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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.

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 (Ho et al. 2016, Tavassoli et al. 2018). 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 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 cement/wellbore interface and adjust the sealant/process to sustain the dynamic geochemical environment of the wellbore.

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.

Publisher Summary This chapter describes the process of geologic storage of CO2 from refineries and chemical plants in the midwestem United States. Three locations in the midwestem United States 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 were completed to predict the formation pressures, CO2 spreading, and dissolution following injection. Injectivity at all sites was 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 per ton, excluding any capture costs. The largest capital cost is in compression and pipeline systems, and the largest operational cost is that of 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.