Mailing Address
James Patterson
Geothermal Energy & Geofluids
Institute of Geophysics
NO F 61.1
Sonneggstrasse 5
CH-8092 Zurich Switzerland
Contact
| Phone | +41 44 633 2751 |
| james.patterson(at)eaps.ethz.ch |
Administration
| Prisca Maurantonio | |
| +41 44 632 3465 | |
| prisca.maurantonio@eaps.ethz.ch | |
Publications
[Go to Proceedings Refereed] [Go to Proceedings Non-Refereed] [Go to Theses]
Underlined names are links to current or past GEG members
REFEREED PUBLICATIONS IN JOURNALS
5.
Patterson, JW, and T Driesner, Elastic and Thermoelastic Effects on Thermal Water Convection in Fracture Zones, Journal of Geophysical Research: Solid Earth, 126, 2021. https://doi.org/10.1029/2020JB020940 [Download] [View Abstract]Natural groundwater convection in fractures is an important mechanism of mass and heat transfer in the subsurface, locally altering temperature by several tens of degrees. The thermoelastic stresses resulting from these thermal anomalies induce thermal strains, which in turn alter the transmissivity (permeability times thickness) of the fracture and, therefore, the convective flow within. We investigate the effect of thermal strains on fracture convection patterns using a three‐dimensional thermo‐hydraulic‐mechanical numerical model, implementing the Barton‐Bandis relationship between fracture transmissivity and effective normal stress, which results in a downward‐narrowing of the fractures. When thermoelasticity is not taken into account, convection forms narrow upflow zones and wide downflow zones. Decreasing fracture stiffness results in similar upflow/downflow patterns, but restricted to the shallow portions of the fracture, creating relatively minor thermal changes. When thermo‐elasticity is included in the model, thermal strains induced by cool downflow zones create narrow high‐transmissivity channels within the fracture, allowing convective flow to reach greater depths and significantly reducing the geothermal gradient near the fracture. Fracture stiffness is a key parameter in determining convection depth and thermal perturbation strength for a given set of host rock mechanical properties. When fracture stiffness is below some threshold, subsequent contractive thermoelastic strains were found to induce tensile failure of the host rock below the fracture, propagating and deepening the fracture into the host rock. This observation provides support to the previously proposed concept of convective downward migration.
4.
Patterson, JW, and T Driesner, The effect of thermo-elastic stress re-distribution on geothermal production from a vertical fracture zone, Geothermics, 85, 2020. https://doi.org/10.1016/j.geothermics.2019.101745 [Download] [View Abstract]Injection of cold water into fracture zones in Enhanced Geothermal Systems (EGS) induces contractive thermo-elastic strains in the host rock, locally altering the stress state of the reservoir. Building on previous studies with horizontal fractures we examined how such thermo-elastic effects act during injection and production from a doublet intersecting a vertically extensive fracture zone embedded in impermeable host rock with a vertical geothermal gradient and with vertical aperture variations in response to stress increase with depth. As in horizontal fracture zones, contractive strains propagate outward from point of injection of cold water and are surrounded, due to stress re-distribution, by a ring zone with increased effective normal stress and, therefore, reduced aperture. The reduced aperture ring affects production temperature evolution to different degrees: for fracture zones with initially homogeneous transmissivity the effect on temperature decline is most pronounced for injection in the deeper well while it is small to negligible for injection in the shallower well. Fractures zones with initially heterogeneous transmissivity distribution experience highly channelized flow and the enhanced normal stresses develop preferentially at the sides of the channels, having little effect on flow along the channel and temperature decline. The effects show systematic variation with the rock's Young's modulus as does the tendency to induce shear failure by thermo-elastic effects. The simulated temperature evolutions deviate significantly from previous models that assessed the economics of EGS with sub-horizontal wells intersecting vertically extensive fractures in which the geothermal gradient and thermo-mechanical were not included.
3.
Patterson, JW, T Driesner, SK Matthai, and R Thomlinson, Heat and Fluid Transport Induced by Convective Fluid Circulation Within a Fracture or Fault, Journal of Geophysical Research: Solid Earth, 123, 2018. https://doi.org/10.1002/2017JB015363 [Download] [View Abstract]Natural water convection in subvertical fractures, fracture zones, or faults can perturb the temperature field around the fracture and enhance and focus vertical heat flow within. We investigate, by means of numerical simulation, the effects of convection in a deeply buried vertical fracture zone. Fracture zone transmissivity, defined as permeability times thickness of the permeable region, is found to be the primary control on convection style rather than fracture zone thickness or permeability alone. In an impermeable host rock, the convection-induced thermal anomaly propagates solely via conduction, diminishing away from the fracture. Convective heat flow increases with fracture transmissivity up to ~10−8 m3, when a plateau in convective heat flow is reached, constrained by fracture size and the host rock's thermal conductivity. Permeable host rocks modify these results significantly. In a moderately permeable host rock (10−14 m2), convection in the fracture induces non-Rayleigh fluid convection, while thermal effects and fluid exchange between host rock and fracture remain moderate. If the host rock is sufficiently permeable to allow porous medium Rayleigh convection to occur (10−13 m2), the convection patterns within the fracture are overprinted by the host's convective patterns. Fluid exchange between the fracture and the rock will be significant. Our findings provide insight into how thermal anomalies in the uppermost crust may relate to locally enhanced heat flow from convection in nonoutcropping fractures below. Furthermore, the results for permeable host rocks provide evidence for previously inferred hydrologic scenarios for the formation of certain hydrothermal, vein-type mineral deposits.
2.
Patterson, JW, T Driesner, and SK Matthai, Self-Organizing Fluid Convection Patterns in an en Echelon Fault Array, Geophysical Research Letters, 45, 2018. https://doi.org/10.1029/2018GL078271 [Download] [View Abstract]We present three-dimensional numerical simulations of natural convection in buried, vertical en echelon faults in impermeable host rock. Despite the fractures being hydraulically disconnected, convection within each fracture alters the temperature field in the surrounding host rock, altering convection in neighboring fractures. This leads to self-organization of coherent patterns of upward/downward flow and heating/cooling of the host rock spanning the entire fault array. This "synchronization" effect occurs when fracture spacing is less than the width of convection cells within the fractures, which is controlled by fracture transmissivity (permeability times thickness) and heterogeneity. Narrow fracture spacing and synchronization enhance convective fluid flow within fractures and cause convection to initiate earlier, even lowering the critical transmissivity necessary for convection initiation. Heat flow through the en echelon region, however, is enhanced only in low-transmissivity fractures, while heat flow in high-permeability fractures is reduced due to thermal interference between fractures.
1.
Ho, JF, S Tavassoli, JW Patterson, and M Shafiei, The Use of a pH-Triggered Polymer Gelant to Seal Cement Fractures in Wells, SPE Drilling & Completion, 31, 2016. https://doi.org/10.2118/174940-PA [Download] [View Abstract]The potential leakage of hydrocarbon fluids or carbon dioxide (CO2) out of subsurface formations through wells with fractured cement or debonded microannuli is a primary concern in oil-and-gas production and CO2 storage. The presence of fractures in a cement annulus with apertures on the order of 10–300 µm can pose a significant leakage danger with effective permeability in the range of 0.1–1.0 md. Leakage pathways with small apertures are often difficult for conventional oilfield cement to repair; thus, a low-viscosity sealant that can be placed into these fractures easily while providing a long-term robust seal is desired. The development of a novel application with pH-triggered polymeric sealants could potentially be the solution to plugging these fractures. The application is based on the transport and reaction of a low-pH poly(acrylic acid) polymer through fractures in strongly alkaline cement. The pH-sensitive microgels viscosify after neutralization with cement to become highly swollen gels with substantial yield stress that can block fluid flow. Experiments in a cement fracture determined the effects of the viscosification and gel deposition with real-time visual observation and measurements of pressure gradient and effluent pH. Although the pH-triggered gelling mechanism and rheology measurements of the polymer gel show promising results, the polymer solution undergoes a reaction caused by the release of calcium cations from cement that collapses the polymer network (syneresis). It produces an undesirable calcium-precipitation byproduct that is detrimental to the strength and stability of the gel in place. As a result, gel-sealed leakage pathways that were subjected to various degrees of syneresis often failed to hold backpressures. Multiple chemicals were tested for pretreatment of cement cores to remove calcium from the cement surface zone to inhibit syneresis during polymer placement. A chelating agent, sodium triphosphate (Na5P3O10), was found to successfully eliminate syneresis without compromising the injectivity of polymer solution during placement. Polymer-gel strength is determined by recording the maximum-holdback pressure gradients during liquid-breakthrough tests after various periods of pretreatment and polymer shut-in time. Cores pretreated with Na5P3O10 successfully held up to an average of 70 psi/ft, which is significantly greater than the range of pressure gradients expected in CO2-storage applications. The use of such inexpensive, pH-triggered polyacrylic acid polymer allows the sealing of leakage pathways effectively under high-pH conditions.
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PROCEEDINGS REFEREED
2.
Byrne, DJ, JW Patterson, PM Rendel, and BW Mountain, The effect of CO2 reinjection on silica scaling in geothermal reservoirs, Proceedings 44th New Zealand Geothermal Workshop, 2023. [Download PDF] [View Abstract]The capture and reinjection of the noncondensable gases (NCG) that are associated with geothermal brine production is a key technology to ensure that geothermal energy remains a sustainable part of Aotearoa's transition to a low carbon economy. Whilst several pilot schemes are underway to trial the viability of NCG reinjection, its potential effects on reservoir geochemistry are not well understood. Here, we present a combined experimental and modelling approach to investigate the effect of the incorporation of CO2 (the primary component of the NCG fraction in NZ geothermal brines) into reinjected brines. Four experimental reinjection simulations were performed in high-PT flow-through reactors under geochemical conditions relevant to New Zealand geothermal reservoirs, with varying levels of added CO2. The empirical observations collected as part of these experiments were used to constrain the rate parameters of a reactive transport model built using PFLOTRAN that can accurately reproduce the geochemical behaviour of the experiments. This numerical model can then be used to extend our investigation to the relevant spatial and temporal scales required to understand the long-term reservoir response to NCG reinjection. We show that for acid-dosed brines, addition of CO2 can significantly reduce the rate of silica scaling in reservoir. This has significant implications for reducing the injectivity decline of reinjection wells, which may help realise previously underappreciated cost savings achieved by NCG reinjection technologies. We demonstrate a framework whereby this combined experimental-modelling approach can be used to quantify the effect on silica scaling for any brine-reservoir rock combination, with the aim of helping to de-risk and accelerate the deployment of NCG reinjection technologies across the NZ geothermal sector.
1.
Tavassoli, S, L Mejia, M Shafiei, C Minnig, J Gisiger, U Rösli, JW Patterson, T Theurillat, H Goodman, T Espie, and M Balhoff, Pilot Test of pH Triggered Polymer Sealant for CO2 Storage, 15th International Conference on Greenhouse Gas Control Technologies, GHGT-15, 2021. https://doi.org/10.2139/ssrn.3820926 [Download] [View Abstract]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.