Summary We present a study of the low–salinity effect during oil recovery using microfluidics experiments in an attempt to narrow the gap between pore–scale observations and porous–media–flow mechanisms, and to explain one type of low–salinity effect with delayed oil recovery and without the presence of clay. A microfluidic toolbox is used, including single–pore–scale microchannels, a pore–network–scale (approximately 102 pores) micromodel, and a reservoir–on–a–chip model (approximately 104 pores with heterogeneity), all with 2D connectivity. Experiments at the single–pore scale reveal a time–dependent oil dewetting and swelling behavior when a crude–oil droplet is in contact with low–salinity water. An interplay between water chemical potential and oil–phase polar compounds explains this pore–scale observation well. Experiments at the pore–network scale illustrate that the dewetting and swelling of residual oil in the swept region increase the water–flow resistance, modifying the flow field and thus redirecting the flooding liquid into unswept regions. This pore–network–scale effect is re–expressed into a macroscale model as a sweep–efficiency improvement derived from the change of relative permeabilities, which requires time to develop. Finally, experiments on our “reservoir–on–a–chip” model show significant incremental oil recovery during tertiary low–salinity waterflooding and confirm that late–time sweep–efficiency improvement contributes to most of the incremental oil recovery. On the basis of this microfluidic framework, we emphasize the following three findings: Low–salinity tertiary waterflooding can improve oil recovery by an improvement of sweep efficiency, which is a consequence of residual–oil dewetting and swelling.The low–salinity effect can occur without the existence of clay.The wettability alteration and oil swelling are time–dependent processes and should be expressed as a function of oil/water contact time rather than dimensionless time [pore volume (PV)], which explains some observations from previous coreflood experiments.
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.
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