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This report describes an assessment of environmental impact potential arising from the possible disposal of hypersaline brines into the ocean as part of reservoir pressure management for Carbon Capture and Storage. We have used sophisticated high-resolution hydrodynamic models to assess a number of guided scenarios. Although the characteristics of some brines in their undiluted form would have a high environmental impact potential, we find that dispersion in a hydrodynamically active region like the North Sea acts to dilute disposed brine rapidly, such that the potential impact footprint (area exposed to environmentally damaging salinity or temperature) is small, generally measured in 10’s of meters depending on scenario and in-situ conditions. Contaminants within the released brines may have more impact potential, depending on concentration. We recommend consideration of brine release height to further limit impact potential.

In a previous project, a silicate based sealant was developed and applied to the case of a clayey sandstone formation with the objectives of plugging the surroundings of a well typically within a radius of 1 m. Here, we report experiments conducted at the Mont Terri Underground Research Laboratory (MT-URL) focusing on the mitigation of pressure leakages associated with CO2 containment in near wellbore injection well systems. This work was performed under the auspices of the CO2 Capture Project (CCP), a three-company collaboration comprising Chevron, BP and Petrobras. The CCP effort is directed to develop more cost effective and efficient processes for CO2 concentration, capture and sequestration applied to the energy, refining, chemical and power generation industries in order to reduce greenhouse gas emissions. The experimental set-up installed at the underground test site mimics an injection well with the objectives of testing various sealants able to contain losses associated with delaminations that may occur at various well boundaries such as cement to casing and cement to caprock. Cement and caprock may also be micro-fractured. The tested sealant takes advantage of the properties of alkaline silicate solutions forming a gel after addition of an acid in appropriate strength and quantity. With a viscosity close to water, it can easily be injected in a liquid state and does not need to be activated after injection. The gelation time can be adjusted and is mostly sensitive to temperature. We tested two formulations of the sealant in a 1 m interval of the well system. The sealing capacity is evaluated by comparing flowrates at constant imposed pressure before and after injection of the sealant. Typically, a decrease by a factor of 10 of these flowrates is an indication of a good sealing performance. The first formulation proved to be efficient only for a limited time smaller than 1 month. The second improved formulation proved to be efficient for a period larger than one month.

The CO2 Capture Project (CCP) is a unique collaborative technology development program initiated in 2000 with participants from corporations, academia, governments, research institutions, policy makers and individual contractors who came together to advance development of new approaches to capture and store CO2 and improve efficiencies of existing technologies. The overall objectives have been to deliver major cost reductions for carbon capture and demonstrate that geological storage is safe, measurable, and verifiable. Since 2000, the CCP partners and cost-sharing governments have invested over $90 million to support a wide-ranging portfolio of projects to advance the understanding and development of capture and storage technologies, the economic analysis of the cost base of CCS together with analysis of regulatory and policy frameworks and a dedicated communications programme with key stakeholders. In this paper, we reflect upon the highlights and lessons learnt from twenty years of investment in technology development and the implications for the future deployment of CCS.

Wellbore integrity is a critical subject in oil and gas production and CO2 storage. Successful subsurface deposition of various fluids, such as CO2, depends on the integrity of the storage site. In a storage site, injection wells and pre-existing wells might leak due to over-pressurization, mechanical/chemical degradation, and/or a poor cement job, thus reducing the sealing capacity of the site. Wells that leak due to microannuli or cement fractures on the order of microns are difficult to seal with typical workover techniques. We tested a novel polymer gelant, originally developed for near borehole isolation, in a pilot experiment at Mont Terri, Switzerland to evaluate its performance in the aforementioned scenario. The polymer gel sealant was injected to seal a leaky wellbore drilled in the Opalinus Clay as a pilot test. The success of the pH-triggered polymer gel (sealant) in sealing cement fractures was previously demonstrated in laboratory coreflood experiments [1-3]. pH-sensitive microgels viscosify upon neutralization in contact with alkaline cement to become highly swollen gels with substantial yield stress that can block fluid flow. The leaky wellbore setup was prepared by heating-cooling cycles to induce leakage pathways in the cased and cemented wellbore. The leakage pathways are a combination of fractures in the cement and microannuli at the cement-formation interface. The exact nature of these leakage pathways can be determined by over-coring at the end of the experiment life. We used polyacrylic acid polymer (sealant) to seal these intervals. The process comprises of three stages: (1) injection of a chelating agent as the preflush to ensure a favorable environment for the polymer gel, (2) injection of polymer solution, and (3) shut-in for the polymer gelation. Then, we evaluated the short-/long-term performance of the sealant in withholding the injected fluids (formation brine and CO2 gas). The novel sealant was successfully deployed to seal the small aperture pathways of the borehole at the pilot test. We conducted performance tests using formation brine and CO2 gas to put differential pressure on the polymer gel seal. Pressure and flow rate at the specific interval were monitored during and after injection of brine and CO2. Results of performance tests after polymer injection were compared against those in the absence of the sealant. Several short-term (4 min) constant-pressure tests at different pressure levels were performed using formation brine, and no significant injection flow rate (rates were below 0.3 ml/min) was observed. The result shows more than a ten-fold drop in the injection rate compared to the case without the sealant. The polymer gel showed compressible behavior at the beginning of the short-term performance tests. Our long-term (1-week) test shows even less injectivity (~ 0.15 ml/min) after polymer gelation. The CO2 performance test shows only 3 bar pressure dissipation overnight after injection compared to an abrupt loss of CO2 pressure in the absence of polymer gel. Sealant shows good performance even in the presence of CO2 gas with high diffusivity and acidity. Pilot test of our novel sealant proves its competency to mitigate wellbore leakage through fractured cement or debonded microannuli, where other remedy techniques are seldom effective. The effectiveness of the sealing process was successfully tested in the high-alkaline wellbore environment of formation brine in contact with cement. The results to date are encouraging and will be further analyzed once over-coring of the wellbore containing the cemented annulus occurs. The results are useful to understand the complexities of the cement/wellbore interface and adjust the sealant/process to sustain the dynamic geochemical environment of the wellbore.

Carbon capture and storage underground (CCS) is now regarded as a vital and significant means to achieve 3 of the 4 IPCC pathways necessary to limit global warming to 1.5degC. Our internal analysis indicates the number of wells required to facilitate the levels of CO2 capture to meet these objectives are numerous over the next 30 years. An understanding of containment is essential for CO2 storage, but few options exist to monitor a CO2 plume growth 100's of metres away from a well. Gravity is a direct measurement of density, through substitution of water by CO2. The gravity measurement detects changes in mass in the subsurface, such that time-lapse wireline-based surveys may be taken to build up a picture of fluid movements at 100’s of meters from the wellbore. By measuring gravity in all three-axis it is possible to determine directional information about the spatial movement of fluid, even when acquired from just a single borehole. We present emerging 3-axis borehole gravity technology that enables the recording of gravitational acceleration at very high sensitivity (targeted at ≈ 5 µGal) using an innovation in resonant Microelectromechanical system (MEMS) vibrating beam technology with the aim of making small, cheap, but highly stable and highly sensitive field and borehole-deployable relative gravimeters. The vibrating beam gravimeter consists of a suspended mass connected to a vibrating beam, such that the inertial force experienced by the mass in gravitational field is communicated as an axial load on the beam. The technology is currently undergoing field trials as part of the CCP* and we show the results of a feasibility study aimed at monitoring CO2 in a deep storage reservoir in Canada which shows the gravity variation likely to be seen due to density changes during a period of CO2 injection. The displacement and substitution of the aquifer water at the storage site over time is referred to as a 4D gravity survey. The cost effectiveness of a 4D wireline gravity survey compared to 4D seismic survey is highly attractive in smaller carbon storage programs. Where the project size or complexity allow both to be run, the complementary nature of the measurements has been noted by several operators. Survey feasibility modelling and a workflow are presented that together provide important information for planning and acquiring a successful gravity survey, as well as the best time interval (given the planned injection rate), and which well location is most suitable to use. The workflow for conducting borehole gravity simulations from time-lapse reservoir models starts with a 3D model of reservoir porosity, saturation and fluid constituent density, which is used to generate a time-lapse density model from the provided set of reservoir simulation data. Vector gravity anomaly responses (gz, gx, and gy) along the wellbore in a variety of well locations are then predicted through forward modelling. The density changes due to fluid substitution are measured by the vertical, gz, gravity anomaly with respect to the reference gravity field. The fluid front progress through the field is assessed through the horizontal gravity anomalies (gx, and gy). Modelling shows plume growth is detectable even over a period of 1 year (Figure 1) and with MEMS technology lifetime monitoring is possible. We conclude that this emerging technology has the potential to provide a solution for long term monitoring of CO2 plume growth within the likely numerous wells that may be needed to fill the CO2 storage requirements resulting from the IPCC pathway scenarios to 1.5degC.

To ensure storage security, it is vital we understand, and can effectively model, the physical and chemical trapping mechanisms for CO2 storage. A key trapping mechanism underpinning storage security and immobilising a significant proportion of the CO2 plume is capillary trapping. Capillary trapping is considered to be responsible for 90% of the storage capacity in saline aquifers in the US, the largest potential CO2 storage resource. The ability to model and predict capillary trapping over large spatial scales in complex geological systems is essential to minimise risks and evaluate capacity. This paper investigates the effect of natural rock heterogeneities on capillary trapping across spatial scales in the Captain D Sandstone, from the Goldeneye formation, North Sea. That is, how heterogeneities affect CO2 saturation and distribution within rock core samples, and how those effects manifest, as a pseudo residual trapping, when upscaled to the field. A comprehensive dataset of 48 core plugs over a 65m interval have been studied. The location has industrial application as a target injection site for the discontinued Peterhead CCS project, with the aim to store 10 Mt CO2 over 10 years. These results are also applicable to other storage sites of similar geology. We have carried out steady-state core flooding experiments using medical x-ray CT, providing a detailed characterisation of continuum multiphase flow properties, including residual trapping characteristics, over cm scales. The results show that individual core plugs exhibit a large range in apparent residual trapping at the centimetre scale which averages out over scales of 10s of cm’s or greater. The average Land trapping value at the deca-centimetre scale is 1.7, however, at the cm scale, it varies between 0.8 and 2.8, representing a very large variation in locally trapped CO2. Consequently, at the plug scale for large initial saturations, approaching 1, the apparent residual saturation may vary between 0.2 and 0.5, given the variations in Land trapping parameter. At lower initial saturations, the variations are not as great in absolute terms, but the relative variation is just as large. Continuum numerical models are constructed from observations of residual trapping in heterogeneous rock cores using characterisation methods developed by Jackson et al. (2018, 2020). The trapping stage of a CO2 injection and migration project is simulated over a 65m region, while retaining the impact of heterogeneities at the cm-scale. Results from these models indicate that great care should be taken when upscaling the Land trapping parameter for use in field simulations, to estimate the long-term trapping of CO2 by capillary heterogeneities. Through quantifying the proportion of trapping resulting from capillary heterogeneities, the implications of modelling the system with the average and maximum experimental Land trapping parameter are evaluated. Modelling the system with the maximum experimental core plug Land trapping parameter results in the proportion of trapping caused by capillary heterogeneities to approximately double compared to that obtained using the average experimental core plug Land trapping parameter.

The Mont Terri Underground Research Laboratory (MT-URL) and Consortia affords member organizations the opportunity to bridge the gap between bench and large field scale experiments. At this underground test site, CCP4 (CO 2 Capture Project Phase 4) partners, a four company collaboration that includes BP, Chevron, Petrobras and Suncor, along with the Swiss Topographic Survey (swisstopo) who operates the laboratory, are conducting 1) an experiment that focuses on the mitigation of pressure leakages associated with CO 2 containment in near wellbore injection well systems using novel sealants and, if resources are available, 2) a fractured caprock breach sealing experiment. The mock well system experiment for CO 2 breach mitigation is of immediate interest. This experiment, designated CS-A, is operational with equipment installation accomplished late 2 nd quarter 2015 and experimental protocols that commenced late December 2015 scheduled to run through the summer of 2017. Sealant testing is scheduled to begin in late 2016. The objective is to assess the ability to characterize and seal induced leaks at micro annular interfaces (casing, cement and country rock) using novel sealants with determination of the long term sealing integrity. The 2 nd experiment is in an earlier stage of development, having been scoped in 2014 for costing and resource alignment. This second project requires additional participants to spread costs before the final design is set.

The CO2 Capture Project, currently in its fourth phase (CCP4), is a unique collaborative technology development program initiated in 2000 with participants from corporations, academia, governments, research institutions, policy makers and individual contractors who have come together to advance development of new approaches to capture and store CO2 and improve efficiencies of existing technologies. The overall objectives are to deliver major cost reductions for carbon capture and demonstrate that geological storage is safe, measurable, and verifiable. The 3rd phase of CCP, CCP3, was recognised with a CSLF Global Achievement Award, reflecting CCP’s role as an exemplary model of science-based research, development and demonstration. CCP4 (2015-20) continues to support work in capture and storage at multiple levels of development, spanning concept development to demonstration. CCP4-SMV (storage monitoring and verification) has built on its prior phases in developing CO2 storage assurance technology from modelling / simulation and experiments to field-scale tests. Its current focus is on integrated field tests of cost-effective surveillance technology and evaluating effective responses to unanticipated fluid / pressure migration events (“contingencies”).

Two concepts have been very influential in aiding the evolving understanding of CO 2 storage systems. The first of these was the trapping diagram that first appeared in the IPCC Special Report on CCS (2007). This shows the evolution of the balance of trapping processes – physical seals, capillary trapping, dissolution and reactive trapping - over time. This clearly demonstrated the need to move beyond simplistic estimates of storage capacity to understanding the interplay between the trapping processes. The second was a conceptual model of the evolution of risk through the life of a CO 2 storage site presented by Benson at GHGT-8. This showed risk rising to a peak during injection and then declining back to a low level as the site stabilised post injection. Both of these concepts were presented in diagrammatic form and have been the subject of considerable discussion ever since. As an illustration, opinion remains divided as to whether storage risk peaks and declines or whether it continues to rise as buoyant migration causes the plume to contact an ever increasing area of seal. In this study we use a simplified model based upon vertical equilibrium concepts to develop analytically derived versions of both the IPCC trapping diagram and to explore the risk of seal failure in the post-closure period.

Three locations in the midwestern US were evaluated for saline reservoir sequestration of CO2 transported from refineries and chemical plants along existing pipeline rights-of-way. Based on formation volume calculations, the potential storage capacity in a single formation (the Mt. Simon Sandstone) is in the range of several billion tons. Compositional reservoir simulations using single-well radial models were completed to predict the formation pressures, CO2 spreading, and dissolution following injection. Injectivity at all sites appears to be sufficient for more than 1 Mt/year/well of CO2 without exceeding the fracture pressure limits, and no leakage of CO2 into shallower horizons was predicted. A horizontal injection well scenario showed a smaller increase in reservoir pressure than vertical wells. The geochemical evaluation included a summary of the brine chemistry and mineralogy of the reservoir and caprock formations. Equilibrium geochemical simulations for several scenarios did not indicate any adverse reactions as a result of CO2 injection. A preliminary economic and engineering assessment of several injection scenarios showed that the cost of CO2 dehydration, compression, transport, and injection is nearly $ 20/t, excluding capture costs. The largest capital cost is compression and pipeline systems, and the largest operational cost is compression. System costs may be reduced by optimizing the location of storage reservoirs closer to the emission sources or through development of a regional shared transport network and storage site.