bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development of Storage Coefficients for Determining the Effective CO2 Storage Resource in Deep Saline Formations
Authors: Gorecki Charles D. , Sorensen James A. , Bremer Jordan M. , Knudsen Damion J. , Smith Steven A. , Steadman Edward N. , Harju John A. 
Published: November 2009

AbstractThe development of broadly applicable storage coefficients for determining CO2 storage resource/capacity estimates has been identified as a critical component for stakeholders to make informed decisions regarding the potential implementation of large-scale CO2 storage. While several evaluations have been conducted to determine CO2 storage resource/capacity estimates, they are the result of different methodologies, and a comparison of the results is often difficult and/or misleading. Thus the development of approaches and methods for developing CO2 storage estimates that can be applied to assessments at a wide range of scales has been identified as crucial to the advancement of broadly applicable and comparable "storage coefficients." At the heart of the matter is the fact that only a fraction of the pore space within any given geological formation will be available or amenable to CO2 storage. The purpose of a storage coefficient is to assign a value to that fraction of a given pore volume in which CO2 can be effectively stored. In order to develop broadly applicable storage coefficients, three methodologies for determining storage resource/capacity in deep saline formations were evaluated: two that can be applied to open systems and one for application in closed systems. In the end, effective storage coefficients were developed for application to deep saline formations at scales ranging from site-specific evaluations to entire formations. Real-world data sets and numerical modeling simulations were used to calculate storage coefficients at the site-specific scale for three lithologies, ten depositional environments, and five structural settings. These results can then be modified and translated into effective storage coefficients that can be applied at the formation scale for the three main lithologies. To develop estimates of effective storage resources for entire basins, estimates for each formation within the basin must be summed. This same methodology can be applied for estimating effective storage resources within state/provincial and national boundaries. In this way, the application of the broadly applicable effective storage coefficients developed by this project can be used to estimate the effective storage resource at levels ranging from site-specific to formation-level, ultimately spanning large sedimentary basins and even entire nations and continents.
Industry Experience With CO2-Enhanced Oil Recovery Technology
Authors: Sweatman R. E. , Parker M. E. , Crookshank S. L. 
Published: November 2009

Abstract
This paper provides substantial and compelling evidence from API (American Petroleum Institute) CCS (Carbon Capture & Storage) Work Group and other studies of CO2 EOR (enhanced oil recovery) and CCS projects showing that CO2 capture, transport, and (GS) geologic-sequestration can be a safe and effective method to reduce GHG (greenhouse gas) emissions and mitigate climate change. The paper summarizes how the oil and gas (O&G) industry has achieved great success in engineering the process to capture, transport, and inject CO2 in EOR projects. This success is seen in over 37 years of safe and environmentally friendly large-scale operations, lessons learned, technical advancements, and millions of tons of CO2 injected. Third party investigations to evaluate this successful record are discussed, including some completed ones that have published statements validating the O&G industry's success. Now that CCS is being widely considered and a few countries have begun to implement commercial-scale CCS projects, technology transfer efforts such as this paper are needed to share the experience of the oil and gas industry and the major contribution it can make as part of the solution for climate change.
Reservoir Modeling and Simulation of the Devonian Gas Shale of Eastern Kentucky for Enhanced Gas Recovery and CO2 Storage
Authors: Schepers Karine C. , Nuttall Brandon , Oudinot Anne Y. , Gonzalez Reinaldo 
Published: November 2009

ABSTRACT
Shale gas and other unconventional gas plays have become an important factor in the United States energy market and are often referred to as statistical plays due to their high heterogeneity. They present real engineering challenges for characterization and exploitation, and their productivity depends upon an inter-related set of reservoir, completion and production characteristics.
The Devonian Ohio shale of eastern Kentucky is the State's most prolific gas producer. The gas shale underlies approximately two-thirds of the state, cropping out around the Bluegrass Region of central Kentucky and having a sub crop beneath the Mississippi Embayment in western Kentucky.
This paper describes the reservoir modeling and history matching of a Devonian Gas Shale Play, eastern Kentucky, its potential for CO2 enhanced gas recovery and storage.
A geologic model of the shale has been compiled from mineralogical, petrographic, core, production, and wireline data. The COMET3 multi-phase, dual porosity simulator is being used to investigate CO2 injection into the shale for enhanced gas recovery. To accomplish this, a subset of wells surrounding the potential injection site has been selected for further study. These eight wells cover approximately 5,300 acres of productive shale. The reservoir was subdivided into the Upper Ohio and Lower Huron members. To capture geological heterogeneity, gas production rates for these wells served as a proxy to characterize fracture permeability using geostatistical methods. Well production was history matched applying an automated process. Finally, several CO2 injection scenarios spanning huff-n-puff to continuous injection were reviewed to evaluate the enhanced gas recovery potential and assess the CO2 storage capacity of these shale reservoirs.
Carbon Dioxide Enhanced Coalbed Methane and Storage: Is There Promise?
Authors: Koperna George J. , Riestenberg David 
Published: November 2009

ABSTRACT
Since the early 1980s, engineers and geologists have been unlocking the secrets of coal seam gas reservoirs. With time and technology advances, such as multi-lateral horizontal drilling, these reservoirs have contributed mightily to the Nation's gas supply. Many of these prolific reservoirs are maturing and field operators now look to improve incremental recoveries from these natural gas sources. One such method is through the use of carbon dioxide enhanced coalbed methane (CO2-ECBM).
CO2-ECBM is a process by which the gas is injected into a coal seam, it is preferentially adsorbed onto the coal, allowing incremental methane to desorb and be produced. This very unique characteristic of a coal allows it to serve double-duty as both a storage reservoir and the seal. As such, geologic sequestration of carbon dioxide in deep, unmineable coal seams may hold tremendous promise for long-term, secure storage of the greenhouse gases as well as providing incremental methane recovery.
However, with only a handful of CO2 injection pilots having been conducted, it seems more questions are being asked regarding the viability of the process than being answered. This paper will focus on the lessons learned from several large-scale and small-scale tests, framing these results against capacity and injectivity estimation and long-term suitability for various coal types/ranks.
Optimization of In-Situ Combustion Processes: Reduction of CO2 Emissions—A Preliminary Study
Authors: Liu Z. , Jessen K. , Tsotsis T. T. 
Published: November 2009

AbstractThe in-situ combustion (ISC) process is an enhanced oil recovery (EOR) method that utilizes fuel in place to upgrade and displace the hydrocarbons in heavy oil reservoirs. In ISC processes, air is injected into a heated section of the reservoir. Upon reaching a threshold temperature, oxygen from the injected air reacts with the oil in place to generate heat, a lighter oil fraction, steam and other reaction products such as CO2. This process drives the upgraded oil towards the production wells, but at the same time produces significant amounts of CO2.In this research project we investigate the potential of a novel hybrid ISC and CO2 recovery and re-injection process, where we attempt to maintain the advantages of the ISC process while at the same time reducing the emissions of CO2. The goal of the study is to test the hypothesis that, as long as the re-injection of produced CO2 does not extinguish the combustion front, the overall oil recovery should not be greatly diminished.Numerical investigations of a pseudo 2-D model of this hybrid ISC process, using the CMG STARS simulator, show that recycling CO2 back into the reservoir, to replace some of the air typically injected, can be beneficial for reducing the CO2 production but also for increasing the oil production. We observe that the CO2 recycled into the system dissolves readily into the oil phase resulting in lower viscosity oil and in improved production rates. The results of our numerical simulations provide justification for the proposed combined ISC/CO2-flood process. In this process the ISC provides on site the gas needed for the CO2 flood, and a substantial fraction of the total CO2 produced can be permanently sequestered in the subsurface.
Inexpensive Assessment of Plume Migration During CO2 Sequestration
Authors: Mantilla Cesar A. , Srinivasan Sanjay , Cross Edward A. , Bryant Steven L. 
Published: November 2009

AbstractMonitoring of CO2 plumes is required to verify long-term sequestration of injected CO2, detect possible leaks from the storage zone, and infer deviations in plume path due to unforeseen large-scale geologic anomalies like flow barriers or high permeability streaks. Although several alternatives are available for monitoring plume path deviations during injection, the cost of monitoring still is a paramount concern for operators. The conjecture of this work is that dynamic data measured at injection wells are informative of the presence of heterogeneities large enough to affect plume paths. Hence geologic models updated using injection data can be used to predict better the trajectory of CO2 plumes and to design operational schemes that will ensure long term containment of the injected CO2. To test this conjecture, we have adapated a probabilistic history matching software (Pro-HMS) originally developed for oil field applications. The software assimilates injection data commonly monitored at active and inactive wells into models for the subsurface aquifer/reservoir. The algorithm yields an ensemble of realizations geologically consistent with the initial model such that the uncertainity in CO2 plume location can be easily assessed. We illustrate the approach with synthetic examples (a deep, heterogeneous aquifer with a long streak of large or small permeability) for which the reference bottomhole pressure and rate responses from injection and inactive wells were obtained from simulation. The updated models obtained after the history matching process detected the presence of the streak, and the subsequent estimation of CO2 plume location was much more accurate. Pressure data recorded at inactive wells were essential for detecting the streak. Monitoring such wells is thus expected to provide valuable information about geologic heterogeneities. The results confirm that injection rate and pressure data provide an inexpensive option for monitoring CO2 plumes.
Utilizing Sustained Casing Pressure Analog to Provide Parameters to Study CO2 Leakage Rates Along a Wellbore
Authors: Huerta Nicolas J. , Checkai Dean A. , Bryant Steven L. 
Published: November 2009

Abstract
Predicting the flux of CO2 along a leaking wellbore requires a model of fluid properties and of transport along the leakage pathway. This model should accurately represent the geometry of any discrete leakage pathway, because this geometry strongly affects the coupling between geochemical reactions and geomechanical response. Validating a transport model in advance of large-scale sequestration is difficult because instances of CO2 plumes reaching abandoned wells are presently rare. However, natural gas leakage events along wellbores can provide insights into conductive pathways analogous to those anticipated for CO2 sequestration. We apply a simple transport model to field measurements of sustained casing pressure (SCP) vs. time. We treat as unknowns the effective permeability of the leakage path and the depth at which leakage into the wellbore is occurring. These parameters are useful for forecasting likely leakage rates in sequestration sites located near oil and gas fields and for choosing candidate sites based on past exploration history. For several cases of SCP, conductive pathways (e.g. open fracture, gas channel, micro annulus) must exist to explain the large inferred values of effective permeability. Applied to a large enough set of SCP wells, this approach can provide a probabilistic distribution of leakage rates given regional and well parameters. For CO2 sequestration purposes this provides a tool to assess the risk associated with carbon dioxide migration along leaky wells, which is necessary for site selection, permitting, and properly crediting sequestration operations.
Effect of Relative Permeability on Pressure-Induced Risk During CO2 Injection in Aquifers
Authors: Oruganti YagnaDeepika , Bryant Steven L. 
Published: November 2009

AbstractWhen CO2 is injected in deep saline aquifers on the scale of gigatonnes, pressure buildup in the aquifer during injection will be a critical issue. Because fracturing, fault activation and leakage of brine along pathways such as abandoned wells require a threshold pressure (Nicot et al., 2009), operators and regulators will be concerned with a critical contour of overpressure (CoP). The extent of this contour varies depending on the target aquifer properties (porosity, permeability etc.) and the geology (presence of faults, abandoned wells etc.). The extent also depends on relative permeability, and from the three-region injection model (Burton et al., 2008), we derive analytical expressions for a specific contour of overpressure at any given time. The risk of pressure-induced leakage from the aquifer can therefore be understood in terms of phase mobilities and speeds of saturation fronts. This provides a quick tool for estimating pressure profiles.Seven different relative permeability curves (Bennion and Bachu, 2005) and their effect on the CoPs in each of the three regions have been studied. The relative permeability curve which gives the maximum two-phase region mobility (MBL) gives the lowest pressure buildup (specific CoP is closest to the injector). Thus characterizing relative permeability will be an important consideration for the practical implementation of CO2 storage projects. For smaller values of critical CoP which lie in the brine region, the location of the critical CoP, and hence the risk due to pressure buildup, are time-invariant and independent of relative permeability. This result significantly reduces the uncertainty in predicting these contours of overpressure.
Emerging Technical Challenges of 5-Million-Ton/yr Injections
Authors: Friedmann S. J. 
Published: November 2009

AbstractTo achieve substantial national and global greenhouse gas abatement, carbon capture and sequestration (CCS) must be deployed at large scale in many locations. Individual large projects (5 million tons/y) will inject volumes on the order of 80,000-130,000 bbls/day equivalent continuously for 30 years or more. This requires explicit consideration of and management of growing reservoir pressure unlike CO2-EOR. Accurate reservoir descriptions of fault networks and the in-situ stress tensor are critical to successful management. Small uncertainties in the structural geometry or stress tensor azimuth can potentially produce very different results for fault activation and risk, which in turn affect the potential for induced seismicity in an active injection.Although smaller than the injection pressure wave, the large injection footprint will make monitoring and verification challenging. Key challenges involve reduction of cost and improvement of accuracy using non-seismic methods. Careful integration of monitoring results and understanding of uncertainties are critical to avoid subsurface trespass and far-field migration. Demonstrations of InSAR, microseismic, and electrical survey methods have improved understanding of these technologies and may lead to improved monitoring suites. Seafloor monitoring has received little attention, but will be central to shelf deployments. Direct monitoring of groundwater systems may also be required by regulations, but have received little attention.In order to avoid excessive local build-up of pressure and to maintain a small injection footprint, active management of the reservoir may be needed. Co-production and treatment of reservoir brines could provide a cost-effective means of reducing both operational risk and project costs. More aggressive reservoir management (interception wells and induced flow fields) may be needed to avoid trespass onto adjacent properties. Such measures are standard practice in many oilfield operations, suggesting that the incremental cost and risk posed by active management is likely to be small.
Carbon Cyber Infrastructure CCI: Identifying and Characterizing CO2 Sources and Opportunities for Carbon Capture and Storage
Authors: Carr T. R. 
Published: November 2009

Abstract
CO2 sources vary widely in emission characteristics including concentration, pressure, contaminants and intermittency. In addition, the ability to initiate carbon capture and storage (CCS) of particular sources are influenced by geographic location, land use, regulatory environment, and the proximity to potential geologic storage sites that can provide safe, secure storage over long periods of time (such as oil and gas fields, deep coal seams and saline aquifers). Differences in these multiple characteristics can dramatically impact the cost of capture and geologic storage. Large stationary anthropogenic sources of CO2 that provide the best opportunities for CCS include cement kilns, ethanol plants, natural gas plants, refineries, ammonia manufacturing plants and power generation (coal and natural gas). The United States Department of Energy's Regional Carbon Sequestration Partnerships (RCSPs) have generated data that provides the foundation of a carbon cyber-infrastructure (CCI). This geospatial data is available online and can be used by the private and public sectors to improve the implementation of CCS for a single CO2 emission source or group of sources. An integrated learning approach using large amounts of geospatial data is proposed to evaluate CO2 sources in relation to an integrated system of capture, transport and geologic storage will be discussed. Use of geospatial data for source and geologic storage sites in southeast Kansas provides an example of integration within a changing regulatory and economic environment of multiple industrial sources of CO2 emissions of widely varying characteristics with multiple stacked geologic storage opportunities.
CO2 Injection Performance in the Fruitland Coal Fairway, San Juan Basin: Results of a Field Pilot
Authors: Oudinot Anne Y. , Koperna George J. , Philip Zeno G. , Liu Ning , Heath Jason E. , Wells Arthur , Young Genevieve B. , Wilson Tom 
Published: November 2009

ABSTRACT
As part of the Southwest Regional Partnership for Carbon Sequestration (SWP), the Pump Canyon CO2-ECBM/sequestration demonstration in New Mexico has for objectives to prove the effectiveness of CO2 sequestration in deep, unmineable coal seams via a small-scale geologic sequestration demonstration.
At the demonstration site, a new CO2 injection well was drilled mid-2008 into the late-Cretaceous Fruitland coals within an existing pattern of coalbed methane production wells mainly operated by ConocoPhillips. CO2 injection in the three coal seams was initiated late July 2008 and stopped in August 2009. A variety of monitoring, verification and accounting (MVA) methods are being employed to track the movement of the CO2 to prevent any leakage. Some of the MVA methods include continuous measurement of injection volumes, pressures and temperatures within the injection well, coalbed methane production rates, pressures and compositions at the offset producer wells via CO2 sensors, tracers in the injected CO2, time-lapse vertical seismic profiling and surface Tiltmeter arrays amongst others. A detailed study of the overlying Kirtland shale is currently being conducted to investigate the integrity of this caprock. In addition, a detailed geologic characterization and reservoir modeling has been implemented in order to reproduce and understand the behavior of the reservoir.
As of now, the injection has ended and no CO2 breakthrough has occurred, classifying the small scale demonstration pilot as a success. This paper describes the project in details from the well construction to the different monitoring techniques used to prevent CO2 leakage as well as the results of the simulation model.
Results From Continuous Downhole Monitoring PDG at a Field-Scale CO2 Demonstration Project, Cranfield, MS
Authors: Meckel T. A. , Hovorka S. D. 
Published: November 2009

AbstractElevated formation fluid pressure resulting from large-volume carbon dioxide (CO2) injection for sequestration is a key factor affecting storage integrity (seal and well performance) and ultimate capacity. Monitoring pressure dynamics (buildup and falloff) is a fundamental and pragmatic reservoir surveillance technique for monitoring sequestration performance. The Southeast Regional Carbon Sequestration Partnership (SECARB) field project conducted by the Gulf Coast Carbon Center with support from the National Energy Technology Laboratory (NETL) and the U.S. Department of Energy (DOE) and managed by the Southern States Energy Board (SSEB) at Denbury Resources' Cranfield Field in southwest Mississippi provides a unique opportunity to monitor large-scale (&gt;106 tons) CO2 injection on the flank of an anticline at 3 km depth. Prior to large-scale CO2 injection, the reservoir has been shut-in for decades and was near hydrostatic pressures when injection commenced. Thus, the initial pressure buildup prior to production is similar to what would be expected for many brine sequestration projects. The evolving CO2 distribution and pressure perturbation has been monitored continuously for over one year. This paper presents the monitoring well design, including a novel dual completion for above-zone monitoring, and presents real-time pressure data recorded in the injection interval. Correlation of changes in CO2 injection rates from eleven injection wells throughout the field with observed pressure response at the observation well are used to demonstrate the sensitivity of this monitoring technique for quantifying CO2 fluxes within the reservoir, and to illustrate the sealing nature of a reservoir-scale fault in the field during CO2 injection. At Cranfield, subsurface pressure monitoring is capable of detecting CO2 fluxes (injection rate changes) corresponding to as little as hundreds of tons per day at distances up to 1 km. The reservoir appears to have a predictable response of the rate of pressure change at the observation well for injection perturbations of variable rates and distances, suggesting that rates of observed pressure change that are uncorrelated with injection changes could be used to detect, quantify, and locate unanticipated migration of CO2 out of the injection zone.