Otway Basin Pilot Project Research Articles

Accurate determination of characteristic relative permeability curves

A recently developed technique to accurately characterize sub-core scale heterogeneity is applied to investigate the factors responsible for flowrate-dependent effective relative permeability curves measured on core samples in the laboratory. The dependency of laboratory measured relative permeability on flowrate has long been both supported and challenged by a number of investigators. Studies have shown that this apparent flowrate dependency is a result of both sub-core scale heterogeneity and outlet boundary effects. However this has only been demonstrated numerically for highly simplified models of porous media. In this paper, flowrate dependency of effective relative permeability is demonstrated using two rock cores, a Berea Sandstone and a heterogeneous sandstone from the Otway Basin Pilot Project in Australia. Numerical simulations of steady-state coreflooding experiments are conducted at a number of injection rates using a single set of input characteristic relative permeability curves. Effective relative permeability is then calculated from the simulation data using standard interpretation methods for calculating relative permeability from steady-state tests. Results show that simplified approaches may be used to determine flowrate-independent characteristic relative permeability provided flow rate is sufficiently high, and the core heterogeneity is relatively low. It is also shown that characteristic relative permeability can be determined at any typical flowrate, and even for geologically complex models, when using accurate three-dimensional models.

A Procedure for the Accurate Determination of Sub-Core Scale Permeability Distributions with Error Quantification

We present a new method for non-destructively calculating sub-core scale permeability distributions within a core. The new method integrates experimentally measured capillary pressure data and sub-core scale saturation and porosity data collected using a computed tomography-scanner, to construct an accurate and unique sub-core scale permeability distribution. Using this procedure, it is possible to conduct highly refined simulations of core flooding experiments without typical assumptions requiring the core to be homogeneous, or relying on inaccurate porosity-based methods for estimating permeability distributions. The calculation procedure is described and results from two example rock cores are presented, a Berea Sandstone and a sandstone from the Otway Basin Pilot Project in Australia. Drainage coreflooding experiments of carbon dioxide ( $$\text{ CO }_{2})$$ injection into water are first conducted on both cores and permeability distributions are calculated using the experimental data. Numerical simulations of the very same experiments are then conducted to demonstrate the accuracy of the calculated sub-core scale permeability distribution. Results from both cores show that the input sub-core scale saturation distributions are predicted with an $$R^{2}$$ correlation of greater than 0.93. This is compared to having no correlation when using simple porosity-only based permeability distributions, or assuming homogeneous core properties (Krause et al., SPE J 16(4):768–777, 2011). The uniqueness of the calculated permeability distribution is then demonstrated by calculating permeability distributions for the same core using data collected at different $$\text{ CO }_{2}$$ injection fractional flows. Results show that the two independently calculated permeability distributions agree within the limits of experimental measurement error.

Seismic monitoring of CO2 injection into a depleted gas reservoir–Otway Basin Pilot Project, Australia

Abstract The use of depleted gas fields for CO 2 storage as well as CO 2 -based enhanced gas recovery are of global importance. Thus, the CO2CRC Otway Basin Pilot Project provides important experience in establishing whether such scenarios can be monitored by geophysical techniques, in particular seismic time-lapse methodology. Injection of CO 2 into a depleted gas reservoir (with residual gas in the Otway case) does not present favourable conditions for the application of geophysical monitoring techniques. Simulation of the CO 2 injection process at Otway shows that changes in elasticity of the reservoir rock will be quite small and difficult to monitor even with the most powerful time-lapse (TL) seismic methodologies. Consequently, the design and implementation of the monitoring program had to address these issues. To increase the sensitivity of TL seismic we combined 3D VSP with 3D surface seismic. For land seismic case, we achieved excellent repeatability with 3D time lapse surveys, which at the reservoir level produced normalised RMS difference values of about 20% for surface seismic and 10% for 3D VSP, respectively. Still due to very small time lapse signal, the primary use of 3D surface seismic was for assurance monitoring. Borehole seismic measurements confirmed that time-lapse is too small to be reliably estimated and analysed from repeated seismic measurements. Finally, post-injection reservoir simulation and accompanying seismic modelling suggest that a prolonged CO 2 /CH4 injection should produce only negligible change of the elastic properties of the Naylor reservoir.

Recent Progress in Predicting Permeability Distributions for History Matching Core Flooding Experiments

Abstract Laboratory core flooding experiments coupled with CT scanning has been shown to be very useful for examining CO 2 -brine displacement processes. These experiments can be used to measure core average properties such as absolute and relative permeability, and also to examine sub core-scale saturation and porosity distributions. By examining the sub core scale fluid distributions during the displacement process, it is possible to study the displacement efficiency of CO 2 -brine drainage processes, residual trapping and fluid saturation at the millimeter to sub-millimeter scale. One potentially useful tool for studying CO 2 -brine systems is using numerical simulation to replicate and study these core flooding systems. This could be used to study the interactions and relative impact of different parameters such as capillary pressure, relative permeability and heterogeneity on brine displacement by CO 2 under various flow conditions. One challenge to successfully conducting such numerical experiments has been accurate representation of the permeability distribution inside the core at the millimeter and sub-millimeter scale. Other simulation parameters can all be measured using laboratory experiments, but permeability must be derived from other properties at the core and sub core-scale. Previous work has shown that predicting sub core-scale permeability distributions based on porosity does not result in accurate representation of permeability at such a small scale. To improve these predictions, a new method based on capillary pressure and was developed and used to accurately predict sub core-scale permeability distributions in a relatively homogeneous Berea sandstone. The work presented in this paper uses the same method to calculate permeability in a strongly heterogeneous sandstone core from the Otway Basin Pilot Project in Australia. Simulations show that the results are consistent with previous results in the homogeneous cores, with statistically significant capability to predict sub core-scale CO 2 distributions in the core. Due to the extreme heterogeneity of the core used in this study, the average match is not as good as for a relatively homogeneous rock core, however, a visual comparison shows that the results are still very good, and that the new method used to calculate permeability may still be valid even in the presence of strong heterogeneity.

Permanent shallow subsoil CO 2 flux chambers for monitoring of onshore CO 2 geological storage sites

Public concern over the possibility of migration of stored CO 2 to the surface with resulting damage to vegetation or hazard to humans and animals is a matter which will need to be addressed to be able to satisfy likely regulatory requirements for onshore CO 2 storage in a number of jurisdictions. While soil CO 2 concentration is readily measured continuously and in situ with current technology, the measurement of CO 2 flux at depths below the soil A horizon may be a more sensitive and meaningful technique for early detection of a near surface CO 2 plume. We describe a system for the continuous measurement of soil CO 2 flux at a depth of approximately 1.3 m and present results from three instruments deployed at the Otway Basin Pilot Project in Victoria, Australia and one development system deployed at Sutton, near the Australian Capital Canberra.

Techbits: Workshop Examines CO2 Capture, Geological Storage

Techbits The SPE Applied Technology Workshop (ATW) titled "Capture and Geological Storage of CO2" was held in Perth, Australia, from 7–10 October. Attending the ATW were 107 participants, representing 50 different organizations from 15 countries. The workshop's chief objective was to provide an overview of current CO2 capture and storage (CCS) technology and projects, as well as a look ahead into how technical, economic, and policy developments might facilitate large-scale, widespread application of CCS to mitigate greenhouse-gas (GHG) levels. Cochairpersons Scott Imbus and John Kaldi opened the ATW's initial session with an overview of the goals and expectations for the week, which was followed by the first keynote address, "Carbon Dioxide Capture and Geologic Storage: Research, Development, and Application in Australia," given by Peter J. Cook, chief executive, Cooperative Research Centre for Greenhouse Gas Technologies, which is known as CO2CRC. Cook focused on the role of CO2CRC's Otway basin pilot project in setting a precedent for safe, effective geological storage of CO2 in Australia. The second keynote speaker, John Bradshaw, chief scientist, Geoscience Australia, spoke on "Technical and Regulatory Impacts of Implementing a Geological Storage Regime." Bradshaw reviewed results of the national storage-capacity assessment and the need for a regulatory regime knowledgeable on the trapping and migration properties of CO2 at the large scale. The need for technical rigor to earn public assurance was stressed. The perspectives of energy providers, including oil and gas companies, coal producers, and utilities, formed Session 2. While recognizing that capture technology is commercially available, speakers focused on the large costs that will be borne by the public and industry. Development and demonstration of more-cost-effective capture technology are needed, but funding for demonstration projects is lacking, they agreed. Subsurface aspects of CCS are familiar to the oil and gas industry but not to the public, they pointed out. The risks of CO2 storage can be managed during capture-and-storage operations. However, long-term liability afterward should be dealt with at the public-policy level rather than through the avenue of litigation against the project participants, the speakers noted. Session 3 overviewed technologies and approaches to site assessment. A recurrent theme was balancing information available with that needed to provide suitable models and simulations, as well as the implications of uncertainty. The importance of natural analogs, flexible workflows, and improved, coupled simulations was stressed. Storage assurance was the topic of Session 4. Monitoring programs should be fit-for-purpose, performance-based, and designed to detect and mitigate leakage in the deep subsurface, speakers said. Understanding fault stability through geomechanical studies will help determine whether faults will be vulnerable to CO2 leakage. Well-integrity studies, including assessment protocols, new well-construction design, and materials and intervention options, will be essential to the long-term security of storage sites, speakers said, adding that risk assessment incorporates all technical assurance issues but at present is not "quantitative." By framing CO2 injection, migration, and trapping scenarios, however, the assessment process serves to align stakeholder perception and risk tolerance, speakers noted.

Land Seismic Acquisition Repeatability for Time-Lapse Monitoring of CO2 Sequestration

Time-lapse surface and borehole seismic surveys are planned for monitoring the injection of CO2 in the CO2CRC Otway Basin Pilot Project in Victoria. Critical to the success of this is to ensure optimum repeatability of acquisition parameters and ground conditions. In order to assess the relative influences of source types and environmental conditions, a series of repeated test surveys have been undertaken. The study utilised repeated high-resolution seismic surveys along the same 2D line. The first test line was acquired with mini-vibroseis (6000 lb) in wet conditions when the top soil and the weathered layers were fully saturated. The line was subsequently re-recorded in dry conditions where we utilised the same mini-vibrator, but in addition repeated the line using a free-fall weight drop. Both sources have similar total energy output but a vibrator is a controlled frequency source while a weight drop is not. Despite differences in the frequency content and phase of the signal generated by these two sources, and positioning differences for source and receiver locations of up to 1m, almost identical stacked sections were obtained after phase matching and scaling of the two datasets. Far greater differences in total energy, frequency content and phase of the signal were observed between the two vibroseis lines recorded at different times of the year (wet and dry periods). Our results clearly demonstrate that near surface conditions has a first order effect on repeatability of land seismic surveys. A common belief that deployment of the same seismic source and positioning errors are crucial for successful time-lapse seismic needs to be reexamined in light of our results, which show that these factors are of secondary importance when it comes to land seismic surveys.

Regulatory challenges and managing public perception in planning a geological storage pilot project in Australia

The implementation of geological storage of CO 2 requires not only further research and development but also the demonstration of carbon dioxide capture and storage (CCS) technology as a viable option. A pilot program is an important first step towards building industry and community confidence in the application of CCS. The Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC), Australia's leading research organisation in CCS, has initiated a comprehensive research and demonstration program in the Otway Basin in South-West Victoria. As the first project of its kind in Australia, the Otway Basin Pilot Project (OBPP) has faced a number of regulatory and organisational challenges while having to concurrently address public perception. The Otway Basin site with its natural CO 2 accumulations and many depleted natural gas fields offers an appropriate CO 2 storage site to test scientific and regulatory concepts and evaluate public response through social research. The project aims to show that CO 2 can be safely captured, transported and stored deep underground under local conditions, and also monitored and verified. Planning has been ongoing for over a year, baseline studies are underway and the project is targeted to start injection in 2007.