Abstract. Gas species are widely used as natural or artificial tracers to study fluid dynamics in environmental and geological systems. The recently developed gas-equilibrium membrane-inlet mass spectrometry (GE-MIMS) method is most useful for accurate and autonomous on-site quantification of dissolved gases in aquatic systems. GE-MIMS works by pumping water through a gas equilibrator module containing a gas headspace, which is separated from the water by a gas-permeable membrane. The partial pressures of the gas species in the headspace equilibrate with the gas concentrations in the water according to Henrys Law, and are quantified with a mass spectrometer optimized for low gas consumption (miniRUEDI or similar). However, the fragile membrane structures of the commonly used equilibrator modules break down at water pressures ≳ 3 bar. These modules are therefore not suitable for use in deep geological systems or other environments with high water pressures. To this end, the SysMoG® MD membrane module (Solexperts AG, Switzerland; “SOMM”) was developed to withstand water pressures of up to 100 bar. Compared to the conventionally used GE-MIMS equilibrator modules, the mechanically robust construction of the SOMM module entails slow and potentially incomplete gas/water equilibration. We tested the gas-equilibration efficiency of the SOMM and developed an adapted protocol that allows correct operation of the SOMM for GE-MIMS analysis at high water pressures. This adapted SOMM GE-MIMS technique exhibits a very low gas consumption from the SOMM to maintain the gas/water equilibrium according to Henrys Law and provides the same analytical accuracy and precision as the conventional GE-MIMS technique. The analytical potential of the adapted SOMM GE-MIMS technique was demonstrated in a high-pressure fluid-migration experiment in an underground rock laboratory. The new technique overcomes the pressure limitations of conventional gas equilibrators and thereby opens new opportunities for efficient and autonmous on-site quantification of dissolved gases in high-pressure environments, such as in research and monitoring of underground storage of CO2 and waste deposits, or in the exploration of natural resources.
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.
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.
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