Greenhouse Issues (March 2005) Number 77
By Susan Hovorka, Bureau of Economic Geology, University of Texas at Austin
From October 4 to 14, 2004 the Frio Brine Pilot team injected 1600 tons of CO2 1500m below surface into a high permeability brine-bearing sandstone of the Frio Formation beneath the Gulf Coast of Texas, USA (See Greenhouse Issues, number 72). Six months into the post-injection phase of the study, we have made substantive progress toward accomplishing the four major project objectives:
(1) Demonstrate to the public and other stakeholders that CO2 can be injected into a brine formation without adverse health, safety, or environmental effects,
(2) measure subsurface distribution of injected CO2 using diverse monitoring technologies,
(3) test the validity of conceptual, hydrologic, and geochemical models, and
(4) develop experience necessary for development of the next generation of larger-scale CO2 injection experiments.
The Frio Brine Pilot experiment is funded by the Department of Energy (DOE) National Energy Technology Laboratory (NETL) and led by the Bureau of Economic Geology (BEG) at the Jackson School of Geosciences, The University of Texas at Austin with major collaboration from GEO-SEQ a national lab consortium led by Lawrence Berkeley National Lab (LBNL).
The first objective was accomplished through outreach, which included numerous site visits by researchers, local citizens, and environmental groups, major media interviews, an online log of research activities (www.gulfcoastcarbon.org), a technical e-newsletter, and an informal non-technical “neighbor newsletter”.
These activities continue as results of analysis are obtained. Public and environmental concerns were moderate, practical, and proportional to minimal risks taken by the project and included issues such as traffic and potential of risks to water resources. Press coverage was balanced and positive toward research goals. Safe site operation was managed by Sandia Technologies LLC, Praxair Inc., and Trimeric Corporation.
The second objective, measurement and monitoring of the subsurface CO2 plume, was accomplished using a diverse suite of technologies in both the injection zone and in the shallow near-surface environment. Figure 1 gives an overview of the monitoring strategies applied, each with a pre-injection and one or more post injection measurements. Wireline logging, pressure and temperature measurement, and geochemical sampling were also contucted during injection. In-zone objectives were to measure changes in CO2 saturation through time, in cross section, and areally, and to document accompanying changes in pressure, temperature, and brine chemistry during and in the months following injection. The in-zone measurement strategy was designed to test the effectiveness of a selected suite of monitoring tools in measuring these parameters. The near-surface monitoring program measured soil gas fluxes and concentrations, introduced tracers, and fluid chemistry in the vadose zone and shallow aquifer in an attempt to detect any leaks upward out of the injection zone, especially those rapid enough to cause releases in a short time frame such as behind well casings.
Tools used for in-zone monitoring included five repetitions of logging with the Schlumberger reservoir saturation tool (RST), which under conditions of a maximum 35% porosity and 125,000 ppm salinity was successful in obtaining high-resolution saturation measurements across the injection interval. During the injection, CO2 saturation increased toward a maximum of 60% of pore space filled with CO2 in both the injection and observation well. Saturation declined in the post injection period; a final RST on Feb 23 will quantify the CO2 permanently trapped in-zone by two-phase (residual) trapping. The log analysis team includes researchers from BEG and Schlumberger–Doll Labs.
An innovative geochemical sampling tool, developed and operated by Barry Freifeld and Rob Trautz (LBNL) to support in-zone fluid chemistry sampling, is the U-tube. The U-Tube is composed of a double length of 9.5 mm O.D. x 1.2 mm wall thickness stainless steel tubing, with a check valve open to the reservoir at 1500m. Formation fluid that was collected in the U-Tube was driven at reservoir pressure into evacuated sample cylinders at the surface by high pressure ultra-pure nitrogen. Samples were collected hourly to facilitate accurate delineation of CO2 breakthrough and recover uncontaminated and representative samples of two-phase fluids. Initial CO2 breakthrough to the observation well 30m updip of the injection well occurred 51 hours after initiation of injection. Steady increases in the ratio of CO2 to brine produced recorded increasing saturation and plume thickness as the front of the plume expanded past the observation well. Free gas in the sample and gases coming out of solution were pumped from the top of the gas separator through a quadrapole mass spectrometer analyzer and a landfill gas analyzer to measure changes in gas composition in the field. During the 12 hours after breakthough, CO2 replaced brine as the fluid in the perforated zone of the wellbore and became the only fluid produced. At the same time that CO2 was detected at the observation well, the pH of produced, partly degassed brine dropped from 6.7 to 5.7, alkalinity increase from 100 to 3,000 mg/L bicarbonate as a result of mineral dissolution, and iron increased from 20 mg/L to 2000 mg/L, changing the fluid from clear to coffee color (Yousif Kharaka [USGS] and Seay Nance[BEG], unpublished results). Downhole sampling with a Kuster sampler in March, 2005 will allow us to assess geochemical changes as CO2 saturated brine reacts with the mineralogially complex sandstone matrix for 6 months.
Stainless lines of the U-Tube conveyed fluids hourly from the Frio Formation in the subsurface at 1500m to the wellhead and then to the portable lab where 102L samples were weighed, subsamples extracted at downhole and surface pressure for geochemical analysis, and gas composition measured (Figure 2).
The suite of tracers injected with the CO2 include perfluorocarbon tracers (PFTs), the noble gases, krypton, neon, and xenon, along with sulfur hexafluoride. Tracer injection and analysis was performed by researchers from Oak Ridge National Laboratory, Lawrence Berkeley National Laboratory, and Alberta Research Council. The tracer arrival times and elution curves allow assessment of the percentage of CO2 that is trapped by dissolution into the brine, based on partitioning of the tracers from CO2 into the brine, along with facilitating estimation of evolution of CO2 saturation as injection proceeded.
Pressure and temperature histories during injection provided comparative effective permeability under brine and evolving CO2+brine conditions. Downhole installation of pressure and temperature gauges proved to be critical for interpretation of complex (gas/supercritical CO2/brine) phases in the wellbore. LBNL and Sandia Technologies designed the hydrologic test program.
Geophysical measurements of plume evolution include cross-well seismic, an azimuthally dependent vertical seismic profile, and cased-hole cross-well electromagnetic (EM) surveys. These surveys were made pre and post injection and analyses to date show that tools were successful in measuring CO2. The entire test is a proxy for a leak that might escape from a large injection; additional analysis is underway to determine success of geophysical methods in leak detection under these conditions. The geophysical team includes LBNL, Paulsson Geophysical, Schlumberger-EMI Technology Center, and Australian CO2CRC/CSIRO.
Near-surface monitoring includes soil-gas CO2 flux and concentration measurements, aquifer chemistry monitoring, and tracer detection of PFT with sorbants in the soil and aquifer. Pre-injection baseline surveys for CO2 flux and concentration-depth profiles over a wide area and near existing wells were done in 2004. Minor variability in aquifer pH and gas concentrations have been measured but analyses of tracers needed to determine whether change is related to leakage are still underway. The near-surface research team includes BEG, NETL SEQURE, Colorado School of Mines, and LBNL.
The third objective is to test the validity of conceptual hydrologic and geochemical models. Reservoir characterization by BEG to provide inputs to the simulations used existing and newly collected wireline logs, existing 3D seismic survey, baseline geochemical sampling by USGS and Schlumberger, and core analyses by Core Labs. A drawdown interference test and a dipole tracer test conducted by LBNL researchers provided interwell permeability estimates (2.3 Darcys) confirmed that the core-based measurements of the porosity-thickness product (6.2m thickness with 0.35 porosity) were appropriate at site scale for the Frio C sand targeted for CO2 injection.
Two groups of modelers, LBNL using TOUGH2 and The University of Texas Petroleum Engineering Department using CGM, input geologic and hydrological information along with assumptions concerning CO2 /brine multiphase behavior to predict the evolution of the injected CO2 through time. The observed CO2 breakthough occurred somewhat faster and in a narrower zone than the predicted arrival. Further refinement of the relative permeability and capillary pressure-saturation properties allow the model to better match the acquired data. Geochemical modeling by Lawrence Livermore National Lab predicted elements of brine composition evolution.
As the Frio experiment analysis and modeling continue, it supports the fourth objective, development of the next generation of larger-scale CO2 injection experiments. Confidence in the correctness of conceptual and numerical models and the effectiveness of monitoring tools tested will encourage the next pilots to investigate more complex factors such as stratigraphic and structural heterogeneity and upscaling. The Frio Pilot results provide a model for the US Regional Partnerships Program participants as well as international collaborators to design test programs in various settings.
The pilot site is representative of a broad area that is an ultimate target for large-volume storage because it is part of a thick, regionally extensive sandstone trend that underlies a concentration of industrial sources and power plants along the Gulf Coast of the United States. The Gulf Coast Carbon Center, in cooperation with the Southeast Regional Carbon Sequestration Partnership, is proposing one of these ambitious pilots in the Frio or related sandstone to conduct a multi-month injection to "prove- up" the concept of stacked storage in an oil reservoir in decline and the underlying brine-bearing sandstones.
By Robert Meyer & Franz May
Within the CO2STORE project, knowledge gained from the former SACS project (Sleipner Field) is currently applied to four virtual case studies in Norway, Denmark, Great Britain and Germany (see Table below) (Greenhouse Issues, number 68).
Overview of the four case studies plus the Sleipner Field research activities integrated into the CO2STORE project
The identification of potential storage sites within the Northeast German Basin has led to the selection of structure Schweinrich for further detailed analysis as the German case study for the project.
Task and Activities
One important task, completed in the CO2STORE project, was to discover, evaluate and characterise potential storage sites which provide a storage volume of more than 400 Mtons CO2 according to the total CO2 production over 40 years by a typical large lignite fired power plant such as, for example, the Schwarze Pumpe power plant operated by Vattenfall Europe. Along the way, the development and implementation of a powerful, site-specific risk assessment concept is under development.
In an initial survey several suitable storage sites (saline aquifers) were identified from a large number of anticlinal structures within Mesozoic formations in the Northeast German basin (see Figure 3). With respect to several geological selection criteria (depth, thickness, porosity, permeability, expected storage volume, presence of a structural closure combined with a sealing cap rock) a ranking of the structures was conducted. Further, environmental selection criteria were included in the selection procedure, such as existing nature protected areas, areas used by the military and areas with valuable nature resources. Accordingly, the Structure Schweinrich is the best candidate for further investigations.
The selected storage site beneath the small village Schweinrich is a passive anticlinal structure with reservoir formations within the Lower Jurassic (Lias) and the Uppermost Triassic (Rhät-Keuper, see Figure 4). The reservoir (saline aquifers) is about 150 metres thick and consists of several layers of fine-grained, highly porous sandstones overlain by thick Jurassic clayey formations.
The storage site covers about 100 km2 and provides a calculated total storage capacity of more than 1000 Mtons CO2. The CO2 could be transported via pipelines from the Schwarze Pumpe power plant to the storage site Schweinrich (about 200 km distance, see Figure 3). However, there are other locations in the region that may be considered in the case a new CO2-free power plant were to be built.
Ongoing and Future Research Activities
In addition to the detailed geological characterisation (BGR) further research activities include risk assessment (TNO-NITG, Vattenfall Utveckling AB and BGR), predictive geochemical modeling (BRGM) and reservoir-geological 3D modelling combined with flow simulations (TNO-NITG and BGR) to predict the long-term fate of the CO2.
By Etienne Brosse, IFP
PICOREF is a R&D programme dedicated to the storage of CO2 in permeable reservoirs. It is supported by the French Ministry of Industry, in the framework of RTPG Funds (Réseau de Technologies PétroliPres et GaziPres: “Network of technologies for petroleum and gas industry”), and by a consortium of French companies, research institutions and academic laboratories. The project is headed by IFP (Institut Français du Pétrole: French institute of petroleum).
The status of France is rather unique concerning its energy management. A major part of the electricity is of nuclear origin (76.6 to 78.1 % in the years 2000s), so that CO2 emissions per inhabitant averages ca. 1.75 tC.yr-1 (ca. 3 tC.yr-1 for OECD countries). France’s CO2 reduction commitment within the Kyoto protocol is thus quantitatively modest, and the effort may be limited to the stabilization of emissions at the present-day level. Nevertheless, a true concern of French public authorities with respect to climate change has progressively emerged. The need to decrease by 4 or 5 times by the year 2050 the level of national greenhouse gases (GHG) emissions, is now clearly outlined at the government level as an overall objective, which includes worldwide environmental awareness, and national industrial competitivity as well. Accordingly, technological challenges to reduce GHG emissions, including CO2 capture and storage (CCS), already are, and will be considered as high-priority national R&D issues.
Historically, the French petroleum & gas industry has always been a strategic stronghold. It is directly concerned by CCS, not only in relation with its own emissions because of its activity in the domain of hydrocarbon extraction and refining, but also as an industrial perspective which provides opportunities of development in novel technological areas. As a matter of fact, the petroleum industry already has acquired a vast expertise directly applicable to CO2 storage management.
PICOREF (PIégeage du CO2 dans les Réservoirs géologiques, En France: “CO2 trapping in geological reservoirs, in France”) has two main objectives:
Note that capture of CO2 in the PICOREF programme is not mentioned. These topics already are thoroughly addressed in the framework of other European projects (e.g., CASTOR: see Greenhouse Issues number 72).
The first objectives of PICOREF (or Work Package WP1: Site characterization;) are to evaluate two types of potential CO2 sites: depleted hydrocarbon fields and deep saline aquifers. A quick screening of the French hydrocarbon fields in terms of CO2 storage capacity and capability was achieved in a prior RTPG project (2004). It highlighted few non-economical minor oil fields as valid potential sites for a pilot project, with appropriate features (burial depth, temperature, pressure, fluids, reservoir lithology) as found in bigger oil fields in the same area. Should a pilot study indeed proceed in PICOREF, the pilot operation would study some aspects such as CO2 breakthrough during an EOR episode, well-bore verification, testing of a well-to-well monitoring technique, at a smaller scale and undoubtedly at lower security risk and cost. Another option would be to use a limited compartment of a larger producing field.
The BRGM (Bureau de Recherches Géologiques et MiniPres: French geological survey) has successfully made a preliminary inventory of French aquifers, in the framework of the European GETSCO project. The Paris Basin appears as a front runner when considering both the amount of CO2 produced and the availability of deep saline aquifers (see Figure 5). Two aquifers appear as potential candidates for CO2 storage, the Dogger Formation and the Keuper Formation (s.l.), either one consisting of a series of large aquifer units. It was thus decided, for practical reasons, to focus the study on the part of the Paris Basin where the subsurface is best known. First of all, because petroleum exploration has been active in this basin for more than thirty years and secondly, because the subsurface has been also investigated for geothermal resources. Lastly, industrial sources of pure CO2 are present in the region, which could reduce the capture cost during the pilot operation.
The second objective of PICOREF (WP2: Methodology) is to define a methodological approach that can be applied to the preliminary study of a geological site foreseen as a candidate for CO2 storage, and to test its use on a real scale. The approach encompasses a series of needs, tools, or questions, that are addressed:
The project WP2 is articulated into three areas of study: (1) capacity of a reservoir to receive a given CO2 stream during a given period of time; (2) CO2 transfers in the reservoir and out of the reservoir, with confining properties of the site; (3) short- and long-term monitoring. On the first two themes, PICOR, a preceding RTPG programme (2002-2004), provided a series of reviews and innovative results on:
Some results of PICOR have been accepted for publication in Oil and Gas Science & Technology Journal (2005, Issue N.1-2: Gas-Water-Rock Interactions Induced by Reservoir Exploitation, CO2 Sequestration, and other Geological Storage, in press)1 and in Chemical Geology (2005, Special Issue: Geochemical Aspects of CO2 Sequestering, in press)2.
PICOREF, aside from its preoccupation of adopting appropriate methodologies, tools and site selection for an up-coming CO2 storage pilot, has also the scope of pursuing the effort of the project PICOR, which dealt with theoretical physical and chemical aspects of CO2 geological storage. New experimental results and kinetic models, notably on the rate of precipitation of CO2-trapping minerals, calibration and validation of phenomenological models, testing of numerical codes at the site scale, and finally integrating all this experience in a methodological work-flow chart, is within the scope of work. In addition, an increasing activity will be devoted to caprock integrity and monitoring techniques.
The PICOREF’s consortiumship is composed of large-size companies (Air Liquide, Alstom, CGG, Gaz de France, La SNET, Total), of middle- and small-size companies (CFG-Services specialized in geothermy, Correx specialized in corrosion, Geostock specialized in underground storage, Magnitude specialized in seismic monitoring), of research institutions (BRGM, IFP, INERIS) and of academic laboratories (SPIN-GENERIC at the School of Mines in Saint-Etienne, ICMCB-CNRS in Bordeaux, LMTG-CNRS at Toulouse University, LGIT-CNRS at Grenoble University, TPHY-ISTEEM at Montpellier University, LAEGO at INPL in Nancy). Most of the partners have valuable experience on CCS, from past and ongoing participation to other R&D projects.
The time schedule of PICOREF is two years, 2005 and 2006. The budget is proposed and evaluated each year, with a detailed work programme. The approved budget in 2005 approximates 3.75 M!.
1 Papers by Brosse et al.: Modelling fluid-rock interaction induced by the percolation of CO2-enriched solutions in core samples; Kervévan et al.: Improvement of the calculation accuracy of acid gas solubility in deep reservoir brines; Noiriel et al.: Hydraulic properties and micro-geometry evolution accompanying limestone dissolution by acidic water; Renard et al.: Numerical modeling of the effect of carbon dioxide sequestration on the rate of pressure solution creep in limestone.
2 Papers by Golubev et al.: Experimental determination of the effects of CO2 on the dissolution kinetics of Mg and Ca silicates; Pokrovsky et al.: Dissolution kinetics of calcite, dolomite and magnesite to 50 atm CO2.
By Neeraj Gupta and Jim Dooley, Battelle
During the last two years, Battelle has been leading the Ohio River Valley CO2 Storage Project with financial and technical support from the U.S. Department of Energy, American Electric Power (AEP), BP, the Ohio Coal Development Office of the Ohio Air Quality Development Authority, the Pacific Northwest National Laboratory, Schlumberger, and several other organizations. The Ohio River Valley CO2 Storage Project (also known as the "Mountaineer Project" as it is located on the grounds of AEP's 1300-MW coal-fired Mountaineer power plant) has recently completed its site characterization phase. This article provides a brief update on the project and summarizes some of the findings from this first ever attempt to evaluate CO2 storage potential at an operational power plant.
Geographic, Economic and Geologic Setting
The Ohio River Valley region in Midwestern United States is home to both a large number of point sources of CO2, including a significant number of large coal-fired power plants, and a variety of potential options for geologic storage of carbon dioxide. Well over three-quarters of the electricity generated in this region is from coal, and the region sits above one of the United States' largest domestic reserves of coal. If carbon dioxide capture and storage technologies (CCS) are going to deploy in the United States, the Ohio River Valley region would appear to be a likely area of intensive use of CCS technologies.
Geologically the site lies within the Appalachian Basin, where up to 3 km of sedimentary rocks overlie Precambrian crystalline basement complex. Thick sedimentary sequences consisting of saline reservoirs, deep-unminable coal seams, thick sections of organic-rich shales, and oil and gas reservoirs are found throughout the region and represent candidates for CO2 storage. Overlaying and often interspersed with these candidate CO2 storage reservoirs are many thick containment intervals with very low permeability shale, limestone, or dolomite layers. Despite the presence of thick sedimentary sequence, the deeper candidate formations are not geologically well characterized, especially in areas with high concentration of large point sources. This is particularly true of the large regional saline reservoirs such as the Mt. Simon Sandstone or other sandstone layers in the Cambrian sequence. Hence, a primary objective of the current phase of the project was to characterize these candidate reservoirs and start developing a regional geologic framework.
The primary field activities of the project have been drilling and testing an approximately 2800m deep exploratory well and conducting a 2D seismic survey covering approximately 16km along two lines. The seismic data has been used to evaluate the geologic structure on both sides of the Ohio River and to model feasibility of monitoring CO2 using 4D seismic surveys.
The test well program included collection of full-core and side-wall core samples from several intervals, an extensive suite of advanced wireline logs to determine formation properties, and brine collection and analysis. Reservoir testing was conducted during April 2004 to evaluate injectivity in the candidate reservoirs and to determine integrity of caprock layers through fracture testing. The core samples have been extensively tested and are now part of the Ohio Geological Survey's core repository and available for further research. While the shallow formations were logged, most of the detailed testing focused on the lower 900 meters of the borehole. Data analysis has been largely conducted by scientists from Battelle and Schlumberger-Doll Research center and by regional geology experts. In addition, Stanford University has conducted an assessment of geomechanical aspects, and Kentucky Geological Survey has tested organic shale samples for CO2 sorption potential in shale. The field and laboratory data is being used to build reservoir models, develop designs for injection and monitoring systems, and support risk assessment.
The field activities have been supported by wide ranging stakeholder outreach efforts at local, regional, and national levels that have also played a significant part in building awareness of the carbon capture and storage technologies. The outreach activity has ensured that the key stakeholders are well informed of the project objectives at every stage of this phased research program.
During the last year, an extensive effort has been undertaken to evaluate the data collected from the well, the seismic survey and by other means. Some analyses are still being completed. Preliminary conclusions based upon the analysis performed to date include:
The Ohio River Valley CO2 Storage Project is being conducted in a phased manner with the ultimate objectives of demonstrating both the technical aspects of CO2 storage and the testing logistical, regulatory, and outreach issues related to conducting such a project at a large point source under realistic constraints. With the site characterization phase nearing completion, the activities in the near future will be focused on moving the project towards a potential injection phase. These activities include an assessment of the CO2 source options (a slip-stream capture system or transported CO2); development of the injection and monitoring system design; preparation of regulatory permits; and continued stakeholder outreach. At the same time, an expanded effort to continue development of regional geologic sequestration framework will continue. The final decision to proceed to an actual CO2 injection and monitoring phase will be made by the project sponsors based on the outcome of the ongoing design feasibility assessment phase.
By Dr Seokwoo Kim, Korea Institute for Energy Research, Dajeon, Korea
The Carbon Dioxide Reduction and Sequestration (CDRS) R&D center, which was launched in July, 2002 with the support of the Korean Ministry of Science & Technology (MOST) hosted this first international symposium in Seoul, Korea from January 17th to 19th. The symposium, which was initiated by a welcome and congratulatory speech by Dr. Seok-Sik Choi, vice-minister of the Ministry of Science and Technology (MOST), included a plenary session, two concurrent sessions throughout the two day meeting and an exhibition. An Asia Pacific Economic Cooperation (APEC) technical workshop with international experts in CO2 capture and storage attending was also held in conjunction with the symposium.
During the plenary session, Dr. Richard Bradley from the International Energy Agency and Dr. Sung-Chul, Shin from the Korea Institute of Energy Research (KIER) delivered presentations on the importance of R&D for greenhouse gas mitigation in Asia and Korea, respectively.
The plenary session was followed by concurrent sessions covering oxy-fuel combustion, CO2 sequestration, reactive separation and unused energy recovery that reflected Korea's heavy industry oriented economic structure. The CDRS center aims to reduce domestic carbon emissions significantly by increased energy efficiency in the petrochemical industry and DHC and/or CES sectors. Reactive separation and unused energy recovery technologies are technologies that could meet the goal of improved energy efficiency. In Korea, the petrochemical industry is one of the largest fossil fuel consumers and in view of this the CDRS center is focusing on the development of catalysts, membranes and other innovative process technologies. For unused energy recovery, active R&D efforts have been achieved to utilize natural heat sources such as river water and sewage water for household and industrial heat demand. At the same time, the center aims to reduce CO2 emissions into the atmosphere by developing carbon sequestration technologies, which were the topic of the oxy-fuel combustion and CO2 sequestration sessions at the symposium. Oxy-fuel combustion can be applied to steel industries and power plants. An interesting feature is that CDRS has developed a dry sorbent to capture CO2, unlike approaches taken in other countries exploring wet scrubbing technologies. The center also seeks diverse technologies to fix captured carbon. Concerning CO2 storage however, the center is currently developing core technologies for ocean sequestration and plans to expand its work to geological sequestration.
During the concurrent sessions, domestic and international experts delivered 32 oral presentations in total. The exhibition of the center's R&D activities was held simultaneously and that helped participants gain an understanding of the work underway and its outcomes.
The symposium clearly showed that the Korean government has a strong will to mitigate greenhouse gas emissions and to actively support related R&D to develop the relevant technologies. The CDRS R&D center performs a crucial role in this context and is expected to be the pillar in R&D to meet the UNFCCC's goal to stabilize the atmospheric concentration of CO2 through international cooperation.