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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 an important consideration for the viability of subsurface CO2 sequestration. Wellbores may leak due to micro annuli that develop between annular cement and steel casing and/or the host formation, as well as fractures and flaws in the cement itself. Leakage pathways may be problematic for the long-term containment of CO2. To address the need for a repair material that can effectively seal and repair wellbores, a new nanotechnology-based sealant has been developed at the University of New Mexico, USA. The sealant, referred to TS-Nano 20™, has superior flowability, excellent bond strength to steel and rock, is very ductile, and is thermally stable. Moreover, the sealant has been demonstrated to readily flow into microcracks below 20 µm under modest pressure gradients. The sealant showed excellent bond strength and superior fatigue resistance to debonding under stress cycles than microfine cement and other sealants. TS-Nano 20™ was used in a field test at the Mont Terri Underground Research Laboratory (MT-URL) located in NW Switzerland. This experimental work at MT-URL 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. A wellbore with a cemented annulus was located beneath the floor of the underground laboratory. The wellbore was intentionally damaged by thermal cycling inside the casing to produce leakage pathways in the wellbore system. The wellbore system included injection ports at several locations along its length to allow pressure and flow tests to be conducted to document the leakage along the length of the wellbore system. Subsequently, various sealants were injected into the injection ports to seal the leakage pathways within the wellbore system. The sealant was then successfully injected into two of the intervals on site. After injection of sealants, the entire wellbore system needed to be stabilized for eventual overcoring and forensic analyses. To this end, a large open hole test interval (uncemented) at the bottom of the wellbore was first filled with a very flowable cement slurry to chase out water and reduce the dead volume, and then the sealant was injected on top of the cement and squeezed into leakage pathways that remained near the bottom of the wellbore system and cracks in the clay formation. Additionally, the sealant was used to further stabilize portions of the wellbore by injecting into all the previously used injection ports. We report on the ability of the nano sealant to maintain its flowability and mechanical characteristics under relatively low temperature and meet all field injection requirements, including having a relatively long-time to gel while hardening after injection. Pressure and permeability measurements from the field tests are reported documenting the ability of the sealant to seal relatively very thin microcracks and create appropriate conditions for overcoring.

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.

Leakage in carbon storage and hydrocarbon wells continues to be an area of concern in the development and abandonment of reservoirs. Industry need for a leakage remediation sealant that can perform in systems beyond the capability of cement squeezes has driven the development of a CO2/pH activated "smart" gel. Exploratory laboratory tests and a mock field scale well test were performed to determine the effectiveness of the smart gel. Control of the smart gel particle size distribution was demonstrated through batch synthesis experiments. Microfluidic experiments show some of the mechanisms leading to the successful sealing of an engineered fracture system. Initial and subsequent testing of the deployed smart gel in a leaky mock well completion proves the effective scale up of the smart gel sealing capability and can further drive wider adoption of this unique technology.

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.