Offshore CO2 storage resource assessment of the northern Gulf of Mexico (Texas-Louisiana)

The Offshore CO2 Storage Resource Assessment of the Northern Gulf of Mexico (Texas-Louisiana) project (a.k.a., "TXLA" study) supports Goals 3 & 4 of the DOE NETL Carbon Storage Program Plan by aiding industry's ability to predict CO2 storage capacity in geologic formations to within +/- 30%. This is achieved by assessing potential regional storage formations in the State and federally regulated portions of the Gulf of Mexico. The objective of the project was to conduct an offshore carbon storage resource assessment of the Gulf of Mexico, Texas — Louisiana study area. This was accomplished by: 1. Assessing the carbon dioxide (CO2) storage capacity of depleted oil and natural gas reservoirs utilizing existing data (well logs, records and sample descriptions from existing or plugged/abandoned wells, available seismic surveys, existing core samples, and other available geologic and laboratory data) from historical hydrocarbon industry activities in the heavily explored portions of the inner continental shelf portions of the Texas and Louisiana Gulf of Mexico coastal areas. 2. Assessing the ability and capacity of saline formations in the region to safely and permanently store nationally-significant amounts of anthropogenic CO2 using existing data. Additionally, the study identified at least one specific site with the potential to store at least 30 million tonnes of CO2, which may be considered in the future for commercial or integrated demonstration projects. The study also engaged the public and other stakeholders in the region through outreach activities to apprise them of the study objectives and results.Bureau of Economic Geolog

High Frequency (4th order) Sequence Stratigraphy of Early Miocene Deltaic Shorelines, Offshore Texas and Louisiana

DOE-NETL Award Numbers DE-FE0026083 and DEFE0029487Bureau of Economic Geolog

Comparing carbon sequestration in an oil reservoir to sequestration in a brine formation-field study

Geologic sequestration of CO2 in an oil reservoir is generally considered a different class than sequestration in formations which contain only brine. In this paper, the significance and validity of this conceptualization is examined by comparing the performance of CO2 injected into a depleted oil reservoir with the performance of similar injection into non-oil bearing sandstones using a field test at Cranfield Field, Mississippi as a case study. The differences considered are: (1)Residual oil in the reservoir slightly reduces the CO2 breakthrough time and rate of pressure build up as compared to a reservoir containing only brine, because under miscible conditions, more CO2 dissolves into oil than in to brine. (2)Dense wells provide improved assessment of the oil reservoir quality leading to improved prediction as well as verification of CO2 movement in this reservoir as compared to the sparsely characterized brine leg. The value of this information exceeds the risk of leakage. Assessment of the difference made by the presence of residual oil requires a good understanding reservoir properties to predict oil and gas distribution. Stratal slicing, attribute analysis and petrographic analyses are used to define the reservoir architecture. Real-time pressure response at a dedicated observation well and episodic pressure mapping has been conducted in the reservoir under flood since mid-2008; comparison measurements are planned for 2009 in down-dip environments lacking hydrocarbons. Model results using GEM compositional simulator compare well in general to measured reservoir response under CO2 flood; imperfections in model match of flood history document uncertainties Time laps RST logging is underway to validate fluid composition and migration models. Monitoring assessing the performance of the wells during the injection of CO2 suggests that the value of wells to provide field data for characterization exceeds the risk of leakage.Bureau of Economic Geolog

Project Evaluation: Phase II: Optimal Geological Environments for Carbon Dioxide Disposal in Brine-Bearing Formations (Aquifers) in the United States

Brine-bearing formations hold significant potential for long-term storage and disposal of greenhouse gases, particularly the large volumes of CO2 produced as a byproduct of fossil fuel combustion. The extensive industry experience in underground injection for enhanced oil recovery (EOR), gas storage, and deep-well waste injection demonstrates the feasibility of disposal into geologic environments using existing technology. Moreover, it is feasible that the residence time for injected CO2 would be adequate to prevent significant negative impacts on overlying potable water or the atmosphere. Several ongoing and planned projects indicate that underground injection technologies are transferable to the injection of CO2 for the purpose of reducing greenhouse gas emissions. However, brine formations are typically underutilized, resulting in a lack of comprehensive documentation of subsurface properties in easily accessible formats. Realistic and quantitative information about the relevant characteristics of the subsurface is essential for assessing the feasibility, costs, and risks of various options for CO2 disposal in brine formations. In this study, we have compiled and integrated a database of realistic properties of brine formations. This database is designed with a geographic structure in a geographic information system (GIS) so that it can be used to match CO2 emitters with prospective sinks.Bureau of Economic Geolog

Final Research Performance Progress Report: CarbonSAFE Phase I: Integrated CCS Pre-Feasibility ? Northwest Gulf of Mexico

Offshore storage achieves two major objectives for the US commercial large-scale CCS deployment: 1. Adding large capacity to serve local, regional, and potentially broader objectives. 2. Lowering risk by providing storage with one public owner, away from population centers, with no conflict with water resources and reduced concern about induced seismicity. A high-concentration CO2 source was identified as the top candidate for the project and going forward with the CarbonSAFE Phase II proposal. The top-rated source is the NET Power facility in Houston (La Porte), Texas. A manuscript based on analysis of results from the two-stage survey conducted in eight selected Texas counties (Brazoria, Chambers, Liberty, Galveston, Jefferson, Orange, Fort Bend, and Harris) was submitted to the International Journal of Greenhouse Gas Control on August 21, 2018. A primary confining interval (seal) is associated with MFS9 (biochronozone Amphistegina B), which can reach a thickness of up to 250 m. However, the Amphistegina B confining interval thins considerably in the onshore direction. Consequently, the most suitable portion of the Miocene section for future CO2 sequestration in the study area is considered to be the offshore area where Amphistegina B is thickest. Based on three models for capacity assessment, the study proposes a base case for the High Island 10-L Field in which 9 wells operated for 12 years each, completed into 4 zones, will emplace a total of 150 MMT of CO2, with wells placed in the water leg where all the plume will slowly migrate into the structural trap is feasible in terms of geology and engineering. The 10-L Field was assessed in more detail than other examined oil and gas fields in the study area to look at some specifics about how initial future CCS projects might be accomplished in the favorable GoM of the US region and expand the sites to a larger set to experiment with matching all the possible sources to sinks. The 10-L site is large enough to accept CO2 from multiple sinks; the expanded sinks are estimated to be large enough to accept all the CO2 from the region plus some from outside the region. A number of uncertainties were identified. The largest and most consequential uncertainty is the cost of offshore pipelines in the study setting, which impacts the conditions where CO2 transport would be by ship versus the cases where pipelines would be preferred. Ships are preferred for small volumes and short durations; pipelines for larger volumes and long duration. Additional work is needed to advance the maturity of multiple sinks available, to continue outreach to industries and the public, and to develop realistic source opportunities. The study demonstrates that industrial source clusters connected to a transport hub delivering CO2 to a nearby storage complex is the most cost-effective and improved way to decarbonize industrial activities, particularly in an expected low-carbon and increasing carbon price environment. The feasibility of the new business models should be based on the best use of the existing infrastructure and strategically built on new supporting infrastructure to drive down the costs of large-scale CCS deployment. Assessing the pre-feasibility of the commercial implementation of a CCS cluster and hub in the GoM energy ecosystem, our study links these elements successfully through an optimized combination (minimum cost) of CO2 sources on land with offshore storage.Bureau of Economic Geolog

A tool to facilitate modeling and pilot projects for sequestration of carbon dioxide in saline formations

Saline water-bearing formations that extend beneath much of the continental United States are attractive candidates for disposal of CO, produced during power generation or by other industrial processes. We have quantified the characteristics of saline formations that assure that gas can be efficiently injected into the selected subsurface unit and that it will remain sequestered for suitably long time periods. A GIS data base of these geologic attributes of 21 saline formations is available to support data analysis and comparison with CO, source locations. Attributes include depth, permeability, formation thickness, net sand thickness, percent shale, sand-body continuity, top seal thickness, continuity of top seal, hydrocarbon production from interval, fluid residence time, flow direction, C02soluhility in brine (P, T and salinity), rock mineralogy, water chemistry, and porosity. Variations in formation properties should be considered in order to match a surface greenhouse gas emissions reduction operation with a suitable subsurface disposal site.Bureau of Economic Geolog

Final Report for Gulf Coast Stacked-Storage Project SECARB Phase II at Cranfield

Phase I regional geologic characterization found that in the Gulf Coast, abundant geologic sequestration targets are found in many areas. The idea of stacked storage, developed for the current (Phase II) study, included the use of multiple hydrologically isolated injection zones beneath a common surface area to produce large capacity yet minimize the monitoring infrastructure footprint and increase public acceptance. Stacked zones include the use of CO2 for enhanced oil production (EOR), which was the focus of the Phase II study. An EOR project provided an opportunity to monitor injection at a higher rate and over a more prolonged injection period than an earlier test in brine (Frio Brine Pilot). The downdip water leg of the same field was then used for Phase III to assess geologic storage capacity beyond the use of CO2 for EOR (Hovorka and others, 2010). At the end of the regional study of options, the site selected was a four-way structural closure at a depth of 10,300 ft (3100 m) below the surface at Cranfield, Mississippi. The field produced oil, gas condensate, and methane gas from the lower Tuscaloosa Formation "D-E" sandstones during the period 1944 through 1966. The field was then pressure depleted and wells plugged and abandoned. The field was purchased by Denbury Onshore, LLC, to be flooded with large volumes of CO2 transported via pipeline from CO2 produced from a geologic accumulation at Jackson Dome, Mississippi. Project design focused on coordination of the monitoring design with Denbury's commercial plans for injection, infrastructure development, and permitting in the Phase II area on the north side of Cranfield field. Phase II provided an opportunity to test innovative monitoring approaches that may be needed in the future to document that either EOR or brine storage is performing correctly in terms of permanence of storage (Hovorka and others, 2010). Injection started July 15, 2008, in 2 wells but increased over the study period to 16 wells over an area of several square miles. Half the wells were updip injectors at the gas-oil contact, and half were downdip injectors injecting CO2 at the oil-water contact. The monitored injection was commercial (½ million metric tons per year) scale, and was sustained over a multiyear time frame, with the end of the Phase II project defined as September 30, 2010. In the report period, 23,640 MMSCF (1,229,510 metric tons) of CO2 was stored under Phase II. Injection and monitoring continued in the Phase II area; however, these were logistically connected to ongoing Phase III injection, which was conducted on the east side of Cranfield.Bureau of Economic Geolog