In the Northern Territory, the Department of Mines and Energy (DME) is the agency responsible for regulating the exploration and production of oil and gas and the administration of petroleum tenures and petroleum pipelines onshore and in designated coastal waters up to 3 nautical miles seaward from the Territorial Sea Baseline of the Northern Territory. The DME’s role is to ensure that best-practice regulatory principles are applied for the sustainable and safe exploration and production of natural resources in the Northern Territory. In the Northern Territory, hydraulic fracturing has taken place since 1967, mainly as a process to enhance hydrocarbon production from conventional reservoirs with vertical wells. Since 2011, however, hydraulic fracturing has been carried out during exploration for unconventional hydrocarbons. Until now, developmental drilling has taken place only in producing fields in the Amadeus Basin.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 182404, “Unconventional-Resources Exploration and Development in the Northern Territory—Challenges From a Regulator’s Perspective,” by M. Rezazadeh, J. van Hattum, and D. Marozzi, Northern Territory Department of Mines and Energy, prepared for the 2016 SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 25–27 October. The paper has not been peer reviewed.
The production of conventional onshore oil and gas in Australia’s Northern Territory began in 1983 from the Palm Valley Field (gas) in the Amadeus Basin. Until 2010, the industry relied on conventional oil and gas development technology, but, in recent years, the focus of the industry has shifted to unconventional-resource exploration. This paper outlines the key issues that must be addressed from a regulatory perspective in regard to the development of an onshore unconventional-gas industry in the Northern Territory.
In the Northern Territory, the Department of Mines and Energy (DME) is the agency responsible for regulating the exploration and production of oil and gas and the administration of petroleum tenures and petroleum pipelines onshore and in designated coastal waters up to 3 nautical miles seaward from the Territorial Sea Baseline of the Northern Territory. The DME’s role is to ensure that best-practice regulatory principles are applied for the sustainable and safe exploration and production of natural resources in the Northern Territory.
In the Northern Territory, hydraulic fracturing has taken place since 1967, mainly as a process to enhance hydrocarbon production from conventional reservoirs with vertical wells. Since 2011, however, hydraulic fracturing has been carried out during exploration for unconventional hydrocarbons. Until now, developmental drilling has taken place only in producing fields in the Amadeus Basin. In the McArthur, Bonaparte, South Georgina, and Pedirka Basins, exploration activities are ongoing.
Onshore Northern Territory oil production comes from the Mereenie and Surprise Fields. Until November 2015, onshore gas production in the Northern Territory came from the Mereenie and Palm Valley Fields. In December 2015, the Dingo Field began producing gas. In 2015, 3,703 MMscf of gas was produced from the three fields.
Current Northern Territory Onshore Petroleum Regulatory Framework
The Northern Territory Petroleum Act is the principal existing legislation regulating oil and gas exploration and production. The DME currently uses the Schedule of Onshore Petroleum Exploration and Production Requirements (referred to here as the Schedule) to regulate petroleum activities; this guideline is similar to that which Western Australia previously used. In 2015, Western Australia replaced the Schedule with its Petroleum Resource Management and Administration Regulations. The Schedule is used to provide requirements to regulate and audit all petroleum activities.
Rezazadeh, M. (Northern Territory Department of Mines and Energy) | Hattum, J. van (Northern Territory Department of Mines and Energy) | Marozzi, D. (Northern Territory Department of Mines and Energy)
The production of conventional onshore oil and gas in the Northern Territory began in 1983 from the Palm Valley gas field, Amadeus Basin South of Alice Springs. Up until 2010the industry relied on conventional oil and gas development technology albeit with substantial technological advances over time. In recent years the focus of the industry has shifted to unconventional resource exploration, particularly the highly prospective shale gas resources in the McArthur and Georgina Basins. Current estimates indicate that the Northern Territory has more than 200 trillion cubic feet of prospective unconventional natural gas resources in six basins. The technologies and techniques to explore and develop petroleum resources from deep shale are innovations on technologies and practices employed for exploration and development of conventional resources with revolutionary consequences, particularly in North America.
This technical note is a synopsis of paper 2001-091.
The chemical composition and evolution of formation waters associated with gas production in the Palm Valley field, Northern Territory, has important implications for reservoir management, saline water disposal, and gas reserve calculations. Historically, the occurrence of saline formation water in gas fields has been the subject of considerable debate. At Palm Valley gas field there were no occurrences of mobile water early in the development of the field and, only after the gas production had reduced the reservoir pressure, was saline formation water produced. Initially this was in small quantities but has increased dramatically with time, particularly after the installation of compression in November 1996.
Produced waters from the field have been chemically and isotopically characterized in order to investigate the origin of the extreme salinity observed in some cases. The produced waters range from highly saline (TDS=>300,000), with unusual enrichments in Ca, Ba and Sr, to very low salinity fluids that may represent condensate waters. The Sr isotopic compositions of the waters are also variable but do not correlate closely with major and trace element abundances.
The formation waters preserve chemical and isotopic heterogeneities and are thus not well mixed. The high salinity brines have Sr isotopic compositions and other geochemical characteristics more consistent with long term residence within the reservoir rocks than with present-day derivation from a more distal pool of brines associated with underlying evaporites. This conclusion is important in that the brines, if locally derived, may be less significant volumetrically than might be expected if there was present-day hydrological continuity between the brines and the evaporites.
The Palm Valley gas field is situated in the Palm Valley anticline, central northern Amadeus Basin of central Australia1. The field supplies natural gas via pipelines to Alice Springs (120 km) and Darwin (1500 km) (Fig. 1)2. Palm Valley is a classic Type 2 naturally fractured reservoir2 where fractures provide essential reservoir permeability in the tight matrix rock. These reservoir effective fractures have yielded gas flow rates up to 137 MMcf/D (3.88 Mm3/D).
The gas is reservoired in low porosity (4-5%), low permeability (0.01-0.03 md) matrix rock and is producible only because of the presence of a complex network of natural fractures. The gas is relatively dry, averaging 88% methane and 8% ethane, and the primary drive mechanism is gas expansion.
Isochronal, modified isochronal, and LIT testing are used routinely as a basisto forecast deliverability of gas reservoirs. This paper shows an applicationof this technique to the naturally fractured Palm Valley gas field in centralAustralia. Results are corroborated with the use of a dual-porosity numericalsimulator.
The initial isochronal tests of 4 wells are presented together with thedeliverability equations. This is followed by a comparison with 40 months ofproduction history. The data show that values of "e" in the Rawlins andSchellhardt equation have been declining continuously for all 4 wellsthroughout the 40 months of production history.
The conclusion is reached that conventional isochronal test analysis is notreliable to forecast deliverability References and illustrations at the end ofpaper of gas wells in naturally fractured reservoirs. Use of this approach caneasily lead to optimistic forecasts.
This case history discusses the Palm Valley gas field in Central Palm Valley gas field in Central Australia Production is obtained from a naturally fractured sandstone characterized by a very low matrix permeability (km less than 0.1 md). permeability (km less than 0.1 md). An integrated study including detailed geology, core and log analyses, well testing and numerical simulation led to a good history match of a 33 hour interference test and over 7 years of production.
The conclusion was reached that 98% of the gas was stored in a very tight matrix and that the prolific production was only possible via a production was only possible via a network of natural fractures.
The methodology used to reach a history match in this case history is presented in detail together with presented in detail together with discussions of critical parameters such as fracture spacing, fracture porosity, and fracture permeability. porosity, and fracture permeability
The Palm Valley Gas Field is situated in the central-northern Amadeus Basin, Northern Territory, Australia (Fig. 1), approximately 120 km. southwest of Alice Springs. The structure is an arcuate anticline mapped from surface expression and seismic data (Fig. 2). The western and eastern plunges of the anticline are poorly defined, however, the anticline poorly defined, however, the anticline axis can be traced for over 40 km.
Production from the field commenced in August 1953 with the completion of an 8" pipeline to Alice Springs. Natural gas has been used as a replacement for liquid fuels in electricity generation. Gas production from the field has increased production from the field has increased steadily, currently averaging 141,000 standard m3/d (5 MMSCFD) to Alice Springs.
In September 1986 a fourteen inch trunk pipeline was completed connecting the field to the city of Darwin, 1300 km to the north, and to several major towns en-route. Production for this pipeline has Production for this pipeline has reached 622,000 standard m3/d (19 MMSCFD) and again has been used as a liquid fuel replacement in electric power generation. power generation. Development of the field has followed the definition of reserves and during the past 24 years, estimation of the gas reserves has been the subject of many studies; the most significant being by Strobel et al. in 1976; a reservoir simulation study by van Poollen and Associates in 1985 and a recent reserves study by Servipetrol Ltd. in 1990.