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DOE OSTI2023

Assessment of Carbonated Brine Injection as Low-risk Strategy for Geologic Carbon Storage

The main objective of this early-phase research was to evaluate the techno-economic feasibility and risk associated with combined brine and CO 2 storage in SWD wells using brine dissolution in the North Dakota portion of the Williston Basin. Three simulation studies were conducted to investigate: (1) CO 2 phases at different conditions, (2) wellbore compatibility, and (3) long-term storage fate in reservoir. (1) A simple reservoir model and injection simulations were created using data to represent the BEST (brine extraction and storage test) site, an operational SWD facility located near Watford City, North Dakota. The pressure evolution caused by CO 2 comingled in produced water injectate in a layer cake reservoir was then modeled while tracking aqueous CO 2 throughout the project. The salinity of the injection water, the salinity of the reservoir brine, and the amount of dissolved CO 2 comingled in the injection water were varied. (2) A wellbore corrosion model was performed using the CO 2 concentrations selected based on the reservoir modeling to examine the carbonated produced water impact on wellbore. (3) Reactive transport modeling was conducted with the optimal CO 2 concentration for this injection site to study the rock-fluid interactions and CO 2 fate in the reservoir. Results suggest that CO 2 dissolved in produced water can be injected without appreciably increasing subsurface pressure or leakage risks. Pressure buildup was found to vary with salinity but not with CO 2 mass fraction. Simulation results show that lower CO 2 percent mass fraction leads to a higher amount of CO 2 that can be dissolved at a higher injection salinity. Furthermore, the long-term goal of dissolution trapping in a traditional carbon storage project is accomplished from the start, mitigating risks associated with potential migration of buoyant CO 2 , so long as the reservoir pressure and temperature are used to determine the maximum mass fraction of the dissolved CO 2 .

54 ENVIRONMENTAL SCIENCES↗

NASA NTRS1971

Experimental study of the effects of injection conditions on the flow in cylindrical and spherical chambers.

Fluid mechanics experiments were performed in cylindrical and spherical chambers to evaluate the simulated-fuel containment resulting from various injection geometry and inlet flow conditions for application to the open-cycle GNR. A preliminary study in the cylindrical chamber was directed toward developing inlet flow conditions which minimize mixing between the simulated fuel and propellant. Gas concentration measurements were obtained at several outer-stream to inner-stream weight flow and density ratios for the best inlet configuration tested in the preliminary study. The spherical cavity flow study was conducted to evaluate techniques for injecting simulated-fuel and propellant into a cavity.

Johnson, B. V.↗

DOE OSTI2015

Sauter mean diameter statistics of the starch dispersion atomized with hydraulic nozzle

In the reported research work, the microscopic droplet velocity at different axial and radial locations downstream to the nozzle exit was studied by using a non-intrusive Laser Doppler Anemometry (LDA) techniques. These velocity measurements made in the viscous fluid spray sterams were used to predict the different breakup regimes in the flow. It was noticed that the droplet velocity decreased sharply downstream to the nozzle exit, whereas steady decrease in velocity was seen along the radial directions. For shorter injection time periods, the velocity downstream to the nozzle was not following the general breakup model. However, along the radial direction it exactly followed the discussed model. Along the spray centerline, the velocity was decreasing sharply even at far points from the nozzle exit. It was difficult to identify the core region, transition region and fully developed spray region in the flow. It revealed that the jet breakup was not completed yet and further disintegration was taking place along the spray centerline for shorter injection periods below 250 ms.

71 CLASSICAL AND QUANTUM MECHANICS, GENERAL PHYSIC↗

DOE OSTI2017

Characterizing the Potential for Injection-Induced Fault Reactivation Through Subsurface Structural Mapping and Stress Field Analysis, Wellington Field, Sumner County, Kansas: Injection-Induced Fault Slip, Kansas

Kansas, like other parts of the central U.S., has experienced a recent increase in seismicity. Correlation of these events with brine disposal operations suggests pore fluid pressure increases are reactivating preexisting faults, but rigorous evaluation at injection sites is lacking. Here we determine the suitability of CO 2 injection into the Cambrian-Ordovician Arbuckle Group for long-term storage and into a Mississippian reservoir for enhanced oil recovery in Wellington Field, Sumner County, Kansas. To determine the potential for injection-induced earthquakes, we map subsurface faults and estimate in situ stresses, perform slip and dilation tendency analyses to identify well-oriented faults relative to the estimated stress field, and determine the pressure changes required to induce slip at reservoir and basement depths. Three-dimensional seismic reflection data reveal 12 near-vertical faults, mostly striking NNE, consistent with nodal planes from moment tensor solutions from recent earthquakes in the region. Most of the faults cut both reservoirs and several clearly penetrate the Precambrian basement. Drilling-induced fractures (N = 40) identified from image logs and inversion of earthquake moment tensor solutions (N = 65) indicate that the maximum horizontal stress is approximately EW. Slip tendency analysis indicates that faults striking <020° are stable under current reservoir conditions, whereas faults striking 020°–049° may be prone to reactivation with increasing pore fluid pressure. Although the proposed injection volume (40,000 t) is unlikely to reactive faults at reservoir depths, high-rate injection operations could reach pressures beyond the critical threshold for slip within the basement, as demonstrated by the large number of injection-induced earthquakes west of the study area.

54 ENVIRONMENTAL SCIENCES↗

DOE OSTI2013

Natural CO 2 accumulations in the western Williston Basin: A mineralogical analog for CO 2 injection at the Weyburn site

The Devonian carbonates of the Duperow Formation on the western flank of the Williston Basin in southwest Saskatchewan contain natural accumulations of CO 2 , and may have done so for as long as 50 million years. These carbonate sediments are characterized by a succession of carbonate cycles capped by anhydrite-rich evaporites that are thought to act as seals to fluid migration. The Weyburn CO 2 injection site lies 400 km to the east in a series of Mississippian carbonates that were deposited in a similar depositional environment. That long-term isolation of natural CO 2 can be accomplished within carbonate strata has motivated the investigation of the Duperow rocks as a potential natural analog for storage of anthropogenic CO 2 in carbonate lithologies. For the Duperow strata to represent a legitimate analog for Midale injection and storage, the similarity in lithofacies, whole rock compositions, mineral compositions and porosity with the Midale Beds must be established. Here we compare lithofacies, whole rock compositions, mineralogy and mineral compositions from both locales. The major mineral phases at both locales are calcite, dolomite and anhydrite. In addition, accessory pyrite, fluorite, quartz and celestine (strontium sulfate) are also observed. Dawsonite, a potential CO 2 -trapping mineral, is not observed within the CO 2 -bearing horizons of the Duperow Formation, however. The distribution of porosity in the Midale Vuggy units is similar to that of the Duperow Formation, but the Marly units of the Midale have significantly higher porosity. The Duperow Formation is topped by the Dinesmore evaporite that is rich in anhydrite, and often contains authigenic K-feldspar. The chemistry of dolomite and calcite from the two localities also overlaps. Silicate minerals are in low abundance (<3%) within the analyzed Duperow samples, with quartz and K-feldspar the only silicates observed petrographically or in X-ray diffraction patterns. The Midale Beds contain significantly higher silica/silicate concentrations (Durocher et al., 2003), but the paucity of mono- and divalent cations that can be derived from dissolution of these silicate minerals likely precludes significant carbonate mineral formation. Therefore physical and solution trapping are likely to be the primary CO 2 trapping mechanisms at both sites.

58 GEOSCIENCES↗

DOE OSTI2018

Time Lapse Charged Wellbore Casing Controlled Source Electromagnetic Surveys for Monitoring Injected Carbon Dioxide

Carbon dioxide (CO2) injection for enhanced oil recovery (EOR) and long-term carbon storage extends the life of an oil field while keeping CO2 out of the atmosphere. Monitoring CO2 migration during EOR operations is critical to maximizing production and detecting unexpected CO2 migration quickly. In this project, we monitor CO2 migration using time-lapse charged well casing controlled source electromagnetics (CSEM) at an active EOR site undergoing CO2 injection. Since the electrical conductivity of the reservoir changes as CO2 displaces other fluids, this novel survey technique aims to monitor CO2 injection effectively and unobtrusively from the surface via electromagnetic field measurements. Of four time-lapse field campaigns spaced over two years, we have completed two. Each campaign consists of a CSEM survey supplemented by magnetotelluric and time-domain electromagnetic surveys. In the CSEM survey, a transmitter delivers alternating current to the subsurface at frequencies from 0.125 Hz to 16 Hz using steel well casings as electrodes. Charged well casing surveys detect deeper conductivity contrasts than surveys that use only surface electrodes, allowing CO2 movement at the depth of the reservoir to be imaged more clearly. We transmit on two well pairs. One pair is oriented in the east-west direction, and the other is oriented in the northeast-southwest direction. Receiver stations measure orthogonal components of the electric and magnetic fields. The measurements are repeated at the same locations in each field campaign. Data differences between campaigns provide information about changes in the electrical conductivity of the subsurface. We present the latest results from this ongoing project, including modeling, survey design, data processing techniques, and preliminary results from the field campaigns.

Magnetic and electrical methods, Geomagnetic induc↗

DOE OSTI2015

Pore-scale investigation on stress-dependent characteristics of granular packs and the impact of pore deformation on fluid distribution

Understanding the effect of changing stress conditions on multiphase flow in porous media is of fundamental importance for many subsurface activities including enhanced oil recovery, water drawdown from aquifers, soil confinement, and geologic carbon storage. Geomechanical properties of complex porous systems are dynamically linked to flow conditions, but their feedback relationship is often oversimplified due to the difficulty of representing pore-scale stress deformation and multiphase flow characteristics in high fidelity. In this work, we performed pore-scale experiments of single- and multiphase flow through bead packs at different confining pressure conditions to elucidate compaction-dependent characteristics of granular packs and their impact on fluid flow. A series of drainage and imbibition cycles were conducted on a water-wet, soda-lime glass bead pack under varying confining stress conditions. Simultaneously, X-ray micro-CT was used to visualize and quantify the degree of deformation and fluid distribution corresponding with each stress condition and injection cycle. Micro-CT images were segmented using a gradient-based method to identify fluids (e.g., oil and water), and solid phase redistribution throughout the different experimental stages. Changes in porosity, tortuosity, and specific surface area were quantified as a function of applied confining pressure. Results demonstrate varying degrees of sensitivity of these properties to confining pressure, which suggests that caution must be taken when considering scalability of these properties for practical modeling purposes. Changes in capillary number with confining pressure are attributed to the increase in pore velocity as a result of pore contraction. Furthermore, this increase in pore velocity was found to have a marginal impact on average phase trapping at different confining pressures.

58 GEOSCIENCES↗

DOE OSTI2022

Heat pulse testing at monitoring wells to estimate subsurface fluid velocities in geological CO 2 storage

Monitoring the injected CO 2 during geological CO 2 storage (GCS) is essential to assure containment and identify CO 2 leakage. Here in this work, a new approach is introduced to estimate the evolution of the downhole fluid velocity at a monitoring well and identify CO 2 arrival time using in-well heat pulse/tracer test. The proposed technique involves using a downhole heater to generate a series of heat pulses and measuring their corresponding temperature response. The surface temperature of the downhole heater is controlled by the supplied electrical power and the heat loss by convection to the surroundings. Convective heat transfer is well described using Newton's law of cooling in which the temperature difference between the heater and the surrounding fluids drives the heat transfer, for which the convection heat transfer coefficient (h) controls the magnitude of heat loss. Among various factors that control h, it depends on the type of the flowing fluid and its velocity. Through analyzing the measured temperature at different heat pulses, the changes in h - due to mobilization of the in-situ brine or CO 2 arrival - can be estimated. Consequently, the velocity of the flowing fluid across the heater can be obtained. Since heat transfer by convection is sensitive to the type of the surrounding fluid, intrusion of CO 2 can be detected from the relatively higher surface temperature obtained at CO 2 arrival. Churchill and Bernstein (1977)'s correlation is adopted to estimate the change of fluid velocity in terms of the change in h. To demonstrate the validity of the proposed technique, the results are applied and validated against those of COMSOL Multiphysics simulation tool for single-phase brine (before CO 2 arrival) and single-phase CO 2 (after CO 2 arrival). The observed temperature heating is sensitive to the flowing fluid velocity and fluid type. The temperature signal observed at CO 2 arrival is large and easily detectable using temperature monitoring tool which provides reliable indication for tracking CO 2 arrival at monitoring wells compared with passive temperature monitoring. The results obtained using the proposed technique agree very well with the numerical results obtained from the simulation tool with a maximum estimation error of 7 percent.

02 PETROLEUM↗

DOE OSTI2021

Thermal Stimulation and Injectivity Testing at Raft River, ID EGS Site

The Raft River geothermal field is the site of an innovative Department of Energy Enhanced Geothermal System (EGS) project to determine the viability of using combined thermal and hydraulic stimulation techniques to improve energy production. Well RRG-9 is currently undergoing a stimulation program using injectate from the US Geothermal Raft River Power Plant and cold water from a cooling tower make-up water well. The stimulation began on 13 June 2013 with injection from the power plant at a temperature of about 39 °C and a pressure of 275 psig. Next, two positive displacement plunger type pumps were used to increase the injection pressure and flow rate for about one month. The highest rate achieved was 258 gpm at a pressure of 741 psig. During this time, fluid from the cooler water well was injected for about 2 weeks at various pressures. Then, the pumps were removed and plant injection resumed on 25 September. Plant injection will continue until the spring of 2014, when a high pressure hydraulic stimulation will be conducted. A series of seismic monitoring stations deployed around the well are providing data on seismic events occurring at the site. Over the past year, 51 microseismic events have been recorded, all less than Magnitude 1. During injection, several diagnostic tests were conducted to gain a better understanding of the well and reservoir. A step-rate test was performed on 22 August to measure the in-situ stress and aid in modeling in-situ fractures. A tracer was injected into the well on 9 September. No tracer was detected in adjacent production wells after several months. A second borehole televiewer survey was conducted for comparison to pre-stimulation images. Here, a third borehole televiewer survey is planned after the high pressure stimulation. Injection test data is evaluated in real time. A modified Hall plot analysis indicates the effective permeability is increasing. The injectivity index supports the results of the modified Hall plot analysis. As the thermal stimulation has continued, the injectivity index has consistently followed an upward trend from 0.1 gpm/psi to 0.53 gpm/psi.

enhanced geothermal systems↗

DOE OSTI2022

Comparison of Microbial Profiling and Tracer Testing for the Characterization of Injector-Producer Interwell Connectivities

Insufficient understanding of the microbial communities and associated microbial processes in geological reservoirs hinders the utilization of this rich data source for improved resource management. In this study, along with four interwell tracer tests at a 1478-m deep fractured crystalline-rock aquifer, we analyzed the microbial communities in the injected and produced water by high-throughput sequencing. The microbial community similarities across boreholes during an interwell flow scenario frequently encountered in reservoir development was explored. Despite the significant tracer recoveries (~30%) in all tracer tests and the cumulatively >100,000 L of exogenous water (carrying exogenous microbes) injected into the 10-m-scale reservoir, the overall structure of produced-fluid microbiome did not increasingly resemble that of the injectate. However, producers with better connectivity with the injector (based on tracer test results) did have more amplicon sequence variants (ASVs) that overlapped with those in the injectate. We identified possible drivers behind our observations and verified the practicality of repeated microbial sampling in the context of reservoir characterization and long-term monitoring. We highlight that injector-producer microbial profiling could provide insights on the relative connectivities across different producers with a given injector, and that the associated logistical needs may be comparable or even less than that of classic tracer tests.

59 BASIC BIOLOGICAL SCIENCES↗

NASA NTRS2017

Computational and Experimental Characterization of the Mach 6 Facility Nozzle Flow for the Enhanced Injection and Mixing Project at NASA Langley Research Center

Computational fluid dynamics analyses and experimental data are presented for the Mach 6 facility nozzle used in the Arc-Heated Scramjet Test Facility for the Enhanced Injection and Mixing Project (EIMP). This project, conducted at the NASA Langley Research Center, aims to investigate supersonic combustion ramjet (scramjet) fuel injection and mixing physics relevant to flight Mach numbers greater than 8. The EIMP experiments use a two-dimensional Mach 6 facility nozzle to provide the high-speed air simulating the combustor entrance flow of a scramjet engine. Of interest are the physical extent and the thermodynamic properties of the core flow at the nozzle exit plane. The detailed characterization of this flow is obtained from three-dimensional, viscous, Reynolds-averaged simulations. Thermodynamic nonequilibrium effects are also investigated. The simulations are compared with the available experimental data, which includes wall static pressures as well as in-stream static pressure, pitot pressure and total temperature obtained via in-stream probes positioned just downstream of the nozzle exit plane.

Drozda, Tomasz G.↗

NASA NTRS1999

Effects of subfornical organ lesions on acutely induced thirst and salt appetite

We examined the role of the subfornical organ (SFO) in stimulating thirst and salt appetite using two procedures that initiate water and sodium ingestion within 1-2 h of extracellular fluid depletion. The first procedure used injections of a diuretic (furosemide, 10 mg/kg sc) and a vasodilator (minoxidil, 1-3 mg/kg ia) to produce hypotension concurrently with hypovolemia. The resulting water and sodium intakes were inhibited by intravenous administration of ANG II receptor antagonist (sarthran, 8 micrograms . kg(-1). min(-1)) or angiotensin-converting enzyme inhibitor (captopril, 2.5 mg/h). The second procedure used injections of furosemide (10 mg/kg sc) and a low dose of captopril (5 mg/kg sc) to initiate water and sodium ingestion upon formation of ANG II in the brain. Electrolytic lesions of the SFO greatly reduced the water intakes, and nearly abolished the sodium intakes, produced by these relatively acute treatments. These results contrast with earlier findings showing little effect of SFO lesions on sodium ingestion after longer-term extracellular fluid depletion.

NASA Discipline Regulatory Physiology↗

DOE OSTI2012

Zero Discharge Water Management for Horizontal Shale Gas Well Development

Hydraulic fracturing technology (fracking), coupled with horizontal drilling, has facilitated exploitation of huge natural gas (gas) reserves in the Devonian-age Marcellus Shale Formation (Marcellus) of the Appalachian Basin. The most-efficient technique for stimulating Marcellus gas production involves hydraulic fracturing (injection of a water-based fluid and sand mixture) along a horizontal well bore to create a series of hydraulic fractures in the Marcellus. The hydraulic fractures free the shale-trapped gas, allowing it to flow to the well bore where it is conveyed to pipelines for transport and distribution. The hydraulic fracturing process has two significant effects on the local environment. First, water withdrawals from local sources compete with the water requirements of ecosystems, domestic and recreational users, and/or agricultural and industrial uses. Second, when the injection phase is over, 10 to 30% of the injected water returns to the surface. This water consists of flowback, which occurs between the completion of fracturing and gas production, and produced water, which occurs during gas production. Collectively referred to as returned frac water (RFW), it is highly saline with varying amounts of organic contamination. It can be disposed of, either by injection into an approved underground injection well, or treated to remove contaminants so that the water meets the requirements of either surface release or recycle use. Depending on the characteristics of the RFW and the availability of satisfactory disposal alternatives, disposal can impose serious costs to the operator. In any case, large quantities of water must be transported to and from well locations, contributing to wear and tear on local roadways that were not designed to handle the heavy loads and increased traffic. The search for a way to mitigate the situation and improve the overall efficiency of shale gas production suggested a treatment method that would allow RFW to be used as make-up water for successive fracs. RFW, however, contains dissolved salts, suspended sediment and oils that may interfere with fracking fluids and/or clog fractures. This would lead to impaired well productivity. The major technical constraints to recycling RFW involves: identification of its composition, determination of industry standards for make-up water, and development of techniques to treat RFW to acceptable levels. If large scale RFW recycling becomes feasible, the industry will realize lower transportation and disposal costs, environmental conflicts, and risks of interruption in well development schedules.

03 NATURAL GAS↗

NASA NTRS1992

Workshop report - A validation study of Navier-Stokes codes for transverse injection into a Mach 2 flow

A CFD (Computational Fluid Dynamics) competition was held at the Third Scramjet Combustor Modeling Workshop to assess the current state-of-the-art in CFD codes for the analysis of scramjet combustors. Solutions from six three-dimensional Navier-Stokes codes were compared for the case of staged injection of air behind a step into a Mach 2 flow. This case was investigated experimentally at the University of Virginia and extensive in-stream data was obtained. Code-to-code comparisons have been made with regard to both accuracy and efficiency. The turbulence models employed in the solutions are believed to be a major source of discrepancy between the six solutions.

Eklund, Dean R.↗

DOE OSTI2018

Staged fuel and air injection in combustion systems of gas turbines

A gas turbine including a working fluid flowpath extending aftward from a forward injector in a combustor. The combustor may include an inner radial wall, an outer radial wall, and, therebetween, a flow annulus, and a third radial wall formed about the outer radial wall that forms an outer flow annulus. A staged injector may intersect the flow annulus so to attain an injection point within the working fluid flowpath by which aftward and forward annulus sections are defined. Air directing structure may include an aftward intake section corresponding to the aftward annulus section and a forward intake section corresponding to the forward annulus section. The air directing structure may include a switchback coolant flowpath to direct air from the compressor discharge cavity to the staged injector. The switchback coolant flowpath may include an upstream section through the flow annulus, and a downstream section through the outer flow annulus.

33 ADVANCED PROPULSION SYSTEMS↗

DOE OSTI2014

An investigation of reaction parameters on geochemical storage of non-pure CO2 streams in iron oxides-bearing formations

Hematite deposit that is the main FeIII-bearing mineral in sedimentary red beds was proposed as a potential host repository for converting CO2 into carbonate minerals such as siderite (FeCO3), when CO2–SO2 gas mixtures are co-injected. This work investigated CO2 mineral trapping using hematite and sensitivity of the reactive systems to different parameters, including particle size, gas composition, temperature, pressure, and solid-to-liquid ratio. Experimental and modelling studies of hydrothermal experiments were conducted, which emulated a CO2 sequestration scenario by injecting CO2-SO2 gas streams into a NaCl-NaOH brine hosted in iron oxide-containing aquifer. This study provides novel information on the mineralogical changes and fluid chemistry derived from the co-injection of CO2-SO2 gas mixtures in hematite deposit. It can be concluded that the amount of siderite precipitate depends primarily on the SO2 content of the gas stream. Increasing SO2 content in the system could promote the reduction of Fe3+ from the hematite sample to Fe2+, which will be further available for its precipitation as siderite. Moreover, siderite precipitation is enhanced at low temperatures and high pressures. The influence of the solid to liquid ratio on the overall carbonation reaction suggests that the conversion increases if the system becomes more diluted.

CO2 storage↗

DOE OSTI2018

Staged fuel and air injection in combustion systems of gas turbines

A gas turbine that includes a working fluid flowpath extending aftward from a forward injector in a combustor. The combustor may include an inner radial wall, an outer radial wall, and, therebetween, a flow annulus. A staged injector may intersect the flow annulus so to attain an injection point within the working fluid flowpath by which aftward and forward annulus sections are defined. Air directing structure may include an aftward intake section that corresponds to the aftward annulus section and a forward intake section that corresponds to the forward annulus section. The air directing structure may be configured to: direct air entering through the aftward intake section through the aftward annulus section in a forward direction to the staged injector; and direct air entering through the forward intake section through the forward annulus section in a forward direction to the forward injector.

42 ENGINEERING↗

DOE OSTI2018

Staged fuel and air injection in combustion systems of gas turbines

42 ENGINEERING↗