|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Abstract Australia is uniquely positioned globally as a major energy provider, but this comes with multiple challenges that must be overcome to realize its full potential. LNG developments that are nearing fruition are set to make Australia the largest supplier of LNG in the world. The Asian LNG market continues to be the growth market. The development of the world's first coal bed methane (coal seam gas) to LNG projects on the east coast has created a robust east coast LNG export market, which in the near future is expected to coincide with domestic energy shortages arising from low exploration activity, maturing fields, higher costs, the interaction of government policy, commercial decisions and activism. As a result, unique approaches to project management and community relations have been developed that are complementary to the Australian consumer's needs for reliable, affordable and cleaner energy. The east coast demand for gas is likely to trigger new development of onshore Northern Territory gas in the short term, if political opposition can be managed. In Western Australia, new approaches leverage technologies such as floating LNG, and more utilization of existing infrastructure and plant capacity to achieve lower costs. This paper outlines Australia's natural gas supply & demand and the challenges to be faced in the coming years.
This paper assesses regulatory rules associated with drilling and completions activities in Queensland unconventional oil and gas plays. This assessment is based on a typology that classified rules into defined categories, defining their structure and what types of activities are required to assure them. This paper also reviewed a sample of ‘as built’ Well Completion Reports (WCR) to understand the self-assurance activities conducted by operating companies as well as to identify trends in compliance against a sample of rules. The typology assessment identified that rulemaking was generally consistent across documents, and a clear balance existed between rules focused on design and rules focused on field operations. The assessment also identified the actual wording of rules could benefit by more standardisation in some areas. Importantly, this assessment also identified the large volume of complex assurance activities faced by inspectors. The ‘as built’ data review identified a clear commitment to the written rules and evidence of self-assurance activities being consistently conducted by operators. This review also confirmed the value of WCR analysis and the potential to use them to measure compliance. Whilst this paper has provided valuable insight into rule making and the approach to self-assurance taken by some operators, there are many areas of the wider regulatory system that would be well served by further analysis. This paper has proposed some recommendations for such analysis to help make a more holistic assessment of effectiveness in the future.
Abstract Shale plays have created the current natural gas boom in the United States (US) and according to the national Energy Information Administration (EIA, 2013)49 produced 47% of total daily production by the end of 2013 (approximately 31.8 Bscf/d). Extensive production data from thousands of wells are now available for analysis to provide potential benchmark information for the Australian shale gas industry, which is still in its infancy. This paper focusses on analysis of publicly available US production data from horizontal wells in five depositional basins reported for the Barnett, Eagle Ford, Fayetteville, and Haynesville shale plays. Type-wells are evaluated which allow estimation of a range of representative initial gas production rate and technical Estimated Ultimate Recovery (EUR) characteristics. The analysis also results in generic recommendations for the minimum sample size and duration required for statistically significant well appraisal programs in shale plays. Such activity phases' primary objective should be to efficiently obtain reasonably reliable type-well performance indicators. The US shale plays' experiences to date provide insight concerning this aspect. Variability in geological factors including, but not limited to: stress regime, total organic content, thermal maturity, porosity, brittleness, natural fractures, and reservoir pressure can result in production performance that differs substantially both within and between shale plays. Also affecting performance is how the wells are completed. The geology of shale formations is discussed along with recent Australian operational activity, geomechanical considerations, and example economics. Analyses of the US data provide potential technical and economic benchmarks for preliminary comparisons to be made with Australian information, and may help to demonstrate the economic resilience required for exploitation of prospective shale gas resources. However, it must be recognised that the likely performance characteristics of the prospective Australian shale plays' type-wells are not currently well understood due to lack of data. Significant exploration and appraisal activity is needed to augment the extremely limited shale gas well performance data available in Australia to date.
Kuila, Utpalendu (Cairn Oil & Gas, Vedanta Ltd.) | Sahoo, Ajit (Cairn Oil & Gas, Vedanta Ltd.) | Jenkins, Creties (Rose and Associates LLP.) | Dev, Tania (Cairn Oil & Gas, Vedanta Ltd.) | Dutta, Sandipan (Cairn Oil & Gas, Vedanta Ltd.) | Batshas, Siddhant (Cairn Oil & Gas, Vedanta Ltd.) | Wilhelm, Chandler (Wilhelm Geoscience Services, LLC) | Brown, P. Jeffrey (Rose and Associates LLP.) | Mandal, Arpita (Cairn Oil & Gas, Vedanta Ltd.) | Dasgupta, Soumen (Cairn Oil & Gas, Vedanta Ltd.) | Mishra, Premanand (Cairn Oil & Gas, Vedanta Ltd.)
The Lower Barmer Hill (LBH) Member of Barmer Hill Formation is the major regional source rock in Barmer basin of Rajasthan and has sourced nearly all the discovered fields. Our previous studies helped to identify the geochemical potential of the LBH as a shale play. Its considerable thickness (50m-800m), high organic richness (6-14 wt.%) and optimum thermal maturity as indicated by vitrinite reflectance (VRo up to 1.7%) makes it a potential unconventional shale play. However, many other questions need to be answered before exploration wells can be drilled. In this paper, we have addressed those important questions and the associated workflow for answering them, with an emphasis upon 1) delineating the prospective areas, 2) estimating prospective resource volumes in these areas, and 3) estimating the chance of commerciality.
We have adopted a play-based approach to identify prospective areas in the northern part of the basin. The LBH shale was divided into two play types (oil and gas) based on thermal maturity ranges of 0.7-1.1% VRo and 1.1-2% VRo respectively. The less prospective areas were eliminated by applying global cut-offs for thickness (>30m) and TOC (>3 wt.%). Finally, the fault segments and the gross depositional environment (GDE) map guided the subdivision of each play type into play segments. A total of 8 play segments (five oil and three gas play segments) were delineated for further exploration.
We then estimated the hydrocarbons-in-place and prospective resources of each play segment. Each play segment was subdivided into sub-play segment polygons based on five different thermal maturity windows corresponding to different hydrocarbon phases. The probability distribution of in-place volumes and technically recoverable resources (TRR) for individual sub-play segment polygon was generated using a reservoir hydrocarbon pore volume and recovery factor approach. Next, we compute the minimum breakeven estimated ultimate recovery (EUR) on a single well basis assuming an economic hurdle of zero NPV10 and production type curves from North American analog shale plays. The chance of meeting or exceeding this EUR for the average well (economic chance of success or ECOS) was then computed for each sub play segment. The 1U, 2U, and 3U Prospective Resources for the play segment were estimated by probabilistically aggregating the TRR distribution of its’ constituent sub-play polygons incorporating risk dependencies. The aggregated Prospective Resources numbers and the chance of success, along with other strategic parameters, help to rank the 8 play segments to high-grade projects for exploration drilling.
Abstract The objective of this research was to identify hydraulic fracturing regulations from a range of jurisdictions, verify the grounds for regulatory intervention within the scientific literature and categorize the statements according to the geospatial application. Specific regulations constraining aspects of hydraulic fracturing activities from jurisdictions across the world were collated to identify common features relating to environmental protection, administrative requirements and grammatical structure. Regulations from 55 jurisdictions including states in the US, provinces in Canada, Australian states, European countries, Africa and South America were assessed and common focus areas identified, allowing for the development of a regulatory suite of universal application. Regulations could be ascribed to partitions of the environment including the lithosphere, the atmosphere, the hydrosphere, biosphere and the social framework. Some 32 distinct elements were identified as frequent constraints to hydraulic fracturing located in three geospatial zones: off-site; wellsite; and, wellhead. The scientific literature for each of these areas was critically assessed and summary reviews developed as a comprehensive and wide ranging review of environmental impacts. The specific use of open ended risk regulation as part of control documents (a permit or regulatory framework) appears to have been promoted as a catch-all in the absence of knowledge within the regulatory agency as if there is a lack of evidence supporting directed regulation. As an output of this research a Driver-Pressure-State-Impact-Response model was developed reflecting the substantial literature base that extends well back into the 1970s, with the initial development of coalbed methane in the Rockies and the Southern States and since the 1990s with shale. The paper calls into question claims of "We don't know enough".