Completion, Perforating and Hydraulic Fracturing Design Changes Yield Success in an Area of Problematic Frac Placement - the Cooper Basin, Australia

2002 ◽  
Author(s):  
Raymond L. Johnson ◽  
Keong P. Aw ◽  
David Ball ◽  
Mike Willis
Keyword(s):  
Hydraulic Fracturing ◽  
Design Changes ◽  
Cooper Basin

Geological and Bioregional Assessments: a tale of two basins

2021 ◽  
Vol 61 (2) ◽  
pp. 491
Author(s):  
Cameron R. Huddlestone-Holmes ◽  
Kate Holland ◽  
Luk J. M. Peeters
Keyword(s):  
Hydraulic Fracturing ◽  
Mitigation Measures ◽  
Unconventional Gas ◽  
Well Integrity ◽  
Surface Disturbance ◽  
Regulatory Regimes ◽  
Local Geology ◽  
Unconventional Gas Development ◽  
Cooper Basin ◽  
Stimulation Of

The Australian Government’s $35.4 million Geological and Bioregional Assessment (GBA) Program is assessing the potential impacts of shale, tight and deep coal gas development on water and the environment in the Beetaloo, Isa and Cooper GBA regions. This paper compares the outcomes of impact assessments for the Beetaloo and Cooper GBA regions, highlighting the role that local geology, hydrogeology, ecology and regulatory regimes play when assessing potential impacts of unconventional gas development. Unconventional gas development activities between basins are broadly consistent, involving drilling, stimulation of the reservoir (typically through hydraulic fracturing), production and processing of hydrocarbons, export to market and decommissioning and rehabilitation. The characteristics of these activities and their potential impacts are strongly influenced by local factors including the geology, environment, industry practices and regulatory regimes. While subsurface impacts associated with hydraulic fracturing and well integrity are considered unlikely in both regions, regional geology means there is greater stratigraphic separation between target resources and overlying aquifers in the Beetaloo Sub-basin than in the Cooper Basin. Local ecological conditions and species influence the nature of potential impacts on protected matters in the two basins, which are mostly associated with surface disturbance and spills or accidental release of fluids. A key similarity between the two regions is the broadly consistent regulation and management of potential impacts in the two basins. Preliminary results of the causal network analysis indicate that mitigation measures are available for all pathways in which unconventional gas resource development activities may have the potential to impact on endpoints.

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.

Design and optimisation of multi-stage hydraulic fracturing in a horizontal well in a shale gas reservoir in the Cooper Basin, South Australia

2015 ◽  
Vol 55 (1) ◽  
pp. 1 ◽  
Author(s):  
Kunakorn Pokalai ◽  
Yang Fei ◽  
Maqsood Ahmad ◽  
Manouchehr Haghighi ◽  
Mary Gonzalez
Keyword(s):  
Hydraulic Fracturing ◽  
Shale Gas ◽  
Horizontal Well ◽  
Productivity Index ◽  
Stress Profile ◽  
Stress Regime ◽  
Vertical Well ◽  
Fracture Simulation ◽  
Multi Stage ◽  
Cooper Basin

Multi-stage hydraulic fracturing in horizontal wells is a well-known technology and is a key mechanism for gas recovery from extremely low permeable shale gas reservoirs. Since Australia’s Cooper Basin has a more complex stress regime and higher temperatures when compared to US shale gas formations, the design and optimisation of this technology in the Cooper Basin has not been explored to the authors’ knowledge. The Murteree and Roseneath shale formations in the Cooper Basin are 8,500 ft in depth and have been targets for shale gas production by different oil and gas operators. Deeper zones are difficult to fracture, as fracture gradients are often above 1 psi/ft. In this study, 1D vertical mechanical earth modelling using petrophysical log data was developed. Then, the stress profile was tuned and validated using the minimum horizontal stress from a mini-frac test taken along a vertical well. A 3D hydraulic fracture simulation in a vertical well as developed as a pilot to select the best locations for horizontal drilling. The selection criteria for the best location included the stress regime, gas flow rate and fracture geometry. Then a multi-stage fracture treatment in a horizontal well was designed. A large number of cases were simulated based on different well lengths, stage spacing and the number of stages. The productivity index was selected as the objective function for the optimisation process. The best case finally was selected as the optimum multi-stage hydraulic fracturing in a horizontal well in the Cooper Basin.

Monitoring shale gas resources in the Cooper Basin using magnetotellurics

Geophysics ◽  
2016 ◽  
Vol 81 (6) ◽  
pp. A13-A16 ◽  
Author(s):  
Nigel Rees ◽  
Simon Carter ◽  
Graham Heinson ◽  
Lars Krieger
Keyword(s):  
Hydraulic Fracturing ◽  
Shale Gas ◽  
South Australia ◽  
Depth Range ◽  
Bulk Conductivity ◽  
Gas Reservoirs ◽  
Horizontal Fracture ◽  
Fluid Permeability ◽  
Fracturing Fluids ◽  
Cooper Basin

The magnetotelluric (MT) method is introduced as a geophysical tool to monitor hydraulic fracturing of shale gas reservoirs and to help constrain how injected fluids propagate. The MT method measures the electrical resistivity of earth, which is altered by the injection of fracturing fluids. The degree to which these changes are measurable at the surface is determined by several factors, such as the conductivity and quantity of the fluid injected, the depth of the target interval, the existing pore fluid salinity, and a range of formation properties, such as porosity and permeability. From an MT monitoring survey of a shale gas hydraulic fracture in the Cooper Basin, South Australia, we have found temporal and spatial changes in MT responses above measurement error. Smooth inversions are used to compare the resistivity structure before and during hydraulic fracturing, with results showing increases in bulk conductivity of 20%–40% at a depth range coinciding with the horizontal fracture. Comparisons with microseismic data lead to the conclusion that these increases in bulk conductivity are caused by a combination of the injected fluid permeability and an increase in wider scale in situ fluid permeability.

A Cooper Basin simulation study of flow-back after hydraulic fracturing in tight gas wells

2016 ◽  
Vol 56 (1) ◽  
pp. 369 ◽  
Author(s):  
Sume Sarkar ◽  
Manouchehr Haghighi ◽  
Mohammad Sayyafzadeh ◽  
Dennis Cooke ◽  
Kunakorn Pokalai ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
History Matching ◽  
Flow Simulation ◽  
Gas Production ◽  
Fluid Injection ◽  
Drainage Pattern ◽  
Gas Wells ◽  
Sweep Efficiency ◽  
Fracture Fluid ◽  
Cooper Basin

After fluid injection (slickwater) during hydraulic fracturing, the flow-back of fracture fluid is necessary before gas production starts. A review of fracture treatments indicates that the incomplete return of treating fluids is a reason for the failure of hydraulic fracturing and is associated with poor gas production. The aim of this study is to investigate the parameters that limit flow-back in low permeability gas wells in the Cooper Basin. The authors used numerical simulation to find the critical controlling parameters to introduce the best practice for maximising the flow-back in the Cooper Basin. Several 3D and multiphase flow simulation models were constructed for three wells in the Patchawarra Formation during fracture fluid injection, soaking time and during flow-back. All models were validated using history matching with the production data. The results show that the drainage pattern is distinctly different in the following directions: vertically upward, vertically downward, and horizontal along the fracture half-length and along the matrix. The lowest recovery is observed during the upward vertical displacements due to poor sweep efficiency. Furthermore, it is observed that drawdown does not influence the recovery significantly for upward displacements. Surface tension reduction, however, can improve sweep efficiency and improve recovery considerably. Also, the wettability of the rocks has a significant impact on ultimate recovery when the effect of gravity is dominant. The authors conclude that a significant amount of injected fluid is trapped in the formation because of poor sweep efficiency and formation of gas fingers, which results from low mobility ratio and gravity segregation.

PETROLEUM AND HOT DRY ROCK: TWO TYPES OF ENERGY SHARING COMMONALITIES

1998 ◽  
Vol 38 (1) ◽  
pp. 830 ◽  
Author(s):  
S.P. Narayan ◽  
D. Naseby ◽  
Z. Yang ◽  
S.S. Rahman
Keyword(s):  
Fracture Mechanics ◽  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Geothermal Energy ◽  
Petroleum Industry ◽  
Gas Production ◽  
Tight Gas ◽  
Mode Fracture ◽  
Hot Dry Rock ◽  
Cooper Basin

The Cooper Basin is the largest gas-producing basin in Australia and hosts a huge volume of natural gas in low permeability (known as 'tight gas') sandstone formations. Hydraulic fracture treatments, based on 'opening mode' fracture mechanics, are routinely carried out to unlock tight gas and to accelerate its recovery. Information regarding insitu stresses and natural fractures is required for successful fracture treatments. However, hydraulic fracturing is still often problematic, in part due to the relatively high insitu stresses and temperatures in the region. A vast amount of Hot Dry Rock (HDR) geothermal energy resources exists in granites below the sedimentary rocks in the Cooper Basin. Exploitation of HDR requires the same drilling and completion technologies as used in the petroleum industry. Hydraulic fracturing is also necessary for HDR reservoir creation, and requires characterisation of insitu stresses and natural fractures, as does tight gas production. It has been realised that the mechanism for reservoir stimulation in granitic rocks is proppant free shear dilation that is related to 'sliding mode' fracture mechanics. Furthermore, seismic imaging of hydraulic fracture propagation is well established in the HDR industry. These two technologies, developed in HDR, may have potential application to the petroleum industry for tight gas production. The geographic proximity of tight gas and HDR geothermal energy in the Cooper Basin and common exploitation technologies should justify close collaboration between the petroleum industry and HDR researchers.

Investigating Hydraulic Fracturing in Tight Gas Sand and Shale Gas Reservoirs in the Cooper Basin

2013 ◽  
Author(s):  
Michael Paul Scott ◽  
Tim Stephens ◽  
Richard Durant ◽  
James McGowen ◽  
Warwick Thom ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Shale Gas ◽  
Tight Gas ◽  
Gas Reservoirs ◽  
Shale Gas Reservoirs ◽  
Cooper Basin
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