Paul R. Knox

The impact of geological heterogeneity on CO2 storage in brine formations: a case study from the Texas Gulf Coast

Abstract Geological complexities such as variable permeability and structure (folds and faults) exist to a greater or lesser extent in all subsurface environments. In order to identify safe and effective sites in which to inject CO2 for sequestration, it is necessary to predict the effect of these heterogeneities on the short- and long-term distribution of CO2. Sequestration capacity, the volume fraction of the subsurface available for CO2 storage, can be increased by geological heterogeneity. Numerical models demonstrate that in a homogeneous rock volume, CO2 flowpaths are dominated by buoyancy, bypassing much of the rock volume. Flow through a more heterogeneous rock volume disperses the flow paths, contacting a larger percentage of the rock volume, and thereby increasing sequestration capacity. Sequestration effectiveness, how much CO2 will be sequestered for how long in how much space, can also be enhanced by heterogeneity. A given volume of CO2 distributed over a larger rock volume may decrease leakage risk by shortening the continuous column of buoyant gas acting on a capillary seal and inhibiting seal failure. However, where structural heterogeneity predominates over stratigraphic heterogeneity, large columns of CO2 may accumulate below a sealing layer, increasing the risk of seal failure and leakage.

Frio Brine Sequestration Pilot in the Texas Gulf Coast

Publisher Summary Subterranian brine-bearing formations that are hydrologically separated from potable water have been widely recognized as having high potential for very long term (geologic time scale) sequestration of greenhouse gases, particularly the large volumes of CO2 resulting from combustion or generation of hydrogen from fossil fuels. Numerous feasibility and modeling studies document the potential for this type of disposal; however, no site isolated from the complexities introduced by hydrocarbon production is currently available where basic field experiments to confirm model results and demonstrate feasibility can be conducted. The chapter describes a project that aims to develop a suitable site and conduct initial experiments. A project has been developed that will quickly produce information and experience by (1) recycling existing infrastructure, (2) building on known technologies and regulatory processes for deep-well waste disposal and CO2-enhanced oil recovery (CO2-EOR), (3) selecting a geologically isolated injection site suitable for experiments with small volumes of injected CO2 without risk of impact to adjacent properties, and (4) building on the earlier phase of the projects and of the GEOSEQ project. This site complements and extends the results of other planned and ongoing sequestration experiments in EOR settings or future large-scale settings by providing a site for initial experiments in a typical high-injectivity sandstone area of high emissions.

Area of review: how large is large enough for carbon storage?

The Texas Gulf Coast is an attractive target for carbon storage. Stacked sand-shale layers provide large potential storage volumes and defense-in-depth leakage protection. However, multiple perforations resulting from intensive hydrocarbon exploration and production have weakened seal integrity in many favorable locations. If the ultimate goal of carbon storage is to isolate large volumes of CO2 for hundreds to thousands of years, plume migration will encounter inadequately completed wells miles away from the injection zone. Moreover, the detrimental impact of CO2 on cement could undermine the structural integrity of all contacted wells, although pressure effects subside quickly after injection. Even wells abandoned to current standards cannot be guaranteed leak-free in the long term. We describe spatial statistics extracted from the Texas RRC Well Bore database as applied to carbon storage. Although the Area of Review (AOR) has been traditionally defined by a fixed radius with the strong regulatory requirement that the injectate stays within the injection layer, buoyancy is a major characteristic of CO2 that introduces a third dimension into the Area of Review process. Using simple geological mapping to characterize structural traps, we determine the likely pathway and the contacted volume of a migrating plume. The latter can be as large as a fault compartment with dimensions of 20 km × 20 km. However, the contacted volume is ultimately a function of the total injected volume, and the specifics of each project should dictate the dimensions of the zone of endangering influence (ZEI). An option, viable for the Texas Gulf Coast, to reduce geologic uncertainty, to decrease the impact of wells, and to limit the amount of information to be collected, is to inject CO2 below the maximum penetration of most wells. Biographic Sketch: Jean-Philippe (JP) Nicot works for the Bureau of Economic Geology, John A. and Katherine G. Jackson School of Geosciences, The University of Texas at Austin, University Station Box X, Austin, Texas 78713-8924, U.S.A.; Tel. 512-471-1534; Fax: 512-471-0140; email: jp.nicot@beg.utexas.edu. JP has a Ph.D. in Civil Engineering from The University of Texas at Austin. His current interests include hydrogeological aspects of carbon storage and brackish water desalination.

Abstract: Determining Between-Well Reservoir Architecture in Deltaic Sandstones Using Only Well Data: Oligocene Frio Formation, Tijerina-Canales-Blucher Field, South Texas

ABSTRACT Accurate prediction of compartment architecture and intracompartment heterogeneity is necessary to locate and recover the estimated 15 billion barrels of mobile oil remaining in U.S. fluvial-dominated deltaic reservoirs. Complex architecture and rapid 1ateral variability in such reservoirs complicate subsurface prediction, particularly in mature fields where well logs are the only available subsurface data. A genetic-stratigraphy-based methodology has been developed that improves between-well prediction of deltaic reservoir architecture and, thus, reduces risks associated with infill-drilling. In the area of Tijerina-Canales-Blucher (T-C-B) field, which lies on the northeast margin of the Oligocene-age Norias delta, the productive 3rd-order Lower Frio unit was subdivided into eight 4th-order genetic units. Delta-front positions were identified on the basis of regional and subregional cross sections. The 4th-order units (30 to 80 ft thick) were subdivided into two to five 5th-order units (10 to 30 ft thick). Log patterns and net sandstone maps were used to identify facies, which include (1) distributary channels (up to 25 ft thick, 8,000 ft wide, and commonly narrower than 40-acre well spacing), (2) mouth bars (up to 15 ft thick, ranging in size from 40 to 640 acres in area, commonly 5,000 ft wide), and (5) washover fans (up to 10 ft thick, and 7,000 ft wide). Many reservoir compartments, including the prolific 21-B interval, contain a significant degree of stratigraphic trapping caused by updip pinchout of delta front or washover sandstones or convex-updip segments of meandering distributary channel sandstones. The methodology and results of this Study are directly applicable to other Gulf Coast fluvial-deltaic reservoirs in the Frio Formation and Wilcox Group, as well as to deltaic reservoirs throughout the U.S. The general methodology should be applied to develop remaining reserves in mature fields where geophysical data are lacking. Further study of T-C-B reservoirs may include stratigraphic analysis of 3-D seismic data and infill drilling to confirm between-well interpretations. End_of_Record - Last_Page 475-------

Frio pilot in CO2 sequestration in brine-bearing sandstones: The University of Texas at Austin, Bureau of Economic Geology, report to the Texas Commission on Environmental Quality to accompany a class V application for an experimental technology pilot injection well.

GEOSEQ project (LBNL, LLNL, ORNL), NETL, Schlumberger–Doll Research Center, Transpetco, Sandia Technologies

Abstract: Predicting Seal Efficiency and Trapped Hydrocarbon Type in Gulf Coast Hydrocarbon Systems:Lessons Learned From West Fulton Beach Field, Mid-Texas Gulf Coast

ABSTRACT Many Gulf Coast fields consist of multiple vertically stacked sandstones in which oil and gas are seemingly randomly distributed stratigraphically. Hydrocarbon entrapment is strongly affected by seal competency and possibly by formation pressure, and these factors are in turn controlled by the characteristics of the interbedded shales. In West Fulton Beach field, Aransas County, Texas, the Oligocene, Frio Formation shales were deposited as shelf mudstones and represent flooding events in a barrier bar/strandplain and inner shelf setting. Reservoirs were placed into a high-frequency genetic stratigraphic framework to test the theory that hydrocarbon entrapment is controlled by a hierarchy of maximum flooding surfaces. Cumulative oil and gas production and gas-to-oil ratios were tabulated for individual reservoirs, as well as for all reservoirs in each 5th-, 4th-, and 3rd-order genetic unit, as measures of entrapment. Total producible hydrocarbons (oil plus gas, in barrels of oil equivalent) increase in volume in successively shallower 3rd-order Frio units (each 800 to 1,000 ft thick), capped by the 600-ft-thick Miocene Anahuac Shale. Likewise, successively shallower 4th-order units (120 to 200 ft thick) within each 3rd-order unit contain greater volumes of total hydrocarbons, as well as greater percentages of gas. This pattern exists independent of shale thickness or reservoir porosity, and it is repeated at the 5th- and 6th-order levels, when viewed on a per-gross-ft-of-sandstone basis. Thus, although appearing random, when evaluated carefully within a stratigraphic framework, total hydrocarbon volumes and oil versus gas distributions follow a systematic pattern tied to their position within a stratigraphic hierarchy. This finding can be used to more accurately constrain seal risk in exploration or deeper pool drilling and to evaluate hydrocarbon type ahead of the drill bit. Further study is needed to model reservoir filling, incorporating reservoir pressures, to better understand the petrophysical controls on hydrocarbon entrapment. Additionally, observations of lateral changes in the observed cyclic patterns may produce a greater understanding of the effects that facies changes and genetic unit stacking patterns have on seal competency. End_of_Record - Last_Page 476-------

Revitalizing a mature oil play: Strategies for finding and producing unrecovered oil in Frio Fluvial-Deltaic Sandstone Reservoirs of South Texas

The Frio Fluvial-Deltaic Sandstone Play of South Texas is one example of a mature play where reservoirs are being abandoned at high rates, potentially leaving behind significant unrecovered resources in untapped and incompletely drained reservoirs. Nearly 1 billion barrels of oil have been produced from Frio reservoirs since the 1940`s, yet more than 1.6 BSTB of unrecovered mobile oil is estimated to remain in the play. Frio reservoirs of the South Texas Gulf Coast are being studied to better characterize interwell stratigraphic heterogeneity in fluvial-deltaic depositional systems and determine controls on locations and volumes of unrecovered oil. Engineering data from fields throughout the play trend were evaluated to characterize variability exhibited by these heterogeneous reservoirs and were used as the basis for resource calculations to demonstrate a large additional oil potential remaining within the play. Study areas within two separate fields have been selected in which to apply advanced reservoir characterization techniques. Stratigraphic log correlations, reservoir mapping, core analyses, and evaluation of production data from each field study area have been used to characterize reservoir variability present within a single field. Differences in sandstone depositional styles and production behavior were assessed to identify zones with significant stratigraphic heterogeneity and a high potential for containing unproduced oil. Detailed studies of selected reservoir zones within these two fields are currently in progress.

Application of Sequence Stratigraphy to the Prioritization of Incremental Growth Opportunities in Mature Reservoirs: An Example from Frio Fluvial-Deltaic Sandstones, T-C-B Field, South Texas

ABSTRACT The U. S. Department of Energy has identified mature fluvial-deltaic reservoirs as being the highest priority reservoir type for near-term domestic reserve-growth potential. Detailed characterization studies to locate the estimated 15 billion barrels of mobile oil remaining in these reservoirs must focus first on those reservoirs with the greatest potential if they are to be economically successful. In quick-look analyses that estimate reserve-growth potential, stratigraphic heterogeneity is the most difficult factor to evaluate. Through detailed study of Frio Formation upper delta-plain fluvial reservoirs in T-C-B field, south Texas, and by using outcrop observations from the Ferron Sandstone, central Utah, a model has been developed that relates stratigraphic heterogeneity to rate of accommodation during deposition, a feature that varies predictably throughout a depositional cycle. Upper delta-plain fluvial channelbelts deposited at the base of a depositional cycle, during periods of low accommodation, are narrow, few in number, and relatively internally homogeneous. As a result, they are not effectively contacted by rigid well patterns but can drain large reservoir volumes through individual completions. Because they are commonly isolated within floodplain mudstones, they possess the potential for stratigraphically trapped accumulations away from the structural crest. In contrast, channelbelts deposited at the top of a depositional cycle, during periods of high accommodation, are broad and internally heterogeneous. Despite appearing laterally continuous, they are extensively compartmented by high volumes of low-permeability siltstones and shales, as well as mudclast-rich lag deposits that drape channel boundaries and limit fluid flow at channel-on-channel contacts. AU other factors being equal, these channelbelt types possess the greatest reserve-growth potential because past completions have only contacted small reservoir volumes. This accommodation-based model for reservoir heterogeneity in upper delta-plain fluvial settings represents the first in a new generation of reservoir models. Similar models developed for reservoirs deposited in the spectrum of depositional settings will improve the effectiveness and increase the use of detailed reservoir characterization studies, resulting in the improved identification and recovery of oil and gas remaining in mature reservoirs throughout the United States.

Architecture, Internal Heterogeneity, and Resulting Drainage Efficiency of Upper Oligocene Frio Formation Inner-Shelf Sandstone Reservoirs in West Fulton Beach Field, Aransas County, Texas

ABSTRACT This study suggests that a significant volume of resources has been overlooked in inner-shelf sandstone reservoirs in the Frio Formation because of their complex architecture and the practice of focusing on thicker reservoirs during initial field development. Subregional and local geophysical well-log correlation, net sandstone and net pay mapping, petrophysical analysis, and mass-balance volumetric calculations were undertaken in West Fulton Beach field, Aransas County, Texas, to assess the reserve-growth potential of these reservoirs. To identify individual reservoir bodies, it was necessary to break intervals down to fifth- and sixth-order genetic stratigraphic units. Inner-shelf sandstone bodies range in thickness from 2 to 8 ft and form shore-parallel lenses up to 1.6 mi long and 0.6 mi wide. These lenses, which may be associated with prograding shorefaces, transgressive disconformities, and retrogradational shelf sequences, form laterally stacked, commonly vertically overlapping, and potentially amalgamated bodies. They average up to 32 percent porosity and 990 md permeability. Internal heterogeneity is low, and drainage efficiency is moderate. Gas completions can drain areas of 150 to 300 acres, whereas oil completions drain from 20 to 50 acres. Remaining resources identified within incompletely drained and untapped reservoirs of eight intervals in West Fulton Beach field total 11.8 billion cubic feet of gas and 315,000 barrels of oil, representing reserve-growth potential of 8 and 4 percent, respectively. Although much of this potential lies in small compartments containing from 50 to 500 million cubic feet each, several such targets can be identified in a vertically stacked arrangement such that a single wellbore can intersect 2 to 3 billion cubic feet of reserves. Projecting these results to the other fields of the play suggests that as much as 752 billion cubic feet of gas and 7 million barrels of oil remain as infill and recompletion targets. Because many of the Tertiary units of the Gulf Coast Basin share a similar depositional setting with the Frio Formation, significant reserve-growth potential is thought to exist in inner-shelf sandstones throughout the basin.