Min, Baehyun (The University of Texas at Austin) | Nwachukwu, Azor (The University of Texas at Austin) | Srinivasan, Sanjay (Pennsylvania State University) | Wheeler, Mary F. (The University of Texas at Austin)
A model selection process based on multi-objective optimization using a fast proxy is presented that chooses geologic models conditioned to observed flow and geomechanical responses. The responses of geologic models to injection of large volumes of CO2 are evaluated using a proxy that approximates pressure distribution using a random walk particle tracking algorithm and computes surface deformation using a stress-field solver. The geologic models showing similar proxy responses are grouped into clusters by invoking multi-dimensional scaling and
ABSTRACT: A coupled flow-geomechanical modelling study has been carried out in an effort to match the flowing bottomhole pressures and InSAR surface uplift time series at the three injection wells over the seven years CO2 injection period at In Salah. The surface deformation data covers the entire period of monitoring from July 2003 to January 2012. It is believed that a structural feature controls the dynamic pressure and geomechanical behaviour at both injection wells KB-502 and KB-503, and that CO2 injection has caused tensile opening of pre-existing fractures/faults in the area. This insight was incorporated by introducing a fracture/fault zone with a dynamic transmissibility into the coupled flow-geomechanical model. Using forward coupled flow- geomechancial modelling, both the injection pressure behaviour and the geomechanical response at the ground surface have been largely reproduced. Research findings helped assess the overall performance of the site and potential for the migration of CO2 within the storage complex.
A growing concern that the ongoing increase in atmospheric concentrations of the greenhouse gas carbon dioxide (CO2) is contributing to global climate change has led to a search for technologies to reduce CO2 emissions. For this purpose, Carbon Capture and Storage (CCS) has been proposed as a promising technology to reduce CO2 emissions produced by the combustion of fossil fuels (IPCC 2005). The concept of CCS involves capturing CO2 from fossil fuel combustion, compression, transport and injection into a deep geological formation.
Research carried out in association with the four major industrial scale projects Sleipner and Snøhvit in Norway (Eiken et al. 2011, Chadwick et al. 2012, Shi et al. 2013a), In Salah in Algeria (Ringrose et al. 2009) and Weyburn in Canada (White 2009), together with smaller but equally valuable research pilots such as Ketzin in Germany (Liebscher et al. 2013) and Otway in Australia (Jenkins et al. 2012) have improved our understanding of the subsurface processes involved in CO2 storage a great deal and helped develop storage performance and risk assessment methodologies. The experience gained from these projects have shown that fluid behaviour and the geomechanical response of the CO2 storage formation and surrounding structures are some of the critical parameters that will determine the overall system performance. Real sites may contain features, such as non-sealing wells, faults, fracture zones, which may allow CO2 to migrate and leak out of the storage reservoir. Furthermore, increases in reservoir pressure in response to CO2 injection would induce mechanical stresses and deformation in and around the injection reservoir. Moreover, there is also a potential to induce seismicity on nearby faults. If reservoir pressure increase becomes too large, the induced stresses may cause irreversible mechanical changes, creating new fractures or reactivating preexisting ones, compromising the storage integrity of the reservoir.
Pore pressure reduction due to hydrocarbon extraction from gas reservoirs causes compaction of the reservoir rock accompanied by a redistribution of stresses in the surrounding rock mass, leading to sub-surface deformations and surface subsidence. There is evidence to suggest that the induced sub-surface movements in some of the Netherlands’ gas fields (the motivation behind the study) are time-varying. The sandstone reservoirs in question are overlain by relatively thick layers of rocksalt, which flows viscoelastically when shear stress are applied to it. For this reason, rocksalt flow has been proposed as a mechanism to explain the observed time-dependence. The work reported here aims to understand the mechanisms by which viscoelastic rocksalt flow can cause surface displacements and to assess whether the magnitude of the resulting displacements can be significant over timescales similar to those observed in the field. Finite Element analyses of idealized reservoir geometries and simplified geological models will be employed for this purpose, with the aim of avoiding complexities that can mask the underlying processes and phenomena. Results here indicate that salt-driven flow has the potential of inducing significant timedependent subsidence, in excess to the ones calculated through solely elastic analyses of the same problem. They therefore indicate that in cases where accurate subsidence predictions are essential, salt has to be modeled accurately.
Extraction of natural gas from a reservoir rock formation leads to pore-fluid pressure decrease and so an effective stress increase in the reservoir rock. This in turn leads to reservoir compaction which is registered at the surface as subsidence. The link between production-induced pore pressure changes at the reservoir level and surface subsidence is well-established, e.g. [1, 2, 3, 4].
In many cases the ground is modelled as elastic and so an immediate subsidence response to the pore pressure reduction is expected at the surface (after [5, 6]). This thinking therefore assumes that subsidence stops immediately after the stop of production from a reservoir. However there is growing evidence to suggest that for some reservoirs there is a delay in the subsidence response, i.e. a time-dependence of ground deformations, see [7, 8].
Zhang, Y. (CSIRO Minerals) | Schaubs, P. M. (CSIRO Minerals) | Langhi, L. (CSIRO Energy) | Delle Piane, C. (CSIRO Energy) | Dewhurst, D. N. (CSIRO Energy) | Stalker, L. (CSIRO Energy) | Michael, K. (CSIRO Energy)
An area in the Southern Perth Basin has been identified as a potentially suitable site for CO2injection, due to its proximity to major CO2emission sources and the presence of potentially suitable geology. The project for testing and proving up of the storage area is known as the South West Hub Project or SW Hub. Recently acquired 2D seismic and well data have allowed a detailed description of facies, measurement of rock properties and development of a 3D structural model for the area. This 3D model has been used as the basis for a preliminary fault seal analysis and also for the development of simplified geomechanical models for the SW Hub using FLAC3D. The geomechanical modelling used in situ stress (magnitude, orientation) and pore pressure conditions as a starting point and then simulated CO2injection from a single well at rates of 1 to 5 million tons per year for 20 years. No matter whether weak or strong faults were used, no faults were reactivated nor the top seal breached under any of the simulated injection rates. Average uplift in the weak fault scenario was modelled at between 0.4 and 1.8 cm for injection rates of 1 to 5 million tons per year. The strong fault model showed slightly smaller uplifts. The majority of uplift was noted in the first 5 years of injection and flattened off rapidly after this point in time. This is consistent with geomechanical models from other CO2storage sites and from actual field measurements.
Suitable geology and proximity to large sources of carbon dioxide led to the Southern Perth Basin being investigated as a potential geological storage site . The specific area selected is in the region of the Harvey- 1 well (Figure 1) around 150 km south of Perth in Western Australia. This has become known as the South West Hub project and this area is currently undergoing extensive site assessment in terms of reservoir quality, containment potential, structural geology, facies analysis, rock properties and the like.
The migration to ultra-mature production and concern about rising greenhouse gas emissions mean that the implementation of carbon capture and storage projects are coming into sharper focus than ever before in the Middle East.
Capturing carbon dioxide (CO2) and using it in enhanced oil recovery (EOR) is one strategy being widely adopted. Studies showing the region having one of the world’s highest per capita environmental footprints have led governments to look for ways to improve their rankings in greenhouse gas emissions.
So far, Oman is the only country in the region to have launched EOR programs on a large commercial, rather than pilot, scale in a bid to stem and reverse years of declining crude production. In Abu Dhabi, tertiary gas injection has been under way for decades at the Total-operated Abu Al Bukhoosh field with great success. As production in the region matures, more countries are expected to implement EOR programs.The application of CO2 EOR provides two advantages for companies in the Middle East. It allows natural gas that would otherwise be used for injection into oil fields for secondary recovery to be freed up to meet domestic requirements, such as power generation and industrial use, or to limit the costly import of liquefied natural gas. Moreover, it helps limit emissions in the region.
This paper demonstrates the ability of a 2D independent two-phase flow hydro-mechanical (H-M) simulator, FLAC (Fast Lagrangian Analysis of Continua), to predict H-M responses related to Co2 injection in subsurface disposal reservoirs. This is the first paper to study the use of FLAC as a single H-M simulator for Co2 injection processes. The models in FLAC are tested against twoexistingmodels: (1)a prototype Co2injectionreservoirand(2)the InSalahgas fieldinAlgeria.The H-M responses such as the spread of Co2 plumes, the history of pore pressure increases, and surface uplifts are presented and compared with the results from the reference models. The potential for mechanical failures and leakage are also analyzed using critical pressure approach. The simulations show that FLAC models are able to capture typical shapes of Co2 plumes in the reservoirs. The history of pore pressure increase and a typical bell-shape for surface uplifts are obtained. The potential location for mechanical failures and leakage is also well predicted. Future implementation of H-M stress-dependent properties in FLAC will improve its capability. Hence, coupling this software with other fluid flow simulator such in the literatures may no longer be necessary in the future.
In this work, we present results of coupled fluid flow and geomechanical modeling associated with the Co2 injection at three different wells (KB-501, KB-502, KB-503) at In Salah, Algeria. Our recent numerical studies focused on the KB- 502 Co2 injection well, where a double-lobe uplift pattern has been observed in the ground-deformation data. The observed uplift patterns at KB-501 and KB-503 are different, with no clear influence of deep fracture zone mechanical response. In this study we improved our modeling with TOUGH-FLAC considering inelastic deformations in the injection zone, which responds to a Mohr- Coulomb failure criterion. For the case of KB-502 we introduced a fracture zone, modeled as in past considering inelastic deformations, but including a more detailed failure criterion. In addition, we modeled a stress-dependent permeability and bulk modulus, according to a dual continuum model. Mechanical and hydraulic properties of the injection reservoir and those of fracture zones at the three injection wells were determined through inverse modeling with iTOUGH2 by matching the simulated spatial and temporal evolution of uplift to the corresponding InSAR observations as well as by matching simulated and measured pressures. We found an excellent match between simulated and observed variables, with residuals well within the limit of the observation errors. The estimated values for the parameterized mechanical and hydraulic properties are in good agreement with previous numerical results.
Optimizing and enhancing oil recovery is a key focus for the oil and gas industry. For economic success, good reservoir formation knowledge is important to optimize oil & gas extraction over the course of production time. Reservoir history matching plays a crucial role in the incorporation of production and logging data for efficiently forecasting the development of reservoirs and its depletion. While production and logging data have been readily incorporated, sparse spatial sampling of these data may yield insufficient information about the formation structure to accurately history match for large reservoirs such as Ghawar. InSAR (Interferometric Synthetic Aperture Radar) has revolutionized the way to measure the Earth's surface deformation and has been successfully and economically utilized for studying large surface deformation caused by hydrocarbon extraction (such as commercialized by Halliburton). Surface displacement is primarily caused by changes in the pressure level within the subsurface reservoirs that lead to an up-or downlift of the subsurface. With fluids travelling from high into low pressure environments, InSAR measurements can be used to forecast fluid displacements. We have developed an InSAR based history matching framework for oil & gas reservoirs that efficiently incorporates InSAR data for improved reservoir management and forecasts. Our numerical results suggest that InSAR data provide important information about the reservoir state which can be exploited to enhance the forecasting for large scale reservoirs.
Recent years have seen significant funding competitions launched in Europe and in the UK that call for bidders to propose commercial demonstration projects which will bring innovation across the carbon capture and sequestration (CCS) technology chain to reduce energy system costs. The primary carbon dioxide (CO2) storage site candidates that are targeting funds are the saline aquifers and depleted oil and gas fields in the North Sea. At the time of writing, no outright winners have been announced.
These programs are open to CCS projects as well as carbon capture, utilization and storage (CCUS) projects. The former deals exclusively with greenhouse gas storage, but the latter differs by using the injected CO2 for enhanced oil recovery (EOR) before eventually being stored. Hence, there are considerable technical and commercial differences between CCS and CCUS projects, in much the same way as onshore projects face less challenges and constraints than if they were being implemented offshore.
The evaluation and selection of which offshore carbon storage projects should be funded is a tough exercise to undertake, but it becomes much more difficult if the competing projects under consideration are allowed to be CCS or CCUS, full chain or part chain, or a mixture of all of the aforementioned. Bias may arise via reliance on selection criterion such as volume of stored CO2 per unit of expenditure, which is likely to favor saline aquifer storage projects over other types, no matter how innovative or compelling they are.
The authors believe that selection committees in Brussels and London would greatly simplify their decision of which bid should be funded, and in what proportion, by separating competing projects into straightforward storage types and CO2-EOR types. Offshore experience of either project type is scarce and their relative merits are difficult to reconcile as the subsurface understanding, timeframe, economics, performance and goals of each project type are quite different.
The paper recognizes that CCS-type projects can be further subdivided into saline aquifers, with open and closed systems, and abandoned gas fields, as each have different storage limitations. Also, CCUS-type projects, which realistically only include abandoned oil fields, can be further subdivided to reflect the operational and commercial characteristics of different EOR schemes.
It is hoped that the discussion outlined in this paper will lead to easier and fairer screening criteria for offshore CCS and CCUS projects for use by governments, operators and investors alike.
Abstract: This study focuses on a specific problem related to the surface uplift induced by the injection of CO