Well Trajectory, Completion and Fracture Design Changes Improve Execution for Deep Unconventional Tight Gas Targets in the Cooper Basin, Australia

2019 ◽  
Author(s):  
Raymond L. Johnson ◽  
Ruizhi Zhong ◽  
Lan Nguyen
Keyword(s):  
Tight Gas ◽  
Design Changes ◽  
Well Trajectory ◽  
Gas Targets ◽  
Cooper Basin

Results of hydraulic fracturing design improvements and changes in execution strategies for unconventional tight gas targets in the Cooper Basin, Australia

2019 ◽  
Vol 59 (1) ◽  
pp. 244
Author(s):  
Raymond Johnson Jr ◽  
Ruizhi Zhong ◽  
Lan Nguyen
Keyword(s):  
Machine Learning ◽  
Hydraulic Fracturing ◽  
Horizontal Stress ◽  
Learning Model ◽  
Hydraulic Fractures ◽  
Tight Gas ◽  
Machine Learning Model ◽  
Wellbore Pressure ◽  
Gas Targets ◽  
Cooper Basin

Tight gas stimulations in the Cooper Basin have been challenged by strike–slip to reverse stress regimes, adversely affecting the hydraulic fracturing treatment. These stress conditions increase borehole breakout and affect log and cement quality, create more tortuous pathways and near-wellbore pressure loss, and reduce fracture containment. These factors result in stimulation of lower permeability, low modulus intervals (e.g. carbonaceous shales and interbedded coals) versus targeted tight gas sands. In the Windorah Trough of the Cooper Basin, several steps have been employed in an ongoing experiment to improve hydraulic fracturing results. First, the wellbore was deviated in the maximum horizontal stress direction and perforations shot 0 to 180° phased to better align the resulting hydraulic fractures. Next, existing drilling and logging-while-drilling data were used to train a machine learning model to improve reservoir characterisation in sections with missing or poor log data. Finally, diagnostic fracture injection tests in non-pay and pay sections were targeted to specifically inform the machine learning model and better constrain permeability and stress profiles. It is envisaged that the improved well and perforation alignment and better targeting of intervals for the fracturing treatment will result in lowered tortuosity, better fracture containment, and higher concentrations of localised proppant, thereby improving conductivity and targeting of desired intervals. The authors report the process and results of their experimentation, and the results relative to the offsetting vertical well where a typical five-stage treatment was employed.

Unconventional gas prospectivity of the Cooper Basin

2015 ◽  
Vol 55 (2) ◽  
pp. 428 ◽  
Author(s):  
Lisa Hall ◽  
Tony Hill ◽  
Liuqi Wang ◽  
Dianne Edwards ◽  
Tehani Kuske ◽  
...  
Keyword(s):  
Source Rocks ◽  
System Modelling ◽  
Hydrocarbon Generation ◽  
Tight Gas ◽  
Unconventional Gas ◽  
Upper Carboniferous ◽  
Gas Market ◽  
Intracratonic Basin ◽  
Exploration Activity ◽  
Cooper Basin

The Cooper Basin is an Upper Carboniferous–Middle Triassic intracratonic basin in northeast SA and southwest Queensland. The basin is Australia's premier onshore hydrocarbon-producing province and is nationally significant due to its provision of domestic gas for the east coast gas market. Exploration activity in the region has recently expanded with numerous explorers pursuing newly identified unconventional hydrocarbon plays. While conventional gas and oil prospects can usually be identified by 3D seismic, the definition and extent of the undiscovered unconventional gas resources in the basin remain poorly understood. This extended abstract reviews the hydrocarbon prospectivity of the Cooper Basin with a focus on unconventional gas resources. Regional basin architecture, characterised through source rock distribution and quality, demonstrates the abundance of viable source rocks across the basin. Petroleum system modelling, incorporating new compositional kinetics, source quality and total organic carbon (TOC) map, highlight the variability in burial, thermal and hydrocarbon generation histories between depocentres. The study documents the extent of a number of unconventional gas play types, including the extensive basin-centred and tight gas accumulations in the Gidgealpa Group, deep-dry coal gas associated with the Patchawarra and Toolachee formations, as well as the less extensive shale gas plays in the Murteree and Roseneath shales.

Exploiting the Cooper Basin: conventional lessons and appropriate analogues to guide an unconventional future

2018 ◽  
Vol 58 (1) ◽  
pp. 339
Author(s):  
Brenton Richards ◽  
Alexander Côté
Keyword(s):  
Development Strategy ◽  
Horizontal Well ◽  
Tight Gas ◽  
Vertical Wells ◽  
Gas Field ◽  
The Status ◽  
Potential Reservoir ◽  
Capital Efficiency ◽  
Gas Potential ◽  
Cooper Basin

Over the past decade, there has been a paradigm shift in the exploitation strategy in North American tight gas plays from vertical to horizontal wells. This shift has yet to occur in Australia. The Cooper Basin has vast amounts of contingent and prospective tight gas resources that have yet to be unlocked commercially. These resources continue to be developed primarily with hydraulic fracture stimulated vertical wells. Operators have yet to challenge the status quo and test the Cooper Basin tight gas potential with a drilled, completed and tested horizontal well. There are many advantages to horizontal well developments, from the ability to target a specific high graded reservoir unit to increased capital efficiency. Operators need to break away from convention and take a new approach to Cooper Basin tight gas exploration and development in the quest to demonstrate commerciality. A review of the inherent challenges in Cooper Basin gas field developments and the current exploitation strategies employed in analogous tight gas plays have been integrated to produce a pragmatic workflow to identify potential reservoir units that would benefit from a change in development strategy.

An overview of the new Geological and Bioregional Assessments Program

2018 ◽  
Vol 58 (2) ◽  
pp. 625 ◽  
Author(s):  
Anthony Swirepik ◽  
Andrew Stacey ◽  
Rod Dann
Keyword(s):  
Environmental Impacts ◽  
East Coast ◽  
Tight Gas ◽  
Environmentally Sustainable ◽  
New Energy ◽  
Exploration And Production ◽  
Building Community ◽  
Three Stages ◽  
Gas Market ◽  
Cooper Basin

As part of the AU$86.3 million ‘Towards a New Energy Future’ package, the Australian Government has committed AU$30.4 million to undertake the Geological and Bioregional Assessments Program. This program aims to encourage sustainable gas development through a series independent scientific studies into the potential environmental impacts of shale and tight gas exploration and production. These studies, conducted by Geoscience Australia and CSIRO, supported by the Bureau of Meteorology and managed by the Department of the Environment and Energy, will focus on three basins (regions) that are prospective, but underexplored for shale and tight gas. The program seeks to encourage exploration to bring new gas resources to the East Coast Gas Market within the next 5–10 years, increase the understanding of the potential environmental impacts posed by gas developments and increase the efficiency of assessment, monitoring and ongoing regulation, including improved data capture and reporting. The Cooper Basin and the Isa Superbasin have been selected for investigation with a third basin expected to be announced by mid-2018. The program will be delivered in three stages over 4 years and will investigate areas prospective for shale and tight gas within these regions. This independent, transparent, science-based approach aims to assist in building community understanding of, and confidence in, the capacity for safe and environmentally sustainable unconventional gas developments.

Next steps to crack the code on tight Permian Toolachee and Patchawarra sandstones of the Cooper Basin, southwest Queensland

2016 ◽  
Vol 56 (2) ◽  
pp. 533 ◽  
Author(s):  
Raymond L. Johnson ◽  
Lan Nguyen ◽  
Terry Russell
Keyword(s):  
Shale Gas ◽  
North American ◽  
Organic Content ◽  
Tight Gas ◽  
Gas Reservoirs ◽  
Stimulated Reservoir Volume ◽  
Reservoir Volume ◽  
Using Data ◽  
Rock Mechanical Properties ◽  
Cooper Basin

Historic wells drilled by Real Energy Corporation Limited (Real Energy) in the Windorah Trough (Cooper Basin, southwest Queensland) characterised the Toolachee and Patchawarra formations as being gas-charged, tight-gas, sandstone/lacustrine shale sequences having layers of coaly source rock with high total organic content and moderate hydrocarbon indices. Consistent with being tight-gas reservoirs, drill stem tests have mostly either failed to produce gas or resulted in non-commercial flow rates. To date, North American methodologies for tight and shale gas extraction have not been consistently successful when applied in non-normal stress regimes outside of North America (i.e. Cooper Basin, China, Poland, Middle East, etc). Real Energy anticipated that North American technologies and practices were not likely to be directly applicable, as noted by published case studies for Australian shale gas wells (Johnson and Greenstreet, 2003; Pitkin et al, 2012; Scott et al, 2013; Johnson et al, 2015). Thus, it became an imperative to evaluate any methodologies or technologies more applicable for the Australian strike-slip to transpressional stress regimes to prevent fracture misalignment or disorientation, effects that result in ineffective fracture stimulation. Overall, a more scientific approach must be applied to developing and understanding the most efficient reservoir stimulation processes (e.g. drilling techniques, rock mechanical properties determination, well azimuth, perforating schema, and well interval selection) to optimise the stimulated reservoir volume (SRV). In this extended abstract the authors take the first steps at defining the stimulation strategies required for these tight sandstones using data and results from two case study wells. The authors outline the well observations and report key lessons in a cooperative spirit to solicit industry feedback and further technologies that can aid development of fit-for-purpose technologies to facilitate extraction of these largely untapped resources across the undeveloped troughs and flanks of the Cooper Basin.

MASSIVE HYDRAULIC FRACTURE STIMULATION OF EARLY PERMIAN GAS RESERVOIRS, BIG LAKE FIELD, COOPER BASIN

1984 ◽  
Vol 24 (1) ◽  
pp. 180
Author(s):  
D. J. Stanley ◽  
G. Halliday
Keyword(s):  
Hydraulic Fracture ◽  
Joint Venture ◽  
Oil And Gas ◽  
Gas Production ◽  
Tight Gas ◽  
Gas Reservoirs ◽  
Potential Resource ◽  
Primary Porosity ◽  
Initial Results ◽  
Cooper Basin

In 1981, South Australian Oil and Gas Corporation Pty Ltd commenced a project to apply Massive Hydraulic Fracture (MHF) technology to the tight gas reservoirs of the Tirrawarra and Patchawarra Formations of the Big Lake Field. Four wells had defined the potential at depths of 8500-10 000 ft (2500-3000 m) in the early 1970s but early attempts to stimulate gas production were unsuccessful.The Tirrawarra Sandstone, as a massive unit of 120-200 ft (35-60 m) thickness, was a prime candidate. The Patchawarra sandstones, ranging up to 40 ft (12 m) thick and interbedded with shales and coals, presented a more difficult problem.Petrologic analysis disclosed quartz sandstones in which the pore system consists mainly of large irregularly shaped dissolution pores. Diagenesis has destroyed primary porosity and precipitated authigenic illite, illite-smectite, kaolinite and siderite. The gas contains 32 per cent CO2 and is very dry. Temperatures are close to 400°F (200°C). The formations are overpressured.The project has drilled two wells, Big Lake 26 and 27, and applied two MHF treatments in Big Lake 26. One further MHF remains to be done in Big Lake 27. Each MHF treatment has been tailored to the particular petrologic, reservoir, stratigraphic, pressure and temperature conditions of that zone. The tailoring of MHF design has been further refined by running a 'mini-frac' with 10 000 gal (45 000 L) of fluid. MHF designs have involved up to 620 000 lb (280 000 kg) of sand, 60 000 lb (27 000 kg) of sintered bauxite and 300 000 gal (1350 kL) of gel. Having management on-site to react to aberrations and vary the design has been important in operations.One Tlrrawarra Sandstone MHF has been unsuccessful (as predicted) and the other, on initial results, appears highly successful. The Patchawarra Formation MHF speared off into a coal but appears moderately successful. Long-term flow tests will provide definitive results.Encouraged by these initial results, the Joint Venture Partners have drilled two further wells in the Big Lake Field which await MHF treatment. The gas-in-place is estimated at about 1.5 trillion cubic feet (42.5 billion cubic metres). Three other tight gas prospects of similar size, Burley, McLeod and Kirby, have been identified. The size of this potential resource provides a strong incentive to attempt to make MHF treatments economically viable in the Cooper Basin.

Geological and Bioregional Assessments: assessing the prospectivity for tight, shale and deep-coal resources in the Cooper Basin, Beetaloo Subbasin and Isa Superbasin

2021 ◽  
Vol 61 (2) ◽  
pp. 477
Author(s):  
Lisa S. Hall ◽  
Meredith L. Orr ◽  
Megan E. Lech ◽  
Steven Lewis ◽  
Adam H. E. Bailey ◽  
...  
Keyword(s):  
East Coast ◽  
Sedimentary Basins ◽  
Tight Gas ◽  
Department Of Agriculture ◽  
Development Scenarios ◽  
Causal Pathways ◽  
Detailed Assessment ◽  
Gas Market ◽  
Stage 1 ◽  
Cooper Basin

The Geological and Bioregional Assessment Program is a series of independent scientific studies undertaken by Geoscience Australia and the CSIRO, supported by the Bureau of Meteorology, and managed by the Department of Agriculture, Water and the Environment. The program consists of three stages across three regions with potential to deliver gas to the East Coast Gas Market. Stage 1 was a rapid regional prioritisation conducted by Geoscience Australia, to identify those sedimentary basins with the greatest potential to deliver shale and/or tight gas to the East Coast Gas Market within the next 5–10 years. This prioritisation process assessed 27 onshore eastern and northern Australian basins with shale and/or tight gas potential. Further screening reduced this to a shortlist of nine basins where exploration was underway. The shortlisted basins were ranked on a number of criteria. The Cooper Basin, the Beetaloo Subbasin and the Isa Superbasin were selected for more detailed assessment. Stage 2 of the program involved establishing a baseline understanding of the identified regions. Geoscience Australia produced regional geological evaluations and conceptualisations that informed the assessment of shale and/or tight gas prospectivity, ground- and surface-water impacts and hydraulic fracturing models. Geoscience Australia’s relative prospectivity assessments provide an indication of where viable petroleum plays are most likely to be present. These data indicate areal and stratigraphic constraints that support the program’s further work in Stage 3, on understanding likely development scenarios, impact assessments and causal pathways.

A comparison of competing amplitude variation with offset techniques applied to tight gas sand exploration in the Cooper Basin of Australia

2015 ◽  
Vol 3 (3) ◽  
pp. SZ15-SZ26 ◽  
Author(s):  
Stephanie Tyiasning ◽  
Dennis Cooke
Keyword(s):  
Random Noise ◽  
Class I ◽  
Rock Properties ◽  
Tight Gas ◽  
Amplitude Variation ◽  
Amplitude Variation With Offset ◽  
Optimal Rotation ◽  
Elastic Impedance ◽  
Synthetic Modeling ◽  
Cooper Basin

We have developed a tight gas amplitude variation with offset (AVO) case history from the Cooper Basin of Australia that addressed the exploration problem of mapping thin fluvial tight gas sand bodies. In the Cooper Basin, Permian Toolachee and Patchawarra sands are difficult to interpret on seismic data due to strong reflections from adjacent Permian coals. This is not the common AVO problem of distinguishing between coal and gas sand, but a more difficult class-I AVO problem of mapping fluvial sands beneath a sheet coal that varies in thickness. We have reviewed local rock properties and concluded that Poisson’s ratio is probably the most appropriate rock property to solve the above exploration problem. We have compared various seismic attributes made using the extended elastic impedance (EEI) technique and a rotation of near and far partial stacks. In a synthetic modeling study that included random noise and tuning, we compared the noise-discrimination abilities of three competing AVO crossplot techniques and “rotated” the attributes made from them. These three crossplots were as follows: intercept versus gradient (I-G), full-stack versus far-minus-near (Full-FmN), and near-stack versus far-stack (N-F). Previous papers on this subject have found that (I-G) crossplots had a spurious correlation in the presence of noise that did not occur with the (Full-FmN) and (N-F) crossplots. We found that for our class-I AVO case, (1) the advantage of the (Full-FmN) and (N-F) crossplots disappeared in the presence of tuning, (2) if tuning was present, the optimal rotation angle was determined by the “tuning angle,” not by the noise angle or some desired EEI angle, and (3) if the three different crossplots were rotated by their respective “tuning” angles, the results were identical.

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