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Queensland
Unconventional reservoirs have always posed a myriad of engineering conundrums to solve to develop the vast resources contained in these challenging formations. Since the early 2000s, when macroeconomics and demand set the stage for "the great shale race," energy companies have looked to technology to unlock these resources. As the demand for energy continues to increase, so does the sociopolitical demand that these resources be produced in a sustainable way. This reflective thought has defined this month's selection of technical papers, each speaking to a different facet of this feature's theme: unconventional reservoir development for a sustainable energy transition. Starting with what we've learned with over 2 decades of unconventional exploration and development, there are many lessons the industry can apply across a wide variety of reservoir types and locations.
- North America > Canada (0.54)
- Oceania > Australia > Queensland (0.19)
- Oceania > Australia > Queensland > Central Highlands > Bowen Basin (0.99)
- North America > United States > West Virginia > Appalachian Basin (0.99)
- North America > United States > Virginia > Appalachian Basin (0.99)
- (8 more...)
Predicting Weathered Rock Properties Using Integrated Geophysics and Laboratory Testing Approach
Shi, Z. (The University of Queensland) | Flottmann, T. (The University of Queensland) | Millen, M. (Queensland University of Technology) | Pidgeon, B. (The University of Queensland) | Huang, Y. (The University of Queensland) | Chen, Z. (The University of Queensland)
ABSTRACT Reliable estimation of the mechanical properties (e.g., strength) of weathered rocks is critical for taking proactive measures, such as adjusting mud weight density and/or drilling parameters, to achieve safe and efficient infill drilling. Currently, the common approach to estimating rock properties is to use its regression with geophysical logs, particularly the sonic velocity. Such an approach was challenged when applied to shallow and heavily weathered bedrocks accompanied by high porosity and water saturation and low density. The preserved drill cores from the previous drilling of adjacent wells offer an opportunity to correlate laboratory results with borehole logging data to estimate rock properties and identify high-risk drilling horizons. In this work, 196 cylindrical drill cores with an average diameter of 89.25 mm from the depth between 35 m and 396 m were prepared for uniaxial compressive strength (UCS) and Brazilian tensile strength tests. Sample characterization on each sample was also conducted, including density, porosity, P- and S-wave velocities, and static and dynamic elastic moduli. Compared with the logging P-wave velocities, the laboratory P-wave values are consistently lower by 32.7% on average, especially for shallow rock cores, which likely reflects the impact of water moisture, further weathering and in-situ compaction stress. The characterisation results were then used as inputs to correlate with rock UCS and tensile strengths, which were found to be well correlated with the depth, density, P- and S-wave velocities, and elastic modulus. This work provides useful experimental data sets of shallow weathered bedrocks and highlights the importance of including rock depth in the regression model for rock strengths. The developed correlations could be directly employed to forecast the mechanical properties of shallow rocks as well as being a guideline to identify high-risk weak rock facies, where are severely weathered and expect significant drilling challenges. INTRODUCTION The mechanical properties of in-situ reservoir rocks are key input parameters for geomechanical assessment of geoengineering applications such as well drilling and completion and wellbore stability. Accurate site investigation, including assessing rock strength, is essential prior to drilling to plan the most efficient and cost-effective activities (Kolapo, 2021). However, weathering constantly affects the strength of rock masses, particularly near the ground surface, posting a significant challenge for conducting engineering activities, such as drilling (Gupta and Seshagiri Rao, 2000; An et al., 2020). It is therefore crucial to reliably predict the mechanical strength of each rock layer, particularly the weathered zones, to achieve a safe and successful drilling operation.
- Oceania > Australia > Queensland (0.29)
- North America > United States > California (0.28)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Processing (0.70)
- Oceania > Australia > Queensland > Surat Basin (0.99)
- Oceania > Australia > New South Wales > Surat Basin (0.99)
- Asia > Middle East > Iraq > Basra Governorate > Arabian Basin > Widyan Basin > Mesopotamian Basin > Zubair Field > Zubair Formation (0.98)
- Asia > Middle East > Iraq > Basra Governorate > Arabian Basin > Widyan Basin > Mesopotamian Basin > Zubair Field > Mishrif Formation (0.98)
ABSTRACT Stress-strain based methods are frequently adopted in the literature to estimate crack initiation (CI) strength in rock. However, despite their widespread use, these methods can introduce subjective interpretations of the stress-strain curves, particularly in rocks with pre-existing microcracks or high porosity. This study aims to examine the subjectivity inherent in strain-based methods and its potential impact on consistent measurement of rock CI. A survey is then conducted using experimental data obtained from sandstone and granite specimens. Results suggest a wider scatter of CI values for sandstone samples, which aligns with expectations due to their inherent pore structure heterogeneity. The Lateral Strain Response (LSR) method demonstrates the least coefficient of variation, indicating less subjectivity. Further research and validation is recommended to improve confidence in the LSR method using parallel measurement techniques. INTRODUCTION In rock engineering, the crack initiation (CI) stress threshold refers to the stress level where new microcracks start to develop within the rock matrix. In practice, it has been demonstrated that the CI stress level can be used to estimate the strength of rock against spalling and rockburtst type failures in deep underground excavations (Martin, 1997; Diederichs, 2007). Further, the CI stress also provides an indication of the stress conditions where breakout can occur in boreholes and petroleum wellbores. The CI stress is usually recognised to be around 30 to 60% of the peak value measured during an Unconfined Compressive Strength (UCS) testing (Brace et al., 1966, Bieniawski 1967, Holcomb & Costin, 1986; Cai et al., 2004; Nicksiar & Martin 2013, Wen et al., 2018) There is a wide range of methods that are available to estimate the CI stress which includes several strain-based methods (SBMs), acoustic emissions (Keshtgar & Modarres, 2013), electrical resistivity (Lataste et al., 2003), digital image correlation (Dong & Pan, 2017), optical diffraction patterns (Li et al., 2002), laser speckle interferometry (Ennos, 1975), and ultrasonic probing (Mi et al., 2006). The strain-based methods are most common due to their low cost and simplicity (Mutaz et al., 2020). With these methods, the CI stress is interpreted from a characteristic change in the stress-strain response that is measured during compression loading.
- North America > United States (0.28)
- Oceania > Australia > Queensland (0.15)
- Research Report > New Finding (0.49)
- Research Report > Experimental Study (0.34)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.51)
- Energy > Oil & Gas (0.68)
- Materials > Metals & Mining (0.46)
Larissa Walker, SPE, graduated with honors from the University of Waterloo in 2005 with a Bachelor of Applied Science degree in geological engineering and began a career with Shell as a petrophysicist in Calgary. Her more than 18 years of energy industry experience covers a wide spectrum of unconventional resources including deep, sour gas carbonates; tight sand and shale plays of Western Canada; the Appalachian Basin shales in America; and coal seam gas in Eastern Australia. These complex assets provide the foundation of Walker’s deep technical and project management insight into the key elements that deliver value throughout each stage of a project’s life cycle. In her current role as technical lead, she is responsible for the front-end development for Shell in Queensland’s Bowen Basin Permian tight gas sand (TGS) assets. The success case delivery of the Bowen TGS Capital Project has the potential to sustain the existing Queensland Curtis LNG project while providing gas and liquids into the East Coast domestic market. Walker is a member of the JPT Editorial Review Board and can be reached at larissa.walker@shell.com.
- Oceania > Australia > Queensland > Central Highlands (0.29)
- North America > Canada > Alberta > Census Division No. 6 > Calgary Metropolitan Region > Calgary (0.29)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.64)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.64)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (0.64)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Coal seam gas (0.64)
- Management > Energy Economics > Unconventional resource economics (0.64)
- Facilities Design, Construction and Operation > Natural Gas Conversion and Storage > Liquified natural gas (LNG) (0.64)
Bed Boundary Mapping Technology Improves Coal Mining by Revealing Its Complex Geological Structures
Abeida, Hatem (Oliden Technology, LLC) | Li, Qiming (Oliden Technology, LLC) | Mather, Jim (Oliden Technology, LLC) | Zhong, Lili (Oliden Technology, LLC) | Patterson, Jason (AngloAmerican) | Woehling, Valentin (Lucas Drilling Pty Ltd.)
ABSTRACT Drilling horizontal wells in the coal mines in Central Queensland, Australia, is key to understanding the complex nature of the coal seams and their lateral extension prior to underground longwall mining. These coal seams are geologically complex with faulting, varying dips, and bed thinning frequently encountered. Consequently, the requirement arose for an advanced logging tool with the capacity to provide accurate geosteering, reveal complex geology, and ultimately improve footage within the coal seams. Conventional geosteering using gamma ray correlation with offset wells has been widely used in geosteering the horizontal section of these wells. The process of confirming coal seam structures involved a risky and time consuming process. It required branching out, logging shoulder beds, and then pulling back into the main bore to drill ahead, repeated a few times throughout drilling the horizontal section. Even though this might work in certain applications, the approach has some limitations when drilling these zones. It is reactive due to the shallow depth of investigation of gamma-ray measurements and the fact that the sensor may be located too far behind the bit to aid efficiency. More importantly, it involves the risk of drilling into the hazardous Tonstein bed. For the last three years, an advanced geosteering technique utilizing the deep reading directional resistivity tool has been used for bed boundary mapping in this high resistivity environment. The tool provides conventional propagation resistivity azimuthal gamma ray, and directional resistivity with a greater depth of detection than other tools in its class, through the use of longer Transmitter-Receiver spacing for directional antennas. Importantly, these directional measurements are available in all three frequencies (125KHz, 500KHz, and 2MHz) to allow a greater selection of measurements for structure inversion/interpretation optimal to the particular geology and application. Incorporating long spacing 2MHz directional resistivity measurements, the multilayer bed mapping technology confirmed and accurately interpreted structural changes in the coal seams where the top and bottom of the coal seam were mapped. The traditional method employed by the coal mining industry of detecting coal seams geometry relies on reactive steering, driving the need for multiple open hole sidetracks throughout the well. The bed boundary mapping technique has enabled the operator to overcome the limitations of the conventional geosteering technique. The outstanding result and gained experience gave the operator the confidence to run the tool and geosteering services in more wells to resolve the coal seams complex structures and map their boundaries. The inversion result provided geological insights into the coal seam structures. The improved geological model based on the inversion has shown that the coal seam is geologically complex and the correct delineation of its boundaries and identifying their precise true vertical depth (TVD) can add significant value to the planning, evaluation, and execution of mines.
- Oceania > Australia > Queensland (1.00)
- North America > United States (1.00)
- Europe (0.93)
- Oceania > Australia > Queensland > Clarence Moreton Basin (0.99)
- Oceania > Australia > Queensland > Central Highlands > Bowen Basin (0.99)
- Oceania > Australia > New South Wales > Gunnedah Basin (0.99)
- (4 more...)
Dr. Janelle Simpson is a Senior Geophysicist with the Geological Survey of Queensland in Australia. She has worked there over 10 years, overseeing collection of pre-competitive geophysical data to help support the mining industry. Over the last 5 years she has been primarily focused on collection and interpretation of magnetotelluric data to understand the crustal structure of the Mount Isa Province.
The present-day crustal in-situ stress field is of extreme importance for understanding both natural processes (e.g., understanding neotectonics, earthquake, and seismic hazard assessment) and anthropogenic activities (e.g., exploration and production of geothermal energy, groundwater, hydrocarbon, mineral resources, CO2, and hydrogen geo-storage). Analysis of the present-day stresses in numerous basins from across the world reveals that significant and complex variations in the present-day stress orientation are commonly observed at different scales. Mojtaba's lecture aims to investigate the pattern of crustal stress at different spatial scales to better evaluate the causes and consequences of contemporary stress in the earth's crust. In this conversation with host Andrew Geary, Mojtaba shares why it's necessary to understand the present-day crustal in-situ stress field, the impact of investigating crustal stress at different scales, and the causes and consequences of contemporary stress in the earth's crust. He also goes over the concept of stress mapping and what his years of experience studying basins have taught him. Dr. Mojtaba Rajabi is an ARC DECRA Fellow at the School of Earth and Environmental Sciences, University of Queensland.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Structural Geology > Tectonics > Plate Tectonics > Earthquake (0.57)
Reconciliation and Insights from a Holistic Reservoir Characterisation Program in a Late, Early-Oil to Early, Peak-Oil Window Shale Oil Play - Eromanga Basin, Australia
Richards, Brenton (Origin Energy) | Solano, Nisael (University of Calgary) | Baruch, Elizabeth (Tamboran Resources) | Gordon, John (University of Calgary) | Younis, Adnan (University of Calgary) | DeBuhr, Chris (University of Calgary) | Ghanizadeh, Amin (University of Calgary) | Stasiuk, Lavern (Stasiuk Petrography) | Bein, Cassandra (Origin Energy) | Mitchell, Brendon (Oceania Geo) | Clarkson, Christopher R. (University of Calgary) | Pedersen, Per (University of Calgary)
Abstract The objective of this work was to develop and apply integrated geological and experimental workflows to enable a holistic evaluation of the reservoir quality and potential producibility of a prospective shale oil play - the Toolebuc Formation (Eromanga Basin), Australia. Tight oil reservoirs are notoriously difficult to characterize; routine analytical and experimental methods developed for tight reservoir characterisation are prone to providing contradicting observations depending on the complexity of the reservoir. This paper explores the data collection methods and results from a calcareous, organic-rich shale and demonstrates the benefits of combing multiple analytical techniques in the early stages of resource appraisal. The Toolebuc Formation is within a late early oil to early peak oil window at the key well sites which, provide access to the most thermogenically mature material recovered for testing in the play to date. Routine shale core analysis data indicate significant gas-filled porosity, which is inconsistent with the anticipated fluid profiles for the optically determined thermal maturity window. Isotopic data collected on mud gas during drilling indicate biogenic signatures within the light-end hydrocarbon fractions; however, this isotopic signature was not present in the headspace gas of low-temperature hydrous pyrolysis (LTHP) experiments. These observations raise questions regarding the maturation pathway and associated fluid evolution for this source rock reservoir and whether apparent in-situ fluid volatility may enhance the exploitation of this resource in lower thermal maturity windows. This research work provides unique opportunities to advance the fundamental understanding of hydrocarbon generation and production in calcareous organic‐rich shales from a prospective Australian Basin, with potential implications for other similar organic‐rich shale plays globally.
- Oceania > Australia > South Australia (1.00)
- Oceania > Australia > Queensland (1.00)
- Oceania > Australia > New South Wales (1.00)
- Phanerozoic > Mesozoic > Cretaceous > Upper Cretaceous (0.46)
- Phanerozoic > Mesozoic > Cretaceous > Lower Cretaceous > Albian (0.46)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.47)
- Oceania > New Zealand > North Island > Taranaki Basin (0.99)
- Oceania > Australia > South Australia > Warburton Basin (0.99)
- Oceania > Australia > South Australia > Great Artesian Basin (0.99)
- (54 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- (3 more...)
Oil and gas have been mainstays of the world’s energy supply for much of the past century and will quite likely continue to play an important role in the global energy mix for many years to come. Despite the steady demand for its products and services, however, the industry that finds and brings these energy resources to market is undergoing significant changes on several fronts. First, it is widely understood that the sector materially contributes to the planet’s overall greenhouse gas emissions, but it is working diligently to reduce its carbon footprint. Second, with much of the world’s “easy oil” already consumed, upstream oil and gas companies will have to use increasingly sophisticated technologies to find and produce tomorrow’s hydrocarbons. Future oil and gas resources—especially in non-OPEC countries—will tend to be deeper, harder to find, and in environments that are significantly more difficult to access than they used to be. Third, policymakers and the public have steadily increased expectations for oil and gas companies with regards to environmental stewardship, safety, and human welfare. In the face of these kinds of challenges, technology will clearly play a pivotal role in the success or failure of oil and gas firms in the future. As a step toward improving how the upstream oil and gas sector develops and deploys new technologies, the first SPE Global Innovation Survey (SPE 166084, SPE-1212-0062-JPT) was put together in 2012 to shed light on several different aspects of how the industry conducts research and development (R&D) and innovation-related activities. The unit of analysis for the first survey was the business unit, and managers from 199 business units around the world responded with data about many aspects of innovation-related activities within and outputs from their respective organizations. While organizations clearly play an important role in the innovation process, these activities are invariably underpinned by the creativity, know-how, and imagination of individual people. Therein lies the motivation for the second SPE Global Innovation Survey, which was conducted in 2017. It dove deeper into the industry than the previous survey, this time asking individuals from a broad range of roles, levels of responsibility, cultures, and geographical locations about the innovation-related dimensions of their jobs within the upstream oil and gas industry. A deeper understanding of the roles of individuals in the innovation process is more important than ever as the organizations that make up the industry are being fundamentally transformed. Some of the largest oil and gas companies are reinventing themselves as “energy companies” rather than continuing to focus on their oil and gas legacies and are significantly overhauling major aspects of their businesses. How organizations configure their human resources has also changed considerably since the beginning of the COVID-19 pandemic. Individual-level innovative behaviors are therefore more important to understand than ever as the oil and gas sector’s institutions are changing and adapting in the face of these tectonic changes—and the people in the industry are the building blocks that will be reorganized as these changes occur.
- Europe (1.00)
- Asia > Middle East (0.29)
- Oceania > Australia > Queensland (0.16)
- Questionnaire & Opinion Survey (1.00)
- Research Report > Experimental Study (0.50)
Near-Wellbore Damage Associated with Formation Dry-Out and Fines Migration During CO2 Injection
Alchin, Liam (The University of Adelaide, Australia) | Lymn, Andre (The University of Adelaide, Australia) | Russell, Thomas (The University of Adelaide, Australia) | Badalyan, Alexander (The University of Adelaide, Australia) | Bedrikovetsky, Pavel (The University of Adelaide, Australia) | Zeinijahromi, Abbas (The University of Adelaide, Australia)
Abstract One of the key parameters for subsurface CO2 storage in well injectivity. There are multiple factors that can affect injection rate including formation dry-out, fines migration, and salt precipitation that can increase or decrease the injectivity. In this study, we experimentally investigated the cumulative effect of rock drying-out and fines migration on well injectivity for a formation in the Cooper – Eromanga Basin, South Australia. Four core plugs with a range of clay content and permeability were chosen from the formation. Each core was fully saturated with artificially made formation water to measure initial permeability. The core samples were then subjected to a constant flow of gas (air or CO2) at reservoir pressure for up to 185,000 PVI. The effluent fluid was sampled continuously to measure the concentration of solid particles produced from the core during gas injection. The tests were followed by injection of formation water to eliminate the salt precipitation effect and then DI water to identify the maximum possible formation damage in each core sample. Overall injectivity increased significantly during continuous injection of CO2or air into fully saturated core samples despite permeability damage due to fines migration. Fines migration was observed during gas injection, resulting in a pressure drop increase across the cores and fine release at the core outlet. 30-60% reduction of core permeabilities were observed during connate water evaporation. The damaging effect of fines migration on injection rate was negligible compared to 4-30 times pressure drop decrease due to reduction in liquid saturation.
- Oceania > Australia > South Australia (1.00)
- Oceania > Australia > Queensland (0.95)
- Geology > Mineral > Silicate > Phyllosilicate (0.49)
- Geology > Geological Subdiscipline > Geomechanics (0.46)
- Oceania > Australia > South Australia > Eromanga Basin (0.99)
- Oceania > Australia > Queensland > Eromanga Basin (0.99)
- Oceania > Australia > Northern Territory > Eromanga Basin (0.99)
- (5 more...)