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At least 505 records · Page 28
All sourcesNASA NTRSDOE OSTI
DOE OSTI2016

Fault structure, stress, or pressure control of the seismicity in shale? Insights from a controlled experiment of fluid-induced fault reactivation

It is clear that clay formations are present in reservoirs and earthquake faults, but questions remain on their mechanical behavior, as they can vary from ductile (aseismic) to brittle (seismic). An experiment, at a scale of 10 m, aims to reactivate a natural fault by fluid pressure in shale materials. The injection area was surrounded by a dense monitoring network comprising pressure, deformation, and seismicity sensors, in a well-characterized geological setting. Thirty-two microseismic events were recorded during several injection phases in five different locations within the fault zone. Their computed magnitude ranged between -4.3 and -3.7. Their spatiotemporal distribution, compared with the measured displacement at the injection points, shows that most of the deformation induced by the injection is aseismic. Whether the seismicity is controlled by the fault architecture, mineralogy of fracture filling, fluid, and/or stress state is then discussed. The fault damage zone architecture and mineralogy are of crucial importance, as seismic slip mainly localizes on the sealed-with-calcite fractures which predominate in the fault damage zone. As no seismicity is observed in the close vicinity of the injection areas, the presence of fluid seems to prevent seismic slips. The fault core acts as an impermeable hydraulic barrier that favors fluid confinement and pressurization. Therefore, the seismic behavior seems to be strongly sensitive to the structural heterogeneity (including permeability) of the fault zone, which leads to a heterogeneous stress response to the pressurized volume.

58 GEOSCIENCES↗
DOE OSTI2013

Predictive modeling of CO2 sequestration in deep saline sandstone reservoirs: Impacts of geochemical kinetics

One idea for mitigating the increase in fossil-fuel generated CO{sub 2} in the atmosphere is to inject CO{sub 2} into subsurface saline sandstone reservoirs. To decide whether to try such sequestration at a globally significant scale will require the ability to predict the fate of injected CO{sub 2}. Thus, models are needed to predict the rates and extents of subsurface rock-water-gas interactions. Several reactive transport models for CO{sub 2} sequestration created in the last decade predicted sequestration in sandstone reservoirs of ~17 to ~90 kg CO{sub 2} m{sup -3|. To build confidence in such models, a baseline problem including rock + water chemistry is proposed as the basis for future modeling so that both the models and the parameterizations can be compared systematically. In addition, a reactive diffusion model is used to investigate the fate of injected supercritical CO{sub 2} fluid in the proposed baseline reservoir + brine system. In the baseline problem, injected CO{sub 2} is redistributed from the supercritical (SC) free phase by dissolution into pore brine and by formation of carbonates in the sandstone. The numerical transport model incorporates a full kinetic description of mineral-water reactions under the assumption that transport is by diffusion only. Sensitivity tests were also run to understand which mineral kinetics reactions are important for CO{sub 2} trapping. The diffusion transport model shows that for the first ~20 years after CO{sub 2} diffusion initiates, CO{sub 2} is mostly consumed by dissolution into the brine to form CO{sub 2,aq} (solubility trapping). From 20-200 years, both solubility and mineral trapping are important as calcite precipitation is driven by dissolution of oligoclase. From 200 to 1000 years, mineral trapping is the most important sequestration mechanism, as smectite dissolves and calcite precipitates. Beyond 2000 years, most trapping is due to formation of aqueous HCO{sub 3}{sup -}. Ninety-seven percent of the maximum CO{sub 2} sequestration, 34.5 kg CO{sub 2} per m{sup 3} of sandstone, is attained by 4000 years even though the system does not achieve chemical equilibrium until ~25,000 years. This maximum represents about 20% CO{sub 2} dissolved as CO{sub 2},aq, 50% dissolved as HCO{sub 3}{sup -}{sub ,aq}, and 30% precipitated as calcite. The extent of sequestration as HCO{sub 3}{sup -} at equilibrium can be calculated from equilibrium thermodynamics and is roughly equivalent to the amount of Na+ in the initial sandstone in a soluble mineral (here, oligoclase). Similarly, the extent of trapping in calcite is determined by the amount of Ca2+ in the initial oligoclase and smectite. Sensitivity analyses show that the rate of CO{sub 2} sequestration is sensitive to the mineral-water reaction kinetic constants between approximately 10 and 4000 years. The sensitivity of CO{sub 2} sequestration to the rate constants decreases in magnitude respectively from oligoclase to albite to smectite.

54 ENVIRONMENTAL SCIENCES↗
DOE OSTI2018

Design and implementation of a shearing apparatus for the experimental study of shear displacement in rocks

Fluid flow in the subsurface is not well understood in the context of “impermeable” geologic media. This is especially true of formations that have undergone significant stress fluctuations due to injection or withdrawal of fluids that alters the localized pressure regime. When the pressure regime is altered, these formations, which are often already fractured, move via shear to reduce the imbalance in the stress state. While this process is known to happen, the evolution of these fractures and their effects on fluid transport are still relatively unknown. Numerous simulation and several experimental studies have been performed that characterize the relationship between shearing and permeability in fractures; while many of these studies utilize measurements of fluid flow or the starting and ending geometries of the fracture to characterize shear, they do not characterize the intermediate stages during shear. We present an experimental apparatus based on slight modifications to a commonly available Hassler core holder that allows for shearing of rocks, while measuring the hydraulic and mechanical changes to geomaterials during intermediate steps. The core holder modification employs the use of semi-circular end caps and structural supports for the confining membrane that allow for free movement of the sheared material while preventing membrane collapse. By integrating this modified core holder with a computed tomography scanner, we show a new methodology for understanding the interdependent behavior between fracture structure and flow properties during intermediate steps in shearing. Here, we include a case study of this device function which is shown here through shearing of a fractured shale core and simultaneous observation of the mechanical changes and evolution of the hydraulic properties during shearing.

58 GEOSCIENCES↗
DOE OSTI2017

Screening improved recovery methods in tight-oil formations by injecting and producing through fractures

Tight-oil reservoirs exhibit two characteristic behaviors that limit potential for improved recovery: (i) limited fluid movement from the unfractured matrix limits the potential to sweep additional oil towards the production wells with injection of a displacing fluid, (ii) the wettability of these reservoirs tend to be oil-wet which holds oil in relatively smaller pores, as compared to gas or water, making it difficult to mobilize that trapped oil. Primary oil production from these formations can decline to half of initial rates in the first year due to low permeability in the unfractured reservoir matrix, and a large amount of unrecovered oil remains in smaller pores that is not able to move out. To address these challenges, this study investigates the potential to improve oil recovery from tight-oil reservoirs by a method that includes injecting a fluid into the fractured reservoir to produce hydrocarbons from adjacent fractures intersecting the same wellbore. The injection and production through fractures has a potential economic advantage over huff-n-puff scheme such that there is no lag-period between injection and production. We compare the estimates of incremental oil recovery obtained by injecting water, immiscible CO 2 , and surfactant over the oil recovered by primary depletion (with no injection). The results suggest that injection of fluids may not always improve recovery from tight-oil reservoirs, especially in a heterogeneous reservoir (having different rock types) whose average matrix permeability is lower than 0.01 mD. In cases where recovery is improved over primary depletion, water flood and surfactant flood perform almost equally well with no noticeable difference between the two. Although, surfactant results in favorable fluid properties to mobilize oil, the reason surfactant did not perform well in tight-oil formation studied here is because the unswept oil is inaccessible due to small permeability, and not because of high capillary pressure.

42 ENGINEERING↗
DOE OSTI2019

Pore habit of methane hydrate and its evolution in sediment matrix – Laboratory visualization with phase-contrast micro-CT

Describing the pore habit of methane hydrate in sediment matrices is essential for understanding natural distribution of methane hydrate, methane trace (transport and solidification) in the hydrate stability zone, physical properties of hydrate-bearing sediments, and the associated influence on potential gas production. Pore habit visualization in natural media at pore scale even with laboratory synthesized cores has been challenging due to the similar densities of methane hydrate from pore liquid. In this work, we used phase-contrast assisted micro-CT with potassium iodine-doped brine to visualize four phases: sand particles, pore fluid, methane hydrate and methane gas. This study visualizes the pore habit of methane hydrate at various stages including during hydrate formation in excess-gas systems, its evolution after brine injection to replace pore fluid, and hydrate formation in excess-water systems. Hydrate tends to adopt round and smooth surfaces when in contact with water while exhibits relatively angular interfaces when in contact with methane gas. Hydrate formation in excess-gas systems results in a partial cementing and partial mineral-coating pore habit, while hydrate in excess-water systems develops mainly as pore-filling, and locally cementing or mineral-coating where big gas pockets exist at the initial state. Pore liquid replacement from methane gas to brine triggers a shift of hydrate pore habit towards pore-filling. Methane hydrate evolution over time produces bigger hydrate particles but with less contact area with sand particles. The effects of hydrate pore habit become less important as hydrate particle size exceeds the pore size. Additionally, hydrate formation could trap residual methane gas and brine as inclusions.

58 GEOSCIENCES↗
DOE OSTI2014

Fracture Propagation, Fluid Flow, and Geomechanics of Water-Based Hydraulic Fracturing in Shale Gas Systems and Electromagnetic Geophysical Monitoring of Fluid Migration

We investigate fracture propagation induced by hydraulic fracturing with water injection, using numerical simulation. For rigorous, full 3D modeling, we employ a numerical method that can model failure resulting from tensile and shear stresses, dynamic nonlinear permeability, leak-off in all directions, and thermo-poro-mechanical effects with the double porosity approach. Our numerical results indicate that fracture propagation is not the same as propagation of the water front, because fracturing is governed by geomechanics, whereas water saturation is determined by fluid flow. At early times, the water saturation front is almost identical to the fracture tip, suggesting that the fracture is mostly filled with injected water. However, at late times, advance of the water front is retarded compared to fracture propagation, yielding a significant gap between the water front and the fracture top, which is filled with reservoir gas. We also find considerable leak-off of water to the reservoir. The inconsistency between the fracture volume and the volume of injected water cannot properly calculate the fracture length, when it is estimated based on the simple assumption that the fracture is fully saturated with injected water. As an example of flow-geomechanical responses, we identify pressure fluctuation under constant water injection, because hydraulic fracturing is itself a set of many failure processes, in which pressure consistently drops when failure occurs, but fluctuation decreases as the fracture length grows. We also study application of electromagnetic (EM) geophysical methods, because these methods are highly sensitive to changes in porosity and pore-fluid properties due to water injection into gas reservoirs. Employing a 3D finite-element EM geophysical simulator, we evaluate the sensitivity of the crosswell EM method for monitoring fluid movements in shaly reservoirs. For this sensitivity evaluation, reservoir models are generated through the coupled flow-geomechanical simulator and are transformed via a rock-physics model into electrical conductivity models. It is shown that anomalous conductivity distribution in the resulting models is closely related to injected water saturation, but not closely related to newly created unsaturated fractures. Our numerical modeling experiments demonstrate that the crosswell EM method can be highly sensitive to conductivity changes that directly indicate the migration pathways of the injected fluid. Accordingly, the EM method can serve as an effective monitoring tool for distribution of injected fluids (i.e., migration pathways) during hydraulic fracturing operations

02 PETROLEUM↗
NASA NTRS1979

Flow visualization of discrete-hole film cooling with spanwise injection over a cylinder

Insight into the fluid mechanics encountered when film air from a single row of holes is injected over a cylinder in a mainstream at conditions simulating a film cooled, turbulent-vane leading edge was investigated. Smoke was added to the cooling air to visualize its flow path. Film was injected in the spanwise direction at angles of 30 deg and 45 deg to the surface; at angular locations of 15 deg, 30 deg, 45 deg, and 60 deg from the stagnation line; and at various blowing ratios. The observations were related to the measured heat transfer data of others. The results indicate that, in addition to the expected growth in film thickness and the greater penetration of the boundary layer with increasing blowing ration, there was an absence of spanwise spreading and only a small spanwise deflection of the injected film.

Russell, L. M.↗
DOE OSTI2018

Joint opening or hydroshearing? Analyzing a fracture zone stimulation at Fenton Hill

Here, we analyze a deep hydraulic stimulation of a fracture zone that was conducted as part of the classical Fenton Hill Hot Dry Rock Program in the 1970s. At the time, it was suggested that a pre-existing fracture or multiple fractures within the fracture zone were jacked open by injection-induced increase in pressure. In this study, we analyze the same stimulation experiment, but investigate the possibility of an alternative mechanism of shear reactivation of pre-existing fractures. We conduct modeling that accounts for both jacking (or elastic-fracture opening) and shear-slip dilation and demonstrate that injection-induced shear reactivation (or hydroshearing) could have occurred simultaneously with seismic events of magnitudes lower than what can be felt by humans. In fact, simulations considering shear reactivation seem to better match observed fluid recovery after multiple injection cycles. Shear reactivation and shear dilation results in locked-open fractures, especially near the injection well that provides permeability of higher flow recovery. We then investigate the sensitivity of the proposed model by varying some of the critical parameters such as maximum aperture, dilation angle, as well as fracture density. Interestingly, none of the simulated cases resulted in a large event that could have been felt by humans, but did result in a cumulative seismic magnitude of less than 1 for each given stimulation step. In conclusion, these results suggest that a permanent irreversible permeability increase of several orders of magnitude can be obtained by hydroshearing in a “seismically” safe manner.

58 GEOSCIENCES↗
DOE OSTI2017

Development of robust pressure management strategies for geologic CO 2 sequestration

Injecting CO 2 into deep geologic formations for permanent storage can potentially lead to leakage or induced seismicity if the overpressures exceed the fracture gradient or fault re-activation pressure. Strategies that remove reservoir fluids before or after injection may reduce these risks. But, even extensively characterized reservoirs can have substantial gaps in characterization necessary for developing optimal deterministic or even probabilistic pressure management strategies. The characterization data may not provide well-defined bounds or distributions of reservoir parameters or conditions (permeability, fault locations, fracture gradient, fault reactivation pressure). To assess the impact of these uncertainties, we present an approach for evaluating alternative pressure management strategies based on their robustness of meeting project performance criteria. We quantify the robustness of alternative strategies against several criteria: (1) exceeding fault re-activation pressure, (2) failing to inject a desired quantity of CO 2 , (3) exceeding a maximum quantity of extracted brine, and (4) failing to reach a desired extraction efficiency. Our approach allows nuances of competing and complimentary criteria to be quantitatively evaluated in a manner and in a level of detail not possible with optimization approaches. We illustrate the fundamentals of the approach on a simple one-dimensional analytical example using the Thiem equation. Here, we demonstrate the approach using a numerical flow and transport model with uncertain heterogeneous permeabilities using data and site characteristics from the Rock Springs Uplift Carbon Storage Site in southwestern Wyoming.

58 GEOSCIENCES↗
DOE OSTI2022

Geomechanical and Hydrogeological Evaluation of a Shallow Hydraulic Fracture at the Devine Fracture Pilot Site, Medina County, Texas

UT-Austin’s Devine Fracture Pilot Site, 50 miles southwest of San Antonio, Texas, has been targeted for a comprehensive, multidisciplinary development of fracture diagnostic techniques that are cross-validated by ground-truth data acquisition near a recently created, 175-ft-deep, horizontal hydraulic fracture (Ahmadian et al. 2018 Demonstration of proof of concept of electromagnetic geophysical methods for high resolution illumination of induced fracture networks. In Proceedings of the SPE Hydraulic Fracturing Technology Conference and Exhibition, The Woodlands, Texas, USA, 23–25 January 2018. SPE-189858-MS.). To evaluate the fracture diagnostic methods at this site, we conducted injection tests with a predefined volumetric flow-rate profile, resembling a diagnostic fracture injection test on September 2020. Subsequently, we developed hydrogeological and geomechanical models based on flow-rate and bottomhole-pressure measurements. History-matching efforts using a simplified layer-cake hydrogeological model resulted in the field-scale formation permeability of 9.87 × 10 –15 m 2 (10 mD) and Darcy-scale fracture permeability. The analysis of the bottomhole pressure and injection-rate history showed that (1) the newly created horizontal fracture was closed adjacent to the injection well pre-injection and (2) the initial pump-pressure increase at a nominal volumetric injection rate led to near-well fracture reopening, fluid conductivity increase, and abrupt injection-rate increase. To overcome hydrogeological-model limitations of predicting fracture reopening throughout injection, we extended the modeling to a finite-element, poroelastic analysis of horizontal-fracture growth using a cohesive-zone model. Using this fracture-reopening model, we improved the history match of the transient-pressure response during the experiment by adjusting the hydromechanical properties. Furthermore, post-injection pressure transient analyses helped reduce uncertainty in the overburden-stress gradient, and the initial hydraulic-fracturing simulation verified the plausibility of achieving the surveyed propped fracture area.

02 PETROLEUM↗
DOE OSTI2012

Fluid-Bed Testing of GreatPoint Energy's Direct Oxygen Injection Catalytic Gasification Process for Synthetic Natural Gas and Hydrogen Coproduction: Year 6 - Activity 1.14 - Development of a National Center for Hydrogen Technology

The GreatPoint Energy (GPE) concept for producing synthetic natural gas and hydrogen from coal involves the catalytic gasification of coal and carbon. GPE’s technology “refines” coal by employing a novel catalyst to “crack” the carbon bonds and transform the coal into cleanburning methane (natural gas) and hydrogen. The GPE mild “catalytic” gasifier design and operating conditions result in reactor components that are less expensive and produce pipeline-grade methane and relatively high purity hydrogen. The system operates extremely efficiently on very low cost carbon sources such as lignites, subbituminous coals, tar sands, petcoke, and petroleum residual oil. In addition, GPE’s catalytic coal gasification process eliminates troublesome ash removal and slagging problems, reduces maintenance requirements, and increases thermal efficiency, significantly reducing the size of the air separation plant (a system that alone accounts for 20% of the capital cost of most gasification systems) in the catalytic gasification process.

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2025

Phase II Field Demonstration at Lansing Smith Generating Plant, Southport, Florida (Final Report)

The Final Technical Report: Field Test Design and Pressure Management Strategies for Phase II Field Demonstration of Optimal Pressure Control, Plume Management, and Produced Water Strategies presents the culmination of multi-year efforts under the U.S. Department of Energy’s Brine Extraction and Storage Test (BEST) program, led by EPRI in partnership with Gulf Power at the Plant Smith site near Panama City, Florida. The project was designed to evaluate and demonstrate the technical feasibility of managing subsurface pressures and fluid movement associated with large-scale CO₂ injection, using low-salinity water as a proxy fluid. Through a combination of field injection testing, reservoir modeling, and optimization studies, the research team developed and refined active and passive brine extraction strategies aimed at controlling injection-induced pressure buildup, mitigating risks of fault activation, and managing plume migration. The field demonstration incorporated a new injection well (TIW-2), a new monitoring/extraction well (TEMW-A), and an existing well (TIW-1) repurposed for passive pressure relief. Complementary geophysical monitoring was designed to track plume development and evaluate the effectiveness of pressure management strategies. The report details the integrated workflow encompassing wellfield development, regulatory permitting, model calibration, and survey design. It includes a comprehensive electromagnetic (EM) modeling and inversion study used to develop a cost-effective, time-lapse geophysical monitoring plan capable of imaging the evolving low-salinity plume within the highly saline Lower Tuscaloosa formation. Reservoir simulation results guided the design of the 17-month injection program and the timing of active extraction to maintain formation pressures below a hypothetical fault reactivation threshold. Supporting analyses evaluated potential injectivity risks related to clay fines migration and geochemical incompatibility, identifying practical mitigation measures such as salinity and pH control. The final design recommends a series of crosswell EM surveys—conducted before, during, and after injection—as the most effective and economical approach for plume imaging, supplemented by continuous downhole pressure and flow monitoring. Collectively, the study provides a field-ready framework for cost-effective pressure management and monitoring in support of future CO₂ storage projects.

01 COAL, LIGNITE, AND PEAT↗
NASA NTRS1990

U.S. Space Station Freedom waste fluid disposal system with consideration of hydrazine waste gas injection thrusters

The results are reported of a study of various methods for propulsively disposing of waste gases. The options considered include hydrazine waste gas injection, resistojets, and eutectic salt phase change heat beds. An overview is given of the waste gas disposal system and how hydrozine waste gas injector thruster is implemented within it. Thruster performance for various gases are given and comparisons with currently available thruster models are made. The impact of disposal on station propellant requirements and electrical power usage are addressed. Contamination effects, reliability and maintainability assessments, safety issues, and operational scenarios of the waste gas thruster and disposal system are considered.

Winters, Brian A.↗
DOE OSTI2023

Modeling the impact of the fuel injection strategy on the combustion and performance characteristics of a heavy-duty GCI engine

Gasoline compression ignition (GCI) is a promising strategy to achieve high thermal efficiency and low emissions with limited modifications to the conventional diesel engine hardware. It is a partially premixed concept, which derives its superiority from higher volatility and longer ignition delay of gasoline-like fuels combined with higher compression ratio typical of diesel engines. Here, the present study investigates the combustion process in a GCI engine operating with different injection strategies using computational fluid dynamics (CFD). Simulations are carried out on a single cylinder of a multi cylinder heavy-duty compression ignition engine, which operates at a compression ratio of 17:1 and an engine speed of 1038 rev/min. Two different injection strategies viz., late injection (LI), and early pilot injection (EP) are investigated to understand their impact on combustion and performance of the engine. Renormalized group (RNG) k-ε model is used to describe in-cylinder turbulence and KH RT model is used to simulate the fuel spray breakup. The developed CFD methodology is validated against relevant experimental data under a wide range of operating conditions for each injection strategy. The developed CFD methodology was found to capture the engine combustion behavior quite well. Based on the validated CFD model, the differences in the progress of combustion event for the two injection strategies is highlighted. It was found that a larger pilot fuel mass fraction results in a steeper rise in the initial heat release rate which in turn influences the transition to mixing controlled combustion. In line with the experimental data, the study showed that the late pilot injection strategy with three injection pulses, results in higher performance compared to the other conditions.

33 ADVANCED PROPULSION SYSTEMS↗
NASA NTRS1998

Modeling of a Two-Phase Jet Pump with Phase Change, Shocks and Temperature-Dependent Properties

One of the primary motivations behind this work is the attempt to understand the physics of a two-phase jet pump which constitutes part of a flow boiling test facility at NASA-Marshall. The flow boiling apparatus is intended to provide data necessary to design highly efficient two-phase thermal control systems for aerospace applications. The facility will also be capable of testing alternative refrigerants and evaluate their performance using various heat exchangers with enhanced surfaces. The test facility is also intended for use in evaluating single-phase performance of systems currently using CFC refrigerants. Literature dealing with jet pumps is abundant and covers a very wide array of application areas. Example application areas include vacuum pumps which are used in the food industry, power station work, and the chemical industry; ejector systems which have applications in the aircraft industry as cabin ventilators and for purposes of jet thrust augmentation; jet pumps which are used in the oil industry for oil well pumping; and steam-jet ejector refrigeration, to just name a few. Examples of work relevant to this investigation includes those of Fairuzov and Bredikhin (1995). While past researchers have been able to model the two-phase flow jet pump using the one-dimensional assumption with no shock waves and no phase change, there is no research known to the author apart from that of Anand (1992) who was able to account for condensation shocks. Thus, one of the objectives of this work is to model the dynamics of fluid interaction between a two-phase primary fluid and a subcooled liquid secondary fluid which is being injected employing atomizing spray injectors. The model developed accounts for phase transformations due to expansion, compression, and mixing. It also accounts for shock waves developing in the different parts of the jet pump as well as temperature and pressure dependencies of the fluid properties for both the primary two-phase mixture and the secondary subcooled liquid. The research effort on which this document partly reports described a relatively simple model capable of describing the performance of a two-phase flow jet pump. The model is based on the isentropic homogeneous expansion/compression hypothesis and is capable of fully incorporating the effects of shocks in both the mixing chamber and the throat/diffuser parts of the pump. The physical system chosen is identical to that experimentally tested by Fairuzov and Bredikhin (1995) and should therefore be relatively easy to validate.

Sherif, S. A.↗
DOE OSTI2025

Experimental and theoretical evidence of universality in superfluid vortex reconnections

The minimum separation between reconnecting vortices in fluids and superfluids obeys a universal scaling law with respect to time. The prereconnection and the postreconnection prefactors of this scaling law are different, a property related to irreversibility and to energy transfer and dissipation mechanisms. In the present work, we determine the temperature dependence of these prefactors in superfluid helium from experiments and a numeric model which fully accounts for the coupled dynamics of the superfluid vortex lines and the thermal normal fluid component. At all temperatures, we observe a pre- and postreconnection asymmetry similar to that observed in other superfluids and in classical viscous fluids, indicating that vortex reconnections display a universal behavior independent of the small-scale regularizing dynamics. We also numerically show that each vortex reconnection event represents a sudden injection of energy in the normal fluid. Finally we argue that in a turbulent flow, these punctuated energy injections can sustain the normal fluid in a perturbed state, provided that the density of superfluid vortices is large enough.

Reconnections↗
DOE OSTI2019

First Ever Polymer Flood Field Pilot to Enhance the Recovery of Heavy Oils on Alaska’s North Slope – Polymer Injection Performance

Alaska North Slope (ANS) holds an estimated 20-30+ billion barrel heavy oil resources, yet the development pace has been very slow due to high development costs and low oil recovery using conventional waterflood and EOR methods. The objective of this pilot is to perform a field experiment to validate the use of an advanced polymer flooding technology to unlock the vast heavy oil resources on ANS. The advanced polymer flooding technology combines polymer flooding, low salinity water flooding, horizontal wells, and if necessary, injection conformance control treatments into one integrated process to significantly improve oil recovery from heavy oil reservoirs. Two pairs of horizontal injection and production wells have been deployed in an isolated fault block of the Schrader Bluff heavy oil reservoir at the Milne Point Field to conduct a polymer flood pilot. The pilot will acquire scientific knowledge and field performance data to optimize polymer flood design in the Schrader Bluff heavy oil reservoirs on ANS. Polymer injection started on August 28, 2018 using a custom made polymer blending and pumping unit. This paper focuses on the facility setup and polymer injection performance into the horizontal injectors drilled and completed in the Schrader Bluff heavy oil reservoir. Partially hydrolyzed polyacrylamide (HPAM) polymer was selected and the initial target viscosity was set at 45 centipoise. Polymer injection rate was set at 2200 bbl/day for one injector (J-23A) and 1200 bbl/day for the other (J-24A) based on production voidage. Injection pressure was controlled at below fracture pressure to prevent fracturing the reservoir and causing fast breakthroughs. Step rate and pressure falloff tests indicate that short term polymer injectivity is similar to water injectivity, which means that injectivity is mostly controlled by fluid mobility deep in the reservoir rather than that in the vicinity of the injection wellbore. Long term injection data indicate that polymer injectivity has been decreasing in both injectors as the reservoir is filled by polymer. No polymer has been observed in the production stream 7 months after the start of polymer injection compared with a 3-month breakthrough time with waterflood. This indicates that polymer significantly delays breakthrough time which will lead to increased sweep efficiency.

Ning, Samson↗
DOE OSTI2021

NETL Well Integrity Workshop: Identifying Well Integrity Research Needs for Subsurface Energy Infrastructure

Wells are a critical component of subsurface energy infrastructure. Ensuring the integrity of wells as engineered pathways for the safe extraction, injection, and storage of fluids in the subsurface is key to maximizing the effectiveness and resilience of that infrastructure. Addressing well integrity issues in a technically robust manner that promotes environmental sustainability and social equity is also an important focus of the United States (U.S.) Department of Energy’s (DOE) Office of Fossil Energy and Carbon Management. Industry best practices, regulatory standards, modern monitoring data acquisition and control systems, and decades of research and development have dramatically improved the performance and reliability of wells for hydrocarbon extraction and underground injection in the oil and gas industry. Yet, important innovation is required to improve and ensure well integrity performance in engineered geologic systems where operational environments (fluid composition, temperature, pressure, and/or stress conditions) and long functional life cycles of well systems present unique challenges. Additionally, work is needed to understand and manage the long-term integrity and risks associated with legacy wells—especially those located adjacent to and presenting hazards for new subsurface activity.

02 PETROLEUM↗