin West-1 flowed at a stabilised rate of 7.5 MMcf/d of gas and 375 bbl/d of condensate. Red Gully-1 flowed at a stabilised rate of 12 MMcf/d of gas and 832 bbl/d of condensate,” he says.
From this discovery, Mr Marshall notes that the EP389 joint venture immediately saw an opportunity to commercialise its gas. “A diversity of gas supply has been in demand particularly since the Varanus explosion for both industry and domestic consumption. Empire could potentially help to fill this in the future,” he says.
“Given there is such a high demand for gas in Australia, particularly within WA with a deregulated gas market and robust gas price, the joint venture decided to develop these wells by constructing the Red Gully Gas and Condensate Processing Facility.”
The EP389 JV has established both a forward gas sales as well as a gas sales contract with Alcoa of Australia Limited to supply a total volume of 15,000 TJ of gas in two tranches into the Dampier to Bunbury Natural Gas Pipeline (DBNGP). The agreement with DBP is for entry into the DBNGP for 20 years, whereby Empire and the EP389 JV can sell gas to customers up and down the pipeline. The JV is also in the process of finalising a contract with BP to sell its condensate at the Kwinana Refinery.
The facility
The Red Gully Gas and Condensate Processing Facility is the first dedicated onshore Perth Basin Facility to treat condensate-rich gas. According to Mr Marshall, this aspect of the gas means the facility required a more complex design to process the condensate such that it can be delivered to the BP Refinery.
Specialised equipment was manufactured for the plant, including two compressors – an export and a flash gas compressor – which were shipped from Enerflex in Houston, Texas.
“As part of the condensate processing process, Empire has included a flash gas compressor and other items to ensure there are no LPGs (volatiles) in the condensate,” explains Mr Marshall.
The initial design for the Red Gully Gas and Condensate Processing Facility will treat up to approximately 10 MMcf/d of gas and up to 500 bbl/d of condensate, with provision for future expansion of the processing facilities to process up to 30 MMcf/d of gas and 1,500 bbl/d of condensate.
Momentum Engineering was contracted to design the facility, and Primero Group began construction of facility in August 2012. Local contractors, construction materials and stores were used whenever possible.
The pipeline
The Red Gully Gas and Condensate Processing Facility includes a 3.2 km, 102 mm diameter gas export pipeline constructed by Thistle Fabrications using API 5L-B, three-layer polyethylene externally coated steel pipe.
This pipeline connects the facility to the DBNGP. It was buried to a minimum depth of 900 mm along its entire route, and is contained within privately-owned land.
The pipeline has the capacity to transport up to 30 TJ/d of sales gas, which includes provision for future expansion. It was hot-tapped into the DBNGP by proponent DBP.
Empire Oil and Gas NL Red Gully Development Project Manager Matt Biddle says “The Empire inlet Facility sits within the expanded Dampier to Bunbury corridor, and the DBP compound sits within the original Bunbury natural gas pipeline corridor. The weld connection between the two spools is right on the boundary of the two corridors.”
Overcoming challenges in construction
Mr Marshall says the main challenge associated with the project has been the need for the facility’s design to suit the DBNGP and Kwinana Refinery specifications. “Otherwise the gas and condensate is sweet, with no problematic gases, such as carbon dioxide or hydrogen sulphide or anomalous metals such as mercury or uranium,” he says.
Mr Marshall adds that there were also some issues surrounding land access resulting in the joint venture purchasing the property on which the facility has been built.
However, Mr Marshall says that commercialising the gas discoveries was made easier by the fact that existing infrastructure is already in place in the Perth Basin.
“The Perth Basin is not as big as other basins, such as the Canning Basin, but it has much better infrastructure with sealed roads and two natural gas pipelines in the immediate proximity to the facility, in addition to an oil refinery at Kwinana only two hours away,” he says.
“It is also located on the doorstep of the city of Perth and its industrial satellites. Unconventional oil and gas potential can be explored side by side with conventional exploration with large cost savings. Access to the DBNGP also allows for the swapping of gas along the pipeline route from Onslow to Dampier and Bunbury.”
Serious potential
Mr Marshall says that building the Red Gully facility is just the beginning. Other potential additional conventional reserves have been identified in structures in close proximity to the facility, and he predicts that other gas plants are likely to be constructed as further discoveries are made along the 60 km Gingin to Bullsbrook oil and gas trend.
“Recoverable reserves for Gingin West-1 and Red Gully-1 are estimated at 30 Bcf, and estimates for potential additional reserves in prospects located in the adjacent Gingin Gas Field Area are up to 205 Bcf of recoverable gas and 9.2 MMbbl of condensate. Gas discoveries from these prospects can be treated at the Facility,” says Mr Marshall.
At the time of writing, Empire is undertaking the Wannamal 3D Heliseismic Survey over both the Wannamal and Gingin Gas Field Area, a process which Mr Marshall says will provide high definition information on prospects identified to date being Gingin-4 Deep; Gingin-5 (Downthrown); Wannamal-1 and Deep; and Gingin West Deep prospects.
“The prospectivity of the Gingin Gas Field Area is demonstrated by discovery wells Gingin-1 and Gingin-2 drilled respectively in 1964 and 1965 by WAPET. The Wannamal 3D seismic will further define prospects for drilling in 2014 and any new gas and condensate discoveries made from drilling these prospects defined by the survey can be treated at the Red Gully Facility.
“In addition, the Perth Basin has very significant unconventional reserve potential. A recent independent report by RPS Energy Services on unconventional gas stated that the unrisked, undiscovered gas-in-place potential in EP 389 contains between
40-140 Bcf per sq km of natural gas within the permit’s Lower Cattamarra Coal Measures.
According to Mr Marshall, the unconventional potential over the seismically delineated 60 km Gingin to Bullsbrook trend in EP389 alone was reported to have gas-in-place of approximately 24 Tcf.
“This prospectivity is already seen in the Lower Cattamarra where adjacent discovery wells Gingin-1 flowed at rates of 4.25 MMcf/d of gas and Gingin-2 at 3.92 MMcf/d of gas. The Lower Cattamarra is to be evaluated in future drilling planned in late 2013-14 when the Lower Cattamarra will be targeted as the “˜Deeps’ (i.e. Gingin-4 Deep; and Wannamal Deep and Gingin West Deep).
“Further RPS studies of the adjacent EP440 permit provide additional unconventional gas of up to 36 Tcf in the Lower Cattamarra Coal Measures. Both EP389 and EP440 have potential gas in place of 60 Tcf.”
Mr Marshall adds that the Red Gully facility will make a significant difference to the economics in future conventional and unconventional gas discoveries in the Perth Basin within its EP389 permit.
“Empire has over 3 million acres under licence in the Perth Basin and most of the unconventional potential is relatively unknown. We intend to pursue this potential as we explore for the conventional targets.
“We are in a desirable position in the Perth Basin having the opportunity to potentially explore the unconventional prospectivity of the onshore prospects. The Red Gully Facility would certainly make a substantial difference to the economics of recovering gas nearby.”
Rediscovering a “˜forgotten’ basin
Mr Marshall believes that international investors and international oil companies are only just starting to realise the conventional and unconventional oil and gas potential of the onshore Perth Basin.
“The Perth Basin is a forgotten basin. For the patient explorer, many discoveries could eventually build into significant reserves. The Perth Basin is a proven petroleum province, and has a history of oil and gas discoveries dating back to the 1960s.
“The upside to the Perth Basin is an already established infrastructure together with two natural gas pipelines including the DBNGP and Parmelia Natural Gas Pipeline. The Perth Basin can be explored all year around whereas places such as the remote Canning Basin have a number of difficulties with no pipeline, infrastructure, and an unpredictable wet season.
“Empire will continue to promote both the conventional and unconventional opportunity potential of the Perth Basin, which remains under-drilled for conventional targets alone with a low drilling density by international standards.”
Empire has appointed Macquarie Capital (Australia) Ltd as the exclusive financial advisor to assist the Company in identifying and evaluating suitable partners for a basin-wide farm-out of the company’s Perth and Carnarvon basins’ assets.
“3D seismic has greatly improved the success rates in the basin, and additional discoveries and reserves can be expected,” he says. “The economics of even small oil and gas fields is highly profitable. The domestic market for additional gas sales is in demand. Any future discoveries of gas in the basin can be quickly marketed and the fields developed with early cash flow.”
At the time of writing, construction of the Red Gully Gas and Condensate Facility was expected to reach completion in early May 2013, with commissioning by Oceaneering Services Australia to follow shortly thereafter.
