Geology topics

Susan D. Hovorka

Publications and source records attributed to Susan D. Hovorka.

6 recordsLinked to original sources

USGS2012

CO 2 –rock–brine interactions in Lower Tuscaloosa Formation at Cranfield CO 2 sequestration site, Mississippi, U.S.A.

A highly integrated geochemical program was conducted at the Cranfield CO 2 -enhanced oil recovery (EOR) and sequestration site, Mississippi, U.S.A.. The program included extensive field geochemical monitoring, a detailed petrographic study, and an autoclave experiment under in situ reservoir conditions. Results show that mineral reactions in the Lower Tuscaloosa reservoir were minor during CO 2 injection. Brine chemistry remained largely unchanged, which contrasts with significant changes observed in other field tests. Field fluid sampling and laboratory experiments show consistently slow reactions. Carbon isotopic composition and CO 2 content in the gas phase reveal simple two-end-member mixing between injected and original formation gas. We conclude that the reservoir rock, which is composed mainly of minerals with low reactivity (average quartz 79.4%, chlorite 11.8%, kaolinite 3.1%, illite 1.3%, concretionary calcite and dolomite 1.5%, and feldspar 0.2%), is relatively unreactive to CO 2 . The significance of low reactivity is both positive, in that the reservoir is not impacted, and negative, in that mineral trapping is insignificant.

Mississippi↗

USGS2011

Monitoring a large volume CO2 injection: Year two results from SECARB project at Denbury’s Cranfield, Mississippi, USA

The Southeast Regional Carbon Sequestration Partnership (SECARB) early project in western Mississippi has been testing monitoring tools and approaches to document storage efficiency and storage permanence under conditions of CO 2 EOR as well as downdip injection into brine. Denbury Onshore LLC is host for the study and has brought a depleted oil and gas reservoir, Cranfield Field, under CO 2 flood. Injection was started in July 2008 and has now achieved injection rates greater than 1.2 million tons/year though 23 wells, with cumulative mass injected as of August, 2010 of 2.2 million metric tons. Injection is into coarse grained fluvial deposits of the Cretaceous lower Tuscaloosa Formation in a gentle anticline at depths of 3300 m. A team of researchers from 10 institutions has collected data from five study areas, each with a different goal and different spatial and temporal scale. The Phase 2 study began at the start of injection and has been using pressure and temperature as a tool for assessing permanence mostly in the oil productive interval. Real-time read-out shows high sensitivity to distant changes in injection rate and confirms the geologic model of reservoir compartmentalization. Above-zone pressure monitoring &sim;120 m above the injection interval is used to test the sensitivity of this approach for documentation of integrity of the confining system in an area of numerous well completions as pressure increase is induced in the reservoir by more than 70 bar. Monitoring of the High Volume Injection Test (HiVIT) area includes repeat measurements of aqueous geochemistry in the injection zone. Rock-water- CO 2 interactions in the reservoir as CO 2 dissolves are minimized by mineral “armoring” by abundant chlorite cement in high permeability reservoir sandstone. Geochemical monitoring of confined freshwater aquifers at depths of 70–100 m is underway. Groundwater analysis focuses on assessment of the sensitivity of this method to detect leakage above background variability. A repeat seismic survey of the HiVIT is planned for late 2010 to assess saturation change especially in downdip brine-only areas. A study focused on feasibility of monitoring the shallow subsurface to separate leakage from normal complex surface fluxes is underway at an monitoring array installed in October 2009 to assess the interactions of recharge, soil gas, and shallow groundwater aquifers. Recent well re-entry and tracer injection will provide further information to interpret observed elevated deep-sourced methane. The Detailed Area Study (DAS) is collecting dense time-lapse data from closely-spaced three well array of an injector and two observation wells. The observation wells were completed with fiberglass casing to facilitate electrical resistance tomography (ERT) measurements, and a diverse array of instrumentation was both cemented behind casing and suspended on tubing. Injection started at the DAS December 1, 2009. We have measured pulsed neutron and resistivity via wireline, downhole and above-zone pressure, distributed temperature, and fluid chemistry including introduced pulses of perfluorocarbons, noble gases, and SF6 as tracers. Between wells, time-lapse crosswell seismic and electrical resistance tomography (ERT) are used to measure saturation change. The goals are to measure changes as fluids evolve from single phase (brine) to two phase (CO 2 –brine) in order to document linkages between pressure and sweep efficiency. A time-lapse VSP survey bridges the vertical resolution and areal coverage between cross-well and surface seismic. The repeat surveys for many tools are scheduled for September, 2010. Reservoir characterization based on cores, historic and new wireline log data, production history, hydrologic tests, fluid analysis, and a three-D seismic survey have been used in multiple numerical models to predict reservoir response in order to design effective monitoring strategies and optimize deployment. History matching of observed response to predicted response is used to interpret results and improve confidence in conceptual models and numerical approaches. Probabilistic methods have been used to assess the significant uncertainties resulting from reservoir heterogeneity.

Mississippi↗

USGS2009

Potential environmental issues of CO 2 storage in deep saline aquifers: Geochemical results from the Frio-I Brine Pilot test, Texas, USA

Sedimentary basins in general, and deep saline aquifers in particular, are being investigated as possible repositories for large volumes of anthropogenic CO 2 that must be sequestered to mitigate global warming and related climate changes. To investigate the potential for the long-term storage of CO 2 in such aquifers, 1600 t of CO 2 were injected at 1500 m depth into a 24-m-thick "C" sandstone unit of the Frio Formation, a regional aquifer in the US Gulf Coast. Fluid samples obtained before CO 2 injection from the injection well and an observation well 30 m updip showed a Na–Ca–Cl type brine with ∼93,000 mg/L TDS at saturation with CH 4 at reservoir conditions; gas analyses showed that CH 4 comprised ∼95% of dissolved gas, but CO 2 was low at 0.3%. Following CO 2 breakthrough, 51 h after injection, samples showed sharp drops in pH (6.5–5.7), pronounced increases in alkalinity (100–3000 mg/L as HCO 3 ) and in Fe (30–1100 mg/L), a slug of very high DOC values, and significant shifts in the isotopic compositions of H 2 O, DIC, and CH 4 . These data, coupled with geochemical modeling, indicate corrosion of pipe and well casing as well as rapid dissolution of minerals, especially calcite and iron oxyhydroxides, both caused by lowered pH (initially ∼3.0 at subsurface conditions) of the brine in contact with supercritical CO 2 . These geochemical parameters, together with perfluorocarbon tracer gases (PFTs), were used to monitor migration of the injected CO 2 into the overlying Frio “B”, composed of a 4-m-thick sandstone and separated from the “C” by ∼15 m of shale and siltstone beds. Results obtained from the Frio “B” 6 months after injection gave chemical and isotopic markers that show significant CO 2 (2.9% compared with 0.3% CO 2 in dissolved gas) migration into the “B” sandstone. Results of samples collected 15 months after injection, however, are ambiguous, and can be interpreted to show no additional injected CO 2 in the “B” sandstone. The presence of injected CO 2 may indicate migration from “C” to “B” through the intervening beds or, more likely, a short-term leakage through the remedial cement around the casing of a 50-year old well. Results obtained to date from four shallow monitoring groundwater wells show no brine or CO 2 leakage through the Anahuac Formation, the regional cap rock.

Texas↗

USGS2006

Gas-water-rock interactions in Frio Formation following CO 2 injection: Implications for the storage of greenhouse gases in sedimentary basins

To investigate the potential for the geologic storage of CO 2 in saline sedimentary aquifers, 1600 t of CO 2 were injected at 1500 m depth into a 24-m-thick sandstone section of the Frio Formation, a regional brine and oil reservoir in the U.S. Gulf Coast. Fluid samples obtained from the injection and observation wells before CO 2 injection showed a Na-Ca-Cl–type brine with 93,000 mg/L total dissolved solids (TDS) at near saturation with CH 4 at reservoir conditions. Following CO 2 breakthrough, samples showed sharp drops in pH (6.5–5.7), pronounced increases in alkalinity (100–3000 mg/L as HCO 3 ) and Fe (30–1100 mg/L), and significant shifts in the isotopic compositions of H 2 O, dissolved inorganic carbon (DIC), and CH 4 . Geochemical modeling indicates that brine pH would have dropped lower but for the buffering by dissolution of carbonate and iron oxyhydroxides. This rapid dissolution of carbonate and other minerals could ultimately create pathways in the rock seals or well cements for CO 2 and brine leakage. Dissolution of minerals, especially iron oxyhydroxides, could mobilize toxic trace metals and, where residual oil or suitable organics are present, the injected CO 2 could also mobilize toxic organic compounds. Environmental impacts could be major if large brine volumes with mobilized toxic metals and organics migrated into potable groundwater. The δ 18 O values for brine and CO 2 samples indicate that supercritical CO 2 comprises ∼50% of pore-fluid volume ∼6 mo after the end of injection. Postinjection sampling, coupled with geochemical modeling, indicates that the brine gradually will return to its preinjection composition.

Geology↗

USGS2006

Measuring permanence of CO 2 storage in saline formations: The Frio experiment

If CO 2 released from fossil fuel during energy production is returned to the subsurface, will it be retained for periods of time significant enough to benefit the atmosphere? Can trapping be assured in saline formations where there is no history of hydrocarbon accumulation? The Frio experiment in Texas was undertaken to provide answers to these questions. One thousand six hundred metric tons of CO 2 were injected into the Frio Formation, which underlies large areas of the United States Gulf Coast. Reservoir characterization and numerical modeling were used to design the experiment, as well as to interpret the results through history matching. Closely spaced measurements in space and time were collected to observe the evolution of immiscible and dissolved CO 2 during and after injection. The high-permeability, steeply dipping sandstone allowed updip flow of supercritical CO 2 as a result of the density contrast with formation brine and absence of a local structural trap. The front of the CO 2 plume moved more quickly than had been modeled. By the end of the 10-day injection, however, the plume geometry in the plane of the observation and injection wells had thickened to a distribution similar to the modeled distribution. As expected, CO 2 dissolved rapidly into brine, causing pH to fall and calcite and metals to be dissolved. Postinjection measurements, including time-lapse vertical seismic profiling transects along selected azimuths, cross-well seismic topography, and saturation logs, show that CO 2 migration under gravity slowed greatly 2 months after injection, matching model predictions that significant CO 2 is trapped as relative permeability decreases.

Environmental Geosciences↗

USGS2005

The U-tube: A novel system for acquiring borehole fluid samples from a deep geologic CO2 sequestration experiment

A novel system has been deployed to obtain geochemical samples of water and gas, at in situ pressure, during a geologic CO 2 sequestration experiment conducted in the Frio brine aquifer in Liberty County, Texas. Project goals required high-frequency recovery of representative and uncontaminated aliquots of a rapidly changing two-phase fluid (supercritical CO 2 and brine) fluid from 1.5 km depth. The data sets collected, using both the liquid and gas portions of the downhole samples, provide insights into the coupled hydrogeochemical issues affecting CO 2 sequestration in brine-filled formations. While the basic premise underlying the U-tube sampler is not new, the system is unique because careful consideration was given to the processing of the recovered two-phase fluids. In particular, strain gauges mounted beneath the high-pressure surface sample cylinders measured the ratio of recovered brine to supercritical CO 2 . A quadrupole mass spectrometer provided real-time gas analysis for perfluorocarbon and noble gas tracers that were injected along with the CO 2 . The U-tube successfully acquired frequent samples, facilitating accurate delineation of the arrival of the CO 2 plume, and on-site analysis revealed rapid changes in geochemical conditions.

Journal of Geophysical Research Solid Earth↗