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At the Ketzin CO 2 storage site, Germany, an interdisciplinary, comprehensive monitoring concept focusses on the storage complex, the overburden, the surface and the wellbores. Well integrity as one key requirement for safe storage operation has been monitored by combined video inspection, pulsed neutron gamma logging PNG, magnetic imaging defectoscopy MID and continuous annuli pressure monitoring. The time-lapse MID derived casing thicknesses are within the production specifications, conform to the API standards, and provide no hints to time dependent changes or to any other signs of corrosion. The comprehensive monitoring data indicate well integrity throughout the entire Ketzin life-cycle.

In order to build confidence in CO2 storage as greenhouse gas control activity, it is vital to learn from the experience gained from first-mover projects, at the pilot scale and at the demonstration scale. Many of the early CCS projects have published their findings with a view to supporting technology development for CO2 storage, giving improved quality and accuracy in forecasting CO2-storage site behaviour. In order to build on these initial insights, we propose developing a comprehensive set of reference datasets designed to address specific uncertainties and technology gaps. This paper describes examples of how existing datasets have been used and identifies new and emerging technical issues that could be addressed using a broader set of reference datasets as part of an International CO2 Storage Dataset Consortium. The datasets presented here show some of the insights gained so far into: well injectivity, down-hole pressure monitoring, flow modelling of CO2-brine systems, the geomechanical response to CO2 injection and analysis of microseismic monitoring data.

The CO2CRC's “Otway Stage 2C project” is a test injection of 15,000 tons of supercritical gas mixture (80 mole% CO 2 & 20 mole% CH 4 ) at the CO2CRC Otway site in the Australian state of Victoria. The objective of this test is to examine the limits of surface seismic detection and to conduct detailed pressure monitoring of the injection. A key design feature of the project is injection near the bottom of a highly permeable formation, thereby allowing for buoyancy driven flow to thicken the plume and enhance seismic response. The project is specifically targeting observation of the development of the gas plume through a combination of multi-vintage 4D seismic surveys acquired with a buried seismic receiver array, 4D Vertical Seismic Profiling (VSP) and pressure measurements. Using both time-lapse seismic data and reservoir simulations, we aim to not only detect the plume but also demonstrate its eventual stabilisation. In this paper we discuss the technical aspects of the Otway Stage 2C seismic monitoring program and the initial results.

Large volume of CO2 may be stored in depleted oil and gas reservoirs or in deep saline aquifers to mitigate global warming. Once injected, monitoring is of essential need to ensure that the injected CO2 is in place and does not disturb the integrity of formation reservoirs. To this purpose, detection of any risk conditions of fluid leakage to overlying formations is critical. We previously presented the applicability of a pressure monitoring to directly monitor the leakage of carbon dioxide or subsurface brine by measuring the pressure of the upper formation based on the idea of quick response of pressure propagation in a porous media. Especially, it was reported that the pressure monitoring is useful even in the offshore storage site where conventional monitoring method in the onshore site cannot be applied, and it might be cost-effective if the pressure sensor is installed in the injection well. However, the preliminary results based on the numerical simulation are in need to be further investigated with field measurement under a variety of conditions. These various conditions are studied by conducting sensitivity analysis on the pressure change and the detection time.

We describe a systematic procedure for the monitoring and analysis of bottom-hole pressure data during CO2 injection into deep saline aquifers. Our methodology builds upon well injectivity and pressure transient analysis techniques developed in the petroleum industry for fluid injection systems. Using field data from AEP's Mountaineer Plant CO2 geologic sequestration project, we show how late-time pressure falloff response at monitoring wells can be interpreted to estimate intrinsic permeability of the reservoir. Effective total compressibility values estimated from history matching of post-breakthrough injection-falloff sequences at different times can also be utilized for tracking the CO2-brine front.

Geological storage of carbon dioxide provides the possibility of maintaining access to fossil energy while reducing emissions of carbon dioxide to the atmosphere. One of the essential concerns in geologic storage is the risk of CO2 leakage from the storage formations. CO2 may leak through various pathways in the cap-rock overlying the storage aquifer. Characterization of the CO2 leakage pathways from the storage formations into overlying formations is required. We present a flow and pressure test to locate and characterize the leaks. The flow test is based on the injection (or production) of water into (or from) a storage aquifer at a constant rate. The pressure is measured at one or several monitoring wells in an aquifer overlying the storage aquifer, which is separated by an aquitard. The objective of the test is to locate and characterize any leakage through the separating aquitard. We present an inverse procedure to obtain the leakage pathway transmissibility and location, based on the pressure measurements in the presence of noise. A single monitoring well allows good determination of the leak magnitude but provides limited constraints on location. Adding a second monitoring well provides two-dimensional location of the leak location in the presence of noise/uncertainty in pressure measurements. It seems plausible that the use of multiple monitoring wells could enable cost-effective and sensitive detection of leakage over a large area. Unlike seismic imaging which only detects leakage when CO2 penetrates the leak, these methods are able to test for leaks before CO2 injection, or during injection but before the CO2 plume reaches the leak.

Various methodologies are proposed to reduce CO2 emissions that are believed to be the main drivers of the climate change. CO2 capture and storage in deep underground formations is one of the promising methods that allow reducing the emissions while continuing the use of fossil fuels. Injection of immense quantities of CO2 is required to make a reasonable cut of the emissions. Deep saline aquifers can provide the capacity to accommodate the storage of such huge amounts of CO2. However, one of main challenges in deployment of CO2 storage is the risk of CO2 leakage through pathways in the cap-rock overlying the target aquifer. The sealing capacity of the cap-rock must be evaluated to ensure the safety of the storage. Therefore, characterization of the cap-rock is required to find the potential leakage pathways even before the CO2 storage begins. Methods to characterize the leakage pathways are proposed at two different scales: 1- By point sampling of the cap-rock and testing the potential pathways such as abandoned wells, 2- by analysing geophysical (e.g. 3-D seismic) data to estimate paths of upward migration of the injected CO2. Flow based methods have the potential for bridging the large gap that exists between the length scale of these two approaches. The aquifer could be tested for the leakage pathways before CO2 storage. This will allow finding proper storage aquifers and locations for the injection wells. In this work we present an analytical model to evaluate the pressure variation in the overlying aquifers due to leakage from the storage aquifer. In a companion paper, this model will be used along with an inverse modelling approach to locate and characterize the leakage pathways based on pressure data. This paper introduces two new analytical solutions: 1- Exact solutions for the pressure variation in an overlying aquifer due to leakage (obtained in Laplace-transformation domain), 2- time-domain approximations for the exact solutions to make the inversion possible. In deriving the analytical solutions two aquifers are considered: Storage and monitoring. The aquifers are separated by an aquitard and are in communication through a leakage pathway. In departure from previous works the leakage pathways are not required to be line source/sink. Such consideration allows incorporation of large pathways such as stratigraphic and structural heterogeneities in the cap-rock. We consider a single-phase 1-D radial flow system in the storage and monitoring aquifers. Both of the aquifers are considered as homogeneous, isotropic, and infinite-acting with constant thickness. The injection (or production) rate is taken as constant. The analytical solution are applied to a base case and corroborated versus numerical solution.

For risk assessment, policy design and GHG emission accounting it is extremely important to know if any CO2 or brine has leaked from a geological sequestration (GS) operation. As such, it is important to understand if it is possible to use certain technologies to detect it. This detection of leakage is one of the most challenging problems associated with GS due to the high uncertainty in the nature and location of leakage pathways. In North America for example millions of legacy oil and gas wells present the possibility of CO2 and brine to leak out of the injection formation. The available information for these potential leaky wells is very limited and the main parameters that control leakage, like permeability of the sealing material are not known. Here we propose to explore the possibility of detecting such leakage by the use of pressure-monitoring wells located in a formation overlying the injection formation. The detection analysis is based on a system of equations that solve for the propagation of a pressure pulse using the superposition principle and an approximation to the well function. We explore the questions of what can be gained by using pressure-monitoring wells and what are the limitations given a specific accuracy threshold of the measuring device. We also try to answer the question of where these monitoring wells should be placed to optimize the objective of a monitoring scheme. We believe these results can ultimately lead to practical design strategies for monitoring schemes, including quantitative estimation of increased probability of leak detection per added observation well. publishedVersion

An extensive programme of modelling, monitoring and verification activities was deployed at a set of active storage sites worldwide including Sleipner, In Salah, Ketzin, Weyburn, K12-B and Snøhvit (EU CO2ReMoVe project). All investigated storage sites were well managed and did not have a negative impact on humans or the environment. Time-lapse seismic and pressure monitoring are key in verifying the deep subsurface performance of the storage sites. Evidence gathered during the site characterisation and operational phases is key to handover responsibility of the storage site to governmental authorities after injection has definitely ceased, which is the focus of the follow-up EU project CO2CARE.

The Midwest Regional Carbon Sequestration Partnership (MRCSP) is implementing a commercial-scale carbon capture and storage (CCS) project in multiple Silurian carbonate pinnacle reefs in northern Michigan that are in various phases of enhanced oil recovery. This paper presents analyses of five pressure fall-off tests performed sequentially during the injection of 166,000 tonnes of CO2 into a Type-1 (depleted) reef which has undergone primary and secondary production. Bottom-hole pressures were monitored in the injection well and in two observation wells to record progressively increasing reservoir pressure during the injection period, which also included five fall-off tests. Pressure data were analyzed using combined history-matching and pressure derivative matching techniques implemented with a commercial well-test interpretation program, FAST WellTest™. The paper illustrates the challenges of consistently interpreting CO2 injection fall-off tests under multi-phase flow with varying pressure conditions using a single-phase analytical model. This work is relevant to CO2 sequestration in depleted oil reservoirs because regular fall-off testing is required under the U.S. Environmental Protection Agency's Underground Injection Control (UIC) Program for CO2 geologic sequestration (75 FR 77230).