Pan, Zhejun (CSIRO Energy) | Heryanto, Deasy (CSIRO Energy) | Down, David (CSIRO Energy) | Connell, Luke (CSIRO Energy) | Camilleri, Michael (CSIRO Energy) | Tan, Yuling (CSIRO Energy) | Sander, Regina (CSIRO Energy)
Cooper Basin is one of the most important onshore oil and gas producing basins in Australia. It also has the most prospective unconventional tight gas and shale gas opportunities. As tight sandstones or gas shales have low permeability, understanding the permeability behaviour is important for the production of these gas resources. In this work, tight sandstone and shale samples were obtained from an exploration well in the Cooper Basin, Australia, and they were cut into cubic samples with about 30 mm on each side using a wire saw. The cubic sample was then placed in a 3D printed membrane, therefore, permeability along each directional axis can be measured. Methane was used to characterise the permeability. Effects of gas pressure and effective stress were studied with gas pressure up to 9.5 MPa and effective stress up to 7.0 MPa. The results shows that the shale has strong permeability anisotropy at different direction. The sandstone sample also showed anisotropic behaviour, but not as significant as the shale. Finally, a reservoir simulator, SIMED II, is used to study the gas production from tight sandstone and shale using hydraulic fractured vertical and horizontal wells. The simulation results show that permeability plays a critical role in the gas production behaviour from tight sandstones and shales.
The Beetaloo Sub-basin in the Northern Territory is one of Australia's most prospective basins for shale gas production. The Beetaloo gas shales are unique in that they could become some of the oldest producing source rocks in the world, if commercialized successfully. In this work we characterise gas shales from two target reservoirs in the Beetaloo Sub-basin and compare them to other shales from around the globe to improve the current understanding of what controls gas adsorption on shales.
We characterise the methane adsorption capacity of two sets of Beetaloo shale samples: middle Velkerri B shale (8 samples, ~2450 m depth) and lower Kyalla shale (10 samples, ~1300 m depth). Measurements are performed at reservoir conditions, i.e. up to 110°C and 30 MPa, using CSIRO's gravimetric isotherm rig. The samples’ mineralogy is analysed using X-ray powder diffraction (XRD) and the total organic carbon (TOC) is determined using a LECO machine.
Our experiments demonstrate that the gravimetric rig is capable of obtaining fast and reliable measurements on low adsorbing shales at high pressures and high temperatures for sample quantities of around 90 g. The results highlight that the adsorption capacity of middle Velkerri B shale is significantly higher than of lower Kyalla shale (average Langmuir volume 3.23 m3/t compared to 2.27 m3/t) and that the isotherms can be represented using a Langmuir relationship. In spite of their age, the Beetaloo shales exhibit adsorption behaviour comparable to that of other shales with similar TOC.
Two global shale data sets, which include the Beetaloo samples, demonstrate that there is a strong relationship between TOC and a shale's adsorption capacity. However, the TOC alone cannot account for the differences in adsorbed amount observed within the two sets of Beetaloo shale samples.
Bulk clay content appears to control the adsorption capacity of shales with low TOC (< 2%), such as the lower Kyalla shale. Analysis assessing the contribution of individual clay minerals to the CH4 adsorption capacity indicates that it is the high illite/muscovite content (30-40%) that controls adsorption on the lower Kyalla shale samples. For the high TOC/low clay middle Velkerri B samples (3.7-6.3% TOC, 20-23% clay) clay content cannot account for the differences observed in adsorbed gas between the samples, even as a secondary control. Further investigation is required to understand what controls gas adsorption on this shale.
Legault, Jean M. (Geotech Ltd, Aurora, CAN) | Izarra, Carlos (Geotech Ltd, Aurora, CAN) | Prikhodko, Alexander (Geotech Ltd, Aurora, CAN) | Wood, Garnet (Cameco Corporation) | Keller, Clinton (Cameco Corporation) | O’Dowd, Clare (Cameco Corporation)
Helicopter ZTEM natural field EM and VTEM helicopter time-domain EM system results are compared over the McArthur River Project in northwestern Saskatchewan. The ZTEM survey data were complicated by the fact that they were obtained in low signal winter conditions and with a major powerline present. The ZTEM results from 30 to 90 Hz were generally of good quality to within ∼1–1.5 km from the powerline; however the higher frequency (>180 Hz) tipper data are clearly affected by powerline noise as far as 5 km away. The ZTEM signatures agree well with those from the VTEM Max system; however source depths from 2D inversion indicate that the bedrock sources are shallower than expected (<250 m), possibly due to limited frequency bandwidth or else an improper (low) apriori resistivity model. 3D ZTEM inversion results appear much improved over 2D. In nearly all cases, depths of investigation estimates exceed 2 km for the ZTEM inversions. The VTEM Max system 30 Hz TDEM results were of a comparatively good quality, with powerline affecting the data to within less than <1 kilometre. Depths to basement range from 250–300 m and imaged the location of the basement graphitic pelites. Depths of investigation from RDI resistivity-depth imaging are estimated to reach and exceed 600 m in some areas. Both EM surveys and magnetics assisted in understanding basement geology.
Presentation Date: Wednesday, October 17, 2018
Start Time: 1:50:00 PM
Location: 213B (Anaheim Convention Center)
Presentation Type: Oral
Australia's Northern Territory Lifts Hydraulic Fracturing Ban The Northern Territory, a 1.4-million-sq-km expanse of outback extending from the center of Australia to its northern coastline, had banned hydraulic fracturing, commonly known as fracking, in September 2016 amid concerns the drilling method could harm the environment. It commissioned an inquiry into the environmental, social, and economic risks of the extraction process and on 17 April accepted the inquiry’s conclusion that the risks were manageable. The announcement, which drew criticism from environmentalists, reopens shale gas reserves in the Beetaloo and McArthur basins for development. It immediately sent shares in commodity explorers in the region sharply higher, even though production is not expected to begin for about a decade. It also raised industry hopes for pushing Australia, with 88 Tcf of identified unconventional gas reserves, like the United States before it, toward energy self-sufficiency if blocks on hydraulic fracturing were lifted elsewhere in the country.
We investigated geological, petrophysical, rock physics and engineering properties of resource shales using well data and core samples from three continents. The North American Utica-Point Pleasant example, spanning carbonates, marls and shales, came from the base of the oil window in this play. Extremely high resistivity invalidated the Passey method for total organic carbon (TOC) calculation, while elevated uranium marked the original source beds rather than the maximum of organic matter found in underlying carbonates where pyrobitumen is abundant. A 1 GHz dielectric log enabled us to develop a new crossplot where matrix, water and organic matter effects could be differentiated. The North American Marcellus shale example represented the other extreme of thermal maturity, where vitrinite reflectance exceeds 4 % Ro and the organic matter is partly transformed to highly conductive proto-graphite, again complicating petrophysical interpretations. The Chinese Longmaxi shale has classical “hot shale” characteristics where U content from logs or core scanning gives a good estimate of TOC. In both cases, siliceous matrix may be advantageous in terms of rock brittleness but may lock up gas in inaccessible pores. The Roseneath and Murteree Shales of the Australian Cooper Basin represent a hybrid shale/tight gas resource play where Gas in Place (GIP) is dominated by free gas, largely sourced from nearby coals, in inter-mineral pore space. Dielectric responses of lab samples show a linear relationship between water content and permittivity, however no downhole dielectric logs are yet available to evaluate this approach to identify sweet spots. Aside from using advanced petrophysical and microstructural methods we gained insights from standard log correlations. We found that neutron porosity alone could entirely predict the organic-free (background) resistivity log response in the Murteree shale via the non-linear equation: 1/R_t = C [*NPHI] ^d. We propose that hydrated cation conductivity determines the pre-factor C, while pore geometry/topology determine the value of exponent d. The application of such nonlinear relationships to modern machine learning methods warrants further investigation.
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.
Water for the unconventional Exploration and Appraisal (E&A) lifecycle, from Spud to Plug and Abandon, has always presented a fundamental challenge. None more so than the recent major unconventional play of Queensland's (QLD) Coal Seam Gas (CSG).
Water management has always been an important surface component of E&A, from supporting drilling and stimulation effort, through to managing production water. However, in Queensland, water became a critical obstacle, initially driven by compliance and stakeholder issues. It became apparent methodologies from North America and even the conventional Central Australia experiences did not offer solutions to the challenge. Water issues from both regulator and landholders were more significant than expected. The consequence of this led to delays in data acquisition and significant cost escalation of planned E&A activity. Ultimately the boarder industry responded to the challenge by understanding the issues, then applying a fair amount of innovation.
Moving forward the general challenge still stands for new unconventional plays. Solving this requires recognition that water management is often a localized issue. Particularly as many new unconventional resources are in remote and isolated areas, with little supporting infrastructure. The
This paper presents the challenges and learnings in E&A water management from the QLD CSG experience. One of the key learnings is that planning was critical. In recognition of that fact, a simple five-part water field development planning tool is proposed to support successful E&A. With costs of E&A now more important than ever, and not withstanding the enduring need to maintain the operator's license to operate (both regulator and community), getting all aspects water management right is a fundamental key to success.
In 2013, Armour Energy commenced evaluation of conventional and unconventional gas reservoirs within the Paleoproterozoic (Pre-Cambrian) Supersequences within the Isa Superbasin, North Queensland, Australia. In 2012, a vertical well with a sidetracked lateral was drilled targeting the Lawn Hill Shale Member (Lawn), offsetting the 1990’s Egilabria 1 well, which exhibited gas shows in the same interval.
Egilabria 2 was the first recent vertical well in the area, which was subsequently sidetracked to create a 567m lateral wellbore, Egilabria 2 DW1. Egilabria 2 exhibited gas shows and flows whilst underbalanced air-drilling across Wide, Doom and Lawn Supersequences. An extensive set of logs and cuttings data were collected in Egilabria 2 aiding targeting and geologic correlation in the sidetracked lateral.
Egilabria 2 DW1 lateral was drilled, cased, cemented, and a multi-stage ‘plug-and-perf’ style of frac treatment was employed. Before shutting in the well post-frac for an extended buildup, during the inaccessible ‘wet season’ in this area, frac fluid was flowing back unassisted and gas was flaring at low surface flowing pressures. This was the first successful, post-frac gas flows from a multistage, fracture stimulated, laterally drilled, shale gas well in Australia.
This paper details the data collected in the vertical pilot well and observations and implications of in situ stress magnitudes and varying natural fracturing azimuths had on the drilling and subsequent hydraulic fracturing treatment of the lateral wellbore. In addition, we will present our recommendations for future well targeting and treatment strategies for this area and recommendations for shale gas exploration and appraisal in other frontier basins.
The Paleoproterozoic Isa Superbasin (1780Ma to 1550Ma) is located in northwest Queensland and in the northeast of the Northern Territory of the Western Fold Belt Province of the Mount Isa Orogen, Australia (see Fig. 1). Detailed summaries of the geology of the area were given by Blake et al., (1987, 1990 and 1992),1,2,3 definition, structure and petroleum geology are compiled by McConachie et al (1993)4 and more recent geological summaries by the Queensland Department of Mines and Energy and Queensland Geological Survey (2000-2010).5 The Mount Isa Basin (McConachie et al, 1993) is approximately 7200 km². A vast portion of the basin is covered by intracratonic sediments of the South Nicholson (1580Ma-1430Ma), Georgina (850Ma-355Ma) and Carpentaria Basins (205Ma-65Ma), bounded in the north by the Murphy Inlier basement complex (1870Ma-1840M) and to the south the complex Elizabeth Creek thrust belt (1640Ma-1590Ma). Dating of basin phases in the Western Fold Belt and their implication for basin development was reported by Page & Sweet (1998).6