Geologic Framework for the National Assessment of 

Carbon Dioxide Storage Resources─South Florida Basin

By Tina L. Roberts-Ashby, Sean T. Brennan, Matthew D. Merrill, Madalyn S. Blondes, Philip A. Freeman, 

Steven M. Cahan, Christina A. DeVera, and Celeste D. Lohr

Chapter L of

Geologic Framework for the National Assessment of Carbon Dioxide Storage Resources 

Edited by Peter D. Warwick and Margo D. Corum

Open-File Report 2012–1024–L

U.S. Department of the Interior

U.S. Geological Survey
ii

U.S. Department of the Interior

SALLY JEWELL, Secretary

U.S. Geological Survey

Suzette M. Kimball, Acting Director

U.S. Geological Survey, Reston, Virginia 2015 

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Suggested citation: 

Roberts-Ashby, T.L., Brennan, S.T., Merrill, M.D., Blondes, M.S., Freeman, P.A., Cahan, S.M., DeVera, C.A., and

Lohr, C.D., 2015, Geologic framework for the national assessment of carbon dioxide storage resources—South Florida

Basin, chap. L of Warwick, P.D., and Corum, M.D., eds., Geologic framework for the national assessment of carbon

dioxide storage resources: U.S. Geological Survey Open-File Report 2012–1024–L, 22 p., 

http://dx.doi.org/10.3133/ofr20121024L. 

ISSN 2331-1258 (online)

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iii

Editors’ Preface

By Peter D. Warwick and Margo D. Corum

The 2007 Energy Independence and Security Act (Public Law 110–140) directs the U.S. 

Geological Survey (USGS) to conduct a national assessment of potential geologic storage resources for 

carbon dioxide (CO2) and to consult with other Federal and State agencies to locate the pertinent 

geological data needed for the assessment. The geologic sequestration of CO2 is one possible way to

mitigate its effects on climate change.

The methodology that is being used by the USGS for the assessment was described by Brennan 

and others (2010), who revised the methodology by Burruss and others (2009) according to comments 

from peer reviewers, members of the public, and experts on an external panel. The assessment 

methodology is non-economic and is intended to be used at regional to sub-basinal scales. 

The operational unit of the assessment is a storage assessment unit (SAU), composed of a porous 

storage formation with fluid flow and an overlying fine-grained sealing unit. Assessments are conducted at 

the SAU level and are aggregated to basinal and regional results. SAUs have a minimum depth of 3,000 

feet (ft), which ensures that the CO2 is in a supercritical state (and thus occupies less pore space than a 

gas). Standard SAUs have a maximum depth of 13,000 ft below the surface, a depth accessible with 

average injection pipeline pressures (Burruss and others, 2009; Brennan and others, 2010). Where 

geologic conditions favor CO2 storage below 13,000 ft, an additional deep SAU is assessed. 

The assessments are also constrained by the occurrence of relatively fresh formation water. 

Specifically, any formation water having a salinity less than 10,000 milligrams per liter (mg/L) total 

dissolved solids (TDS), regardless of depth, has the potential to be used as a potable water supply (U.S. 

Environmental Protection Agency, 2009). The U.S. Environmental Protection Agency (2008) has 

proposed the limit of 10,000 mg/L TDS for injection of CO2. Therefore, the potential storage resources for 

CO2 in formations where formation waters have salinities less than 10,000 mg/L TDS are not assessed 

(Brennan and others, 2010). 

This report series contains geologic descriptions of each SAU identified within the assessed basins 

and focuses on the particular characteristics specified in the methodology that influence the potential CO2

storage resource. Although assessment results are not contained in these reports, the geologic framework 

information will be used to calculate a statistical Monte Carlo-based distribution of potential storage space 

in the various SAUs following Brennan and others (2010). Figures in this report series show SAU 

boundaries and cell maps of well penetrations through the sealing unit into the top of the storage 

formation. Wells sharing the same well borehole are treated as a single penetration. Cell maps show the 

number of penetrating wells within one square mile and are derived from interpretations of incompletely 

attributed well data (IHS Energy Group, 2011; and other data as available), a digital compilation that is 

known not to include all drilling. The USGS does not expect to know the location of all wells and cannot 

guarantee the amount of drilling through specific formations in any given cell shown on cell maps.

References Cited

Brennan, S.T., Burruss, R.C., Merrill, M.D., Freeman, P.A., and Ruppert, L.F., 2010, A probabilistic 

assessment methodology for the evaluation of geologic carbon dioxide storage: U.S. Geological Survey 

Open-File Report 2010–1127, 31 p., accessed March 22, 2011, at http://pubs.usgs.gov/of/2010/1127/. 

Burruss, R.C., Brennan, S.T., Freeman, P.A., Merrill, M.D., Ruppert, L.F., Becker, M.F., Herkelrath, 

W.N., Kharaka, Y.K., Neuzil, C.E., Swanson, S.M., Cook, T.A., Klett, T.R., Nelson, P.H., and Schenk, 
iv

C.J., 2009, Development of a probabilistic assessment methodology for evaluation of carbon dioxide 

storage: U.S. Geological Survey Open-File Report 2009–1035, 81 p., accessed March 22, 2011, at 

http://pubs.usgs.gov/of/2009/1035/. 

IHS Energy Group, 2011, ENERDEQ U.S. well data: IHS Energy Group, online database available from 

IHS Energy Group, 15 Inverness Way East, D205, Englewood, CO 80112, U.S.A., accessed January 20, 

2011, at http://energy.ihs.com/. 

U.S. Environmental Protection Agency, 2008, Federal requirements under the underground injection 

control (UIC) program for carbon dioxide (CO2) geologic sequestration (GS) wells: Washington, D.C., 

U.S. Environmental Protection Agency, proposed rule, accessed March 23, 2011, at 

http://www.epa.gov/fedrgstr/EPA-WATER/2008/July/Day-25/w16626.htm.

U.S. Environmental Protection Agency, 2009, Safe Drinking Water Act (SDWA): Washington, D.C., U.S. 

Environmental Protection Agency Web site, accessed January 14, 2009, at 

http://www.epa.gov/ogwdw/sdwa/index.html. 
v

Contents

Editors’ Preface ..........................................................................................................................................................iii

References Cited........................................................................................................................................................iii

Conversion Factors.....................................................................................................................................................vi

Abbreviations..............................................................................................................................................................vi

Abstract ...................................................................................................................................................................... 1

Introduction................................................................................................................................................................. 1

Pre-Punta Gorda SAU C50500101............................................................................................................................. 6

Sunniland Formation SAU C50500102....................................................................................................................... 8

Gordon Pass and Marco Junction Formations SAU C50500103.............................................................................. 11

Dollar Bay Formation SAU C50500104 .................................................................................................................... 13

Cedar Keys and Lawson Formations SAU C50500105............................................................................................ 15

Acknowledgments .................................................................................................................................................... 18

References Cited...................................................................................................................................................... 18

Figures

1. Geologic map of the South Florida Basin study area within the southeastern United States. Major 

structural features adapted from Grinnell (1976), Ferber (1985), Halley (1985), Huddlestun (1993), 

and Randazzo (1997). In the inset on the lower left, area in outlined red is the South Florida Basin 

study area...................................................................................................................................................... 4

2. Stratigraphic column for the South Florida Basin study area. Storage assessment units consist of a 

potential reservoir (red) and potential regional seal (blue). Modified from Pollastro and others (2001) 

and Faulkner and Applegate (1986) .............................................................................................................. 5

3. Map of the U.S. Geological Survey storage assessment unit (SAU) boundaries for the Pre-Punta Gorda 

SAU in the South Florida Basin. Grid cells (one square mile) represent counts of wells derived from 

ENERDEQ well database (IHS Energy Group, 2011) that have penetrated the reservoir-formation top ....... 7

4. Map of the U.S. Geological Survey storage assessment unit (SAU) boundaries for the Sunniland 

Formation SAU in the South Florida Basin. Grid cells (one square mile) represent counts of wells 

derived from ENERDEQ well database (IHS Energy Group, 2011) that have penetrated the reservoirformation top................................................................................................................................................ 10

5. Map of the U.S. Geological Survey storage assessment unit (SAU) boundaries for the Gordon Pass 

and Marco Junction Formations SAU in the South Florida Basin. Grid cells (one square mile) represent 

counts of wells derived from ENERDEQ well database (IHS Energy Group, 2011) that have penetrated 

the reservoir-formation top........................................................................................................................... 12

6. Map of the U.S. Geological Survey storage assessment unit (SAU) boundaries for the Dollar Bay 

Formation SAU in the South Florida Basin. Grid cells (one square mile) represent counts of wells 

derived from ENERDEQ well database (IHS Energy Group, 2011) that have penetrated the reservoirformation top................................................................................................................................................ 14

7. Map of the U.S. Geological Survey storage assessment unit (SAU) boundaries for the Cedar Keys and 

Lawson Formations SAU in the South Florida Basin. Grid cells (one square mile) represent counts of 

wells derived from ENERDEQ well database (IHS Energy Group, 2011) that have penetrated the 

reservoir-formation top................................................................................................................................. 17
vi

Conversion Factors

Multiply By To obtain

Length

inch (in.) 2.54 centimeter (cm)

foot (ft) 0.3048 meter (m)

mile (mi) 1.609 kilometer (km)

Area

square foot (ft2) 0.09290 square meter (m2)

square foot (ft2) 0.00002296 acre 

square mile (mi2) 2.59 square kilometer (km2)

Volume

barrel (bbl), (petroleum, 1 barrel=42 gal) 0.1590 cubic meter (m3) 

cubic foot (ft3) 0.02832 cubic meter (m3) 

1,000 cubic feet (MCF) 28.32 cubic meter (m3)

cubic meter (m3) 6.290 barrel (petroleum, 1 barrel = 42 gal)

Abbreviations

CKLIZ Cedar Keys/Lawson Injection Zone

CO2 carbon dioxide

EPA U.S. Environmental Protection Agency

mD millidarcy

mg/L milligrams per liter

SAU storage assessment unit

TDS total dissolved solids

UIC underground injection control

USGS U.S. Geological Survey
1

Geologic Framework for the National Assessment of 

Carbon Dioxide Storage Resources─South Florida Basin

By Tina L. Roberts-Ashby, Sean T. Brennan, Matthew D. Merrill, Madalyn S. Blondes, Philip A. Freeman, Steven M. 

Cahan, Christina A. DeVera, and Celeste D. Lohr

Abstract

This report presents five storage assessment units (SAUs) that have been identified as potentially 

suitable for geologic carbon dioxide (CO2)sequestration within a 35,075-square-mile area that includes 

the entire onshore and State-water portions of the South Florida Basin. Platform-wide, thick successions 

of laterally extensive carbonates and evaporites deposited in highly cyclic depositional environments in 

the South Florida Basin provide several massive, porous carbonate reservoirs that are separated by 

evaporite seals. For each SAU identified within the basin, the areal distribution of the reservoir-seal 

couplet identified as suitable for geologic CO2 sequestration is presented, along with a description of the 

geologic characteristics that influence the potential CO2 storage volume and reservoir performance. On a 

case-by-case basis, strategies for estimating the pore volume existing within structurally and (or)

stratigraphically closed traps are also discussed. Geologic information presented in this report has been

employed to calculate potential storage capacities for CO2 sequestration in the SAUs assessed herein, 

although complete assessment results are not contained in this report.

Introduction

This report is meant to provide geologic descriptions and basic reservoir characterization for 

storage assessment units (SAUs) identified within the South Florida Basin, in support of U.S. Geological 

Survey (USGS) Geologic Carbon Dioxide Storage Resources Assessment Team (2013a,b,c), which 

provide the results, data, and summary of a national assessment of carbon dioxide (CO2) storage resources 

within the United States. The area assessed for CO2 storage within the South Florida Basin and the 

surrounding region encompasses an area of approximately 22,447,911 acres and extends across the southcentral and southern extents of the Florida peninsula (fig. 1). Although the South Florida Basin continues 

offshore toward its basin center to the southwest of peninsular Florida, this assessment was only 

conducted onshore and outward to the State-water boundary (fig. 1).

The South Florida Basin is located on the Florida Platform, a carbonate platform that can be more 

than 350 miles (mi) wide, extending from the shelf break off the east coast of Florida westward to the 

Florida Escarpment, a bathymetric and geologic feature that is more than 450 mi long that plunges from a 

depth of approximately 2,000 feet (ft) below sea level to more than 10,000 ft at the modern abyssal plain 

of the Gulf of Mexico (fig. 1; Hine and others, 2001; Scott, 2001). Together with the carbonate Bahama 

Platform, the Florida Platform was part of a larger “gigaplatform” during the Jurassic that extended from 

Mexico across the Gulf of Mexico to the Grand Banks of Newfoundland and is thought to have been one 

of the largest laterally continuous carbonate platforms in geologic history (Poag, 1991; Hine and others, 

2001). The basement strata of the Florida Platform are composed of Precambrian and Cambrian igneous 

and metamorphic rocks, Ordovician to Devonian sedimentary rocks, and Triassic and Jurassic volcanic

rocks whose depths increase from central-northern peninsular Florida to southern Florida (Milton, 1972; 

Arthur, 1988; Randazzo, 1997; Scott, 2001). Scientists believe that the igneous-metamorphic and 

sedimentary basement rocks were once attached to the African plate before rifting events associated with
2

the breaking apart of the supercontinent Pangea in the Triassic or pre-Middle Jurassic(?) (Smith, 1982; 

Randazzo, 1997; Scott, 2001). 

The Florida Platform has been subjected to multiple fluctuations in relative sea level throughout 

its history, with the highest levels occurring during the Late Cretaceous when a large majority of the 

platform was submerged (Randazzo, 1997). During the mid-Cretaceous, relative sea levels and paleoenvironmental stresses, considered by many to be the result of worldwide oceanic anoxic events, affected 

sedimentation rates on the Florida Platform (Hine and others, 2001). Ultimately, sediment production and 

accumulation could not keep pace with tectonic subsidence that was occurring at that time, and the 

western portion of the Florida Platform became submerged (Hine and others, 2001). Regressive relative

sea levels dominated the Tertiary, and by the Oligocene, relative sea levels were considerably less than 

modern-day sea levels, exposing much of the Florida Platform (Randazzo, 1997). Furthermore, during the 

Tertiary, the platform had an elevated eastern portion and a largely submerged western portion that was 

no longer suitable for major carbonate accumulation; therefore, the Florida Platform was transformed 

from a rim-type platform into a gently west-sloping ramp (Randazzo, 1997; Hine and others, 2001).

The South Florida Basin has a maximum sediment thickness of 15,000–17,000 ft and a center that

is located offshore due west of Collier County (Pressler, 1947; Halley, 1985). The basin is positioned to 

the east of the Lower Cretaceous Reef trend, which generally runs parallel to the Florida Escarpment and 

continues into the Gulf of Mexico (fig.1; Halley, 1985). The South Florida Basin was subjected to 

differential subsidence and is part of the larger, regionally subsiding South Florida Embayment that 

includes the southeastern Gulf of Mexico, south Florida, and the Bahamas (Grinnell, 1976). The onshore 

part of the South Florida Basin, an emergent segment of the Florida Platform, and the Florida State waters 

represent about half of the entire basin (fig. 1; Applegate and Pontigo, 1984). 

During the middle Jurassic through to about the middle Oligocene, shallow-water marine 

deposition was dominant in the South Florida Basin and sequences comprising carbonate and evaporite 

rocks were deposited in water typically less than about 300 ft deep (Halley, 1985; Scott, 2001). Organicrich carbonate mud also accumulated during the intermittent occurrence of salinity-stratified interior 

lagoons (Halley, 1985). During this time, two important features affected sedimentation on the Florida 

Platform, including the South Florida Basin: the Suwannee Channel and Gulf Trough, together known as 

the Georgia Channel System (Miller, 1986; Huddlestun, 1993; Randazzo, 1997). The Suwannee Channel 

was a sedimentologic system positioned across northern Florida and southern Georgia through which the 

Suwannee Current flowed (fig. 1; Chen, 1965; Randazzo, 1997; Hine and others, 2001). The channel 

existed from Late Cretaceous to middle Eocene and connected the northern Gulf of Mexico to the Atlantic 

Ocean; the Gulf Trough existed from middle Eocene to middle Miocene (Randazzo, 1997; Hine and 

others, 2001). The position of and sediment-transporting current within the Georgia Channel System, 

together with high relative sea levels, prevented clastic sediments from encroaching down the Florida 

Platform and further contributed to a carbonate-dominated platform. During the late Oligocene, however, 

the channel system began to infill, possibly during relative sea level regression when river deltas were 

depositing sediments derived from the southern Appalachian Mountains due to renewed uplift and erosion 

within the orogenic system, marking the beginning of major clastic sediment deposition on the platform 

(Randazzo, 1997; Hine and others, 2001; Scott, 2001).

The South Florida Basin has been a target for petroleum exploration and production since the first 

discovery of oil within the Sunniland Formation in 1943 (Lloyd, 1996). Signs of hydrocarbons have been 

identified in several other geologic units within the basin; however, the Sunniland Formation is the only 

unit that has had commercial production to date, with a total of 14 existing or depleted oil fields (Palacas, 

1978; Palacas and others, 1981; Applegate and Pontigo, 1984; Applegate, 1987; Winston, 1987; Lloyd, 

1996; Pollastro and others, 2001). The most recently completed geologic assessments of undiscovered oil 

and gas resources conducted by the USGS present the history of hydrocarbon exploration and production 

in the South Florida Basin (Pollastro, 2001; Pollastro and others, 2001). The USGS estimates mean values 

of approximately 351 million barrels of oil, 1,658 billion cubic feet of gas, and approximately 75 million 

barrels of natural gas liquids that remain undiscovered in the South Florida Basin (Pollastro and others, 
3

2001). Pore volumes associated with existing and depleted oil and gas fields may be available for the 

purpose of geologic CO2 sequestration, with the additional possibility of uncharged traps that have yet to 

be delineated. Nonpetroleum-producing saline aquifers occur throughout the basin as well, with total 

dissolved solid (TDS) concentrations exceeding 10,000 milligrams per liter (mg/L). These aquifers could

provide additional pore volume for CO2 sequestration. 

To date, at least two geochemically distinct hydrocarbon systems, separated by the massive Punta 

Gorda Anhydrite, have been recognized in the South Florida Basin that are each associated with unique 

source rocks and are confined to discrete stratigraphic intervals (Pollastro and others, 2001). This

stratigraphic confinement of hydrocarbon systems is important to the potential of geologic CO2

sequestration because it suggests the presence of several regional sealing units within the basin. The 

geographic extent of “regional” can vary from basin to basin within the United States. Within the South 

Florida Basin, “regional” is considered to be an area that typically extends across two or more counties. 

Regional seals are essential components to CO2 storage sites, and their presence in hydrocarbon systems 

of the South Florida Basin suggests the potential for containment of CO2 over long periods of time (that 

is, millennia) and a low risk of leakage from storage sites into overlying sources of drinking water or into 

the atmosphere (Wilson and others, 2003). 

Multiple geologic units within the South Florida Basin meet the USGS criteria for conducting a 

regional assessment for CO2 storage capacity and are for the most part confined to Jurassic and 

Cretaceous strata. The USGS-assessed reservoir units include (1) Pre-Punta Gorda SAU, (2) Sunniland 

Formation SAU, (3) Gordon Pass and Marco Junction Formations SAU, (4) Dollar Bay Formation SAU, 

and (5) Cedar Keys and Lawson Formations SAU (fig. 2). 

In the following five sections, the depositional setting, distribution, and stratigraphy of each 

prospective SAU are presented. Key information that provides the basis for calculating the capacity of 

each SAU for buoyant and residual CO2 storage (as described in Burruss and others, 2009; Brennan and 

others, 2010; Blondes and others, 2013), as well as information that relates to the reservoir characteristics 

for each unit, is also summarized. Such key input parameters include depth from surface; area; gross 

thickness; net-porous-interval thickness, or the portion of the SAU gross thickness that contains porous 

rock identified as being sufficient for CO2 storage; porosity of the net-porous interval; and range of 

permeability for the entire SAU. Because the U.S. Environmental Protection Agency (EPA 2009, 2013) 

stipulates that aquifers used for CO2 sequestration must contain groundwater with a TDS concentration 

greater than 10,000 mg/L, regional trends in groundwater quality for an assessed area are characterized, 

and the area fraction of the SAU that is available for CO2 storage is estimated. All parameters were 

estimated using a combination of proprietary databases (such as IHS Energy Group, 2010, 2011 and 

Nehring Associates, Inc., 2010); public and nonproprietary databases and well-log repositories; and 

published literature, including isopachs, structure maps, and cross sections.

Finally, in order to differentiate between the pore volume contained within buoyant traps and that 

contained within residual traps for the various SAUs (see Brennan and others, 2010; Blondes and others, 

2013), the pore volume enclosed within buoyant traps, which are analogous to stratigraphic and (or) 

structural hydrocarbon traps, is defined. For each SAU, (a) minimum and (b) most likely pore volumes 

enclosed within buoyant traps were constrained on the basis of (1) the sum of the cumulative oil and gas 

production and the known hydrocarbon reserve volume and (2) the minimum buoyant pore volume plus 

the estimated volume of undiscovered resources (see Brennan and others, 2010; Blondes and others, 

2013). Because this method was applied to all SAUs, it is not discussed on a case-by-case basis. An upper 

boundary for enclosed pore volume was also determined for each unit, and methods for the various SAUs 

are discussed on a case-by-case basis. The information derived from the data sources and methods 

described in this report were used in accordance with the USGS Carbon Sequestration Assessment 

Methodology (Brennan and others, 2010; Blondes and others, 2013) to calculate the available storage 

space for CO2 within each SAU.
4

Figure 1. Geologic map of the South Florida Basin study area within the southeastern United States. Major 

structural features adapted from Grinnell (1976), Ferber (1985), Halley (1985), Huddlestun (1993), and Randazzo

(1997). In the inset on the lower left, area shaded red is the South Florida Basin study area.
5

Figure 2. Stratigraphic column for the South Florida Basin study area. Storage assessment units consist of a 

reservoir (red) and regional seal (blue). Modified from Braunstein and others (1988), Pollastro and others (2001), and 

Faulkner and Applegate (1986). 
6

Pre-Punta Gorda SAU C50500101

By Sean T. Brennan

The Pre-Punta Gorda SAU (fig. 3) is an Upper Jurassic to Lower Cretaceous composite 

assessment unit, with storage formations that include the Wood River, Bone Island, Pumpkin Bay, and 

Lehigh Acres Formations, and a seal that is composed of the Punta Gorda Anhydrite (fig. 2). The Upper 

Jurassic Wood River Formation is primarily composed of carbonate-rich deposits; however, the basal 100 

to 150 ft of the formation contains approximately 100 ft of shale and arkosic sandstone (Braunstein and 

others, 1988; Pollastro and others, 2001). The overlying Lower Cretaceous Bone Island and Pumpkin Bay 

formations contain carbonates and evaporite strata and are overlain by the Lehigh Acres Formation 

(Pollastro and others, 2001). The Lehigh Acres Formation is divided into the basal West Felda Shale 

Member, overlain by the Twelve Mile Member and the Able Member. The West Felda Shale Member is a 

regionally persistent calcareous shale that is typically less than 100 ft thick in the South Florida Basin

(Applegate and others, 1981). The Twelve Mile Member is a skeletal limestone (Winston, 1987) and 

contains the informal “Brown Dolomite Zone”, which has hydrocarbon staining (Applegate, 1987; 

Pollastro and others, 2001). The uppermost unit of the Lehigh Acres Formation, the Able Member, is 

composed primarily of anhydritic and argillaceous limestone. These storage formations are overlain by 

the Punta Gorda Anhydrite, the uppermost unit of the Glades Group (fig. 2; Pollastro and others, 2001), 

which is composed mainly of anhydrite, locally interbedded with limestone, dolomite, shale, and more 

rarely halite (Applin and Applin, 1965). The Punta Gorda Anhydrite is a regionally persistent, wedge-like 

unit, with thicknesses ranging from 200 ft in Hillsborough County, Florida to 2,100 ft in the Florida Keys 

(Applin and Applin, 1965). Isopachs of these formations were created using available formation-tops data 

and data interpreted from publically available geophysical logs provided by the Florida Geological Survey 

(IHS, 2010), which were then aggregated to estimate the average total thickness of the composite SAU, 

which ranges from 1,500 to 4,500 ft. 

The extent of the Pre-Punta Gorda SAU, defined by the extent of the Punta Gorda Anhydrite, is

approximately 20,709,000 acres. The depth to the top of the Lehigh Acres Formation is between 8,200 and 

13,000 ft across the entire SAU, with an average depth of approximately 12,000 ft. The few water analyses 

obtained for this composite SAU indicate TDS values between 85,000 and 270,000 mg/L (Breit, 2002). 

These salinity values and the presence of thick evaporite units indicate that water salinity is likely well above 

10,000 mg/L TDS for the entire SAU; therefore, 100 percent of the entire SAU is available for CO2 storage. 

The net-porous interval was determined by calculating a net-to-gross ratio from well logs for each 

unit of the composite SAU. These net-to-gross values were used to modify the isopachs of each formation 

in the composite SAU. These net-porous-thickness isopachs were aggregated into a single net-porous 

isopach for the entire SAU, which indicates an average net-porous thickness that ranges from 100 to 1,500 

ft. Density and neutron porosity values from several wells in the SAU, along with values from literature 

sources (Applin and Applin, 1965; Applegate and others, 1981; Pollastro and others, 2001), were used to 

determine the range of porosity values for the net-porous intervals, which is between 9 and 15 percent. 

Because there is no petroleum production from within the SAU to date, and no published permeability 

values could be identified by the author during the assessment, analog values taken from SAUs identified 

within the Gulf Coast region (Roberts-Ashby and others, 2014) were used. Specifically, the Gulf Coast 

analogs considered during this assessment were the Smackover Formation SAUs (Buursink, 2014); the 

Sligo and Hosston Formations and Cotton Valley Group SAUs (Roberts-Ashby, 2014); the Rodessa

Formation and James Limestone SAUs (Warwick, 2014); and the Washita and Fredericksburg Groups, 

Rusk Formation, and James Limestone SAUs (Brennan, 2014). Using these analogs, the permeability was 

estimated to be between 0.1 and 1,000 millidarcies (mD), with a most likely permeability of 15 mD. The 
7

buoyant trapping pore volume, based on these same analogs, was estimated to be between 0 and 200,000 

million barrels, with a most likely value of 1,420 million barrels.

Figure 3. Map of the U.S. Geological Survey storage assessment unit (SAU) boundaries for the Pre-Punta Gorda 

SAU in the South Florida Basin. Grid cells (one square mile) represent counts of wells derived from ENERDEQ well 

database (IHS Energy Group, 2011) that have penetrated the reservoir-formation top.
8

Sunniland Formation SAU C50500102

By Tina L. Roberts-Ashby

The Lower Cretaceous Sunniland Formation is a predominantly carbonate unit within the South 

Florida Basin that forms a potential CO2 storage reservoir within its petroleum-producing region, known 

as the Sunniland trend (figs. 2 and 4; Applegate and Pontigo, 1984; Roberts-Ashby and Stewart, 2012). 

The Sunniland Formation is composed of shallow-water marine deposits that accumulated on a very 

slowly subsiding platform subjected to cyclic sea level fluctuations, resulting in several carbonateevaporite successions within the formation (Lane, 1994). The Sunniland trend is a slightly arc-like band 

within the South Florida Basin that is ≈145 mi long and 20 mi wide, where oil production activities have 

been concentrated to date within the Sunniland Formation (Applegate and Pontigo, 1984; Roberts-Ashby 

and Stewart, 2012). This region of the Sunniland Formation is also believed to contain the more highly 

porous intervals of the formation, which are composed of mound-like structures (30–100 ft thick) thought 

to be shallow-water bioherms, banks, shoals, and barrier beaches made of coarse fossil fragments

(predominantly rudistids) and various seafloor debris that are located within the middle to upper parts of 

the Sunniland Formation (Mitchell-Tapping, 1986; Lane, 1994; Pollastro, 2001; Roberts-Ashby and 

Stewart, 2012). The basal, or lower, part of the Sunniland Formation is composed of a tight, organic-rich, 

micritic limestone of low porosity and permeability; this section of the formation contains the Sunniland 

Formation petroleum source rocks (Klopp, 1975; Pollastro, 2001). Updip and to the northeast of the 

porous, petroleum-producing trend, the Sunniland Formation thins and is partially replaced by lowporosity dolostone, and the porous bioclastic mounds transition laterally into low-porosity, miliolid-rich 

limestone; downdip and southwest of the trend, the upper section of the Sunniland Formation is composed 

of anhydrite (Grinnell, 1976; Applegate, 1983; Applegate and Pontigo, 1984; Lane, 1994). In the area of 

the potential CO2 storage reservoir, the Sunniland Formation is overlain by the Lower Cretaceous Lake 

Trafford Formation, which is composed of carbonate-evaporite successions of anhydrite; fine dolostone;

and micritic, skeletal limestone (Ferber, 1985; Halley, 1985). The Lake Trafford Formation contains thick 

(>30 ft), confining beds of anhydrite and overall has an average thickness of ≈130–170 ft. The low 

permeability of the overlying Lake Trafford Formation and the lateral decrease in permeability of the 

Sunniland Formation form the regional seal for the Sunniland Formation SAU. 

One potential CO2 storage reservoir is identified within the Sunniland Formation of the South 

Florida Basin that is between 3,000 and 13,000 ft subsurface depth—Sunniland Formation C50500102 SAU 

(fig. 4). The Sunniland Formation SAU encompasses an area of about 3,024,000 acres (+10 percent). 

Although porosity within the Sunniland Formation petroleum reservoir is high, it is not limited to 

the isolated mounds, and the area of porous carbonate within the upper part of the formation is much 

larger than the area containing the producing oil fields (Beinert, 1976; Applegate and Pontigo, 1984;

Mitchell-Tapping, 1987; Lloyd, 1996; Roberts-Ashby and Stewart, 2012). As such, the boundary of the 

Sunniland Formation SAU is not limited to the producing fields but is instead primarily defined by the 

area around the Sunniland trend, where the Sunniland Formation is known to be a porous carbonate

reservoir rock with proven structural and stratigraphic trapping and a thick regional seal consisting of 

anhydrites within the Lake Trafford Formation (Applegate and Pontigo, 1984; Mitchell-Tapping, 1986; 

Lloyd, 1996; Roberts-Ashby and Stewart, 2012). Throughout the extent of the SAU, reservoir-top depths 

are greater than ≈10,000 ft, as seen in approximately 70 geophysical well logs. The rocks within the

Sunniland Formation SAU deepen and thicken to the southwest (Klopp, 1975; Roberts-Ashby and 

Stewart, 2012), and on average are 230 to 270 ft thick, with a most likely thickness of 250 ft, as 

determined from the geophysical well logs. 

Wave erosion common to shallow-water marine environments probably had a winnowing effect 

and created the porous and permeable reservoir carbonates of the Sunniland Formation, whereas in other 
9

areas, porosity within the formation has been enhanced by dolomitization resulting from periods of 

subaerial exposure (Applegate and Pontigo, 1984; Mitchell-Tapping, 1984; Pollastro, 2001). 

Maximum porosities are found within the leached limestone of the Sunniland Formation

(Mitchell-Tapping, 1984); however, porosity continues to be relatively high beyond the isolated mounds 

within the perimeter of the trend (Roberts-Ashby and Stewart, 2012). Average porosity in the porous 

intervals of the Sunniland Formation SAU range from 13 to 14 percent with a most likely porosity of 15 

percent. Net-porous-interval thickness was estimated using geophysical logs for 70 wells located 

throughout the SAU, resulting in an average net-porous-interval thickness that ranges from 60 to 70 ft, 

with a most likely thickness of 65 ft. Average permeability in the Sunniland Formation SAU ranges from 

0.01 to 400 mD, with a most likely permeability of 80 mD (Mitchell-Tapping, 1984; Nehring Associates, 

Inc., 2010). 

Water sampled from six wells within the Sunniland Formation SAU indicates saline formationwaters, with TDS values well above 10,000 mg/L (Breit, 2002). Because groundwater within the 

Sunniland Formation SAU exceeds the 10,000 mg/L TDS lower limit emplaced by the EPA (EPA, 2010), 

100 percent of the SAU is considered to be potentially suitable for geosequestration of CO2.

In order to calculate the maximum buoyant pore volume within structural and stratigraphic 

closures for the Sunniland Formation SAU, the known closure areas from the highly productive regions 

located throughout the SAU were extrapolated and combined with upper bounds on regional reservoir 

thickness and porosity. The known closure areas were calculated by summing petroleum reservoir areas 

for the Sunniland Formation SAU (Nehring Associates, Inc., 2010). An assumption underlying this 

calculation is that there is potential for additional uncharged or undiscovered structural and stratigraphic 

closures outside of regions of historical hydrocarbon production.
10

Figure 4. Map of the U.S. Geological Survey storage assessment unit (SAU) boundaries for the Sunniland 

Formation SAU in the South Florida Basin. Grid cells (one square mile) represent counts of wells derived from 

ENERDEQ well database (IHS Energy Group, 2011) that have penetrated the reservoir-formation top.
11

Gordon Pass and Marco Junction Formations SAU C50500103

By Matthew D. Merrill

The Marco Junction and Gordon Pass Formations are Early Cretaceous Albian-age shallowmarine carbonate and evaporite units in the Big Cypress Group, located in today’s central and southern

Florida (figs. 2 and 5). The sediments were deposited as distal back-reef chalky limestones and micrites 

(Winston, 1976; Amato and others, 1986). Changes in relative sea level in a restricted-marine 

environment increased salinity through evaporation, producing evaporite deposits of gypsum. Those 

gypsum deposits were later altered to anhydrite, and much of the original limestone from this interval has 

been altered to dolostone, the primary reservoir facies in these units. Work by Winston (1976), MitchellTapping (1990), and Randazzo (1997) provide greater details on the depositional environment and postdepositional alteration recorded in these units.

The Gordon Pass and Marco Junction Formations SAU includes much of the onshore and Statewaters extent of these formations (fig. 5). Boundaries extend northward from the Florida Keys to an east–

west line near Tampa Bay. Both the Gordon Pass Formation and down-section Marco Junction Formation 

are reservoirs in this SAU; the seal is a thick regional anhydrite that marks the top of the Gordon Pass

Formation. Interpolation and analysis of evaporite thicknesses from 35 wells were used to determine the 

extent of the seal thickness that is greater than 20 ft. In the northern part of the SAU, the 20-ft minimumseal-thickness line serves as the northern boundary of the assessed area. In the east, south, and west, the 

SAU boundary extends to the State-water line. The SAU has an area of slightly more than 17 million 

acres. Within the SAU, the top of the Gordon Pass Formation reservoir ranges from 7,000 to 10,500 ft 

below the surface (IHS Energy Group, 2011).

Well-log analysis indicates the combined reservoir thickness is 500 to 1,000 ft, and the netporous-interval thickness is 420 to 700 ft, with a most likely thickness of about 525 ft. Geophysical logs 

from wells located within the area of the SAU were used to identify the net-porous intervals, defined in 

this case as carbonate lithology with greater than 5 percent porosity, as inferred from neutron formationdensity porosity logs. Data from the well logs suggest that a majority of the porous intervals are 

composed of dolostone. Lower Cretaceous formations of central and southern Florida, which occur at 

depths significantly deeper than the various aquifers used for potable water, contain water that is highly 

saline (>10,000 mg/L TDS; Breit, 2002); therefore, reservoirs should be available for CO2 sequestration. 

Porosity data from Mitchell-Tapping (1990) indicate that average porosity values for the Dollar Bay 

Formation in the Big Cypress Group, a potential analog for the Gordon Pass and Marco Junction 

Formations (fig. 2), are between 8 and 18 percent; these values are similar to those inferred from well-log 

investigation and are used for this SAU. Analog permeability values, also from the Mitchell-Tapping 

(1990) investigation of the Dollar Bay Formation, span from 0.2 to 200 mD. Currently available maps and 

data reveal that structural features are not readily apparent in the Gordon Pass Formation or Marco 

Junction Formation, but this is assumed to be a result of lack of investigation. Debris mounds and lowrelief reefs like those in the down-section Sunniland Formation are presumed to exist within this SAU;

however, at a lesser magnitude and density. Additionally, research by Roberts-Ashby and Stewart (2012) 

show that porosity in the Sunniland Formation is not restricted to the reef mounds; this assumption has 

been extended to the Marco Junction Formation and Gordon Pass Formation reservoirs for the purposes of 

this assessment.
12

Figure 5. Map of the U.S. Geological Survey storage assessment unit (SAU) boundaries for the Gordon Pass and 

Marco Junction Formations SAU in the South Florida Basin. Grid cells (one square mile) represent counts of wells 

derived from ENERDEQ well database (IHS Energy Group, 2011) that have penetrated the reservoir-formation top.
13

Dollar Bay Formation SAU C50500104

By Matthew D. Merrill

The Lower Cretaceous Dollar Bay Formation (Big Cypress Group) is mainly composed of 

sequences of evaporites and carbonates that were deposited during sea level regressions and 

transgressions; locally they contain thin beds of calcareous shale, mudstones, salt, and lignitic material 

(figs. 2 and 6; Applin and Applin, 1965; Winston, 1971; Mitchell-Tapping, 1990; Pollastro and others, 

2001). In some parts of the basin, the dominant lithology is limestone; however, dolostones produced by 

the variable alteration of these carbonates are potentially the most porous lithology (Pollastro and others, 

2001). Variable dolomitization may be the result of differential cementation and conterminous and 

subsequent periods of changing pore fluid chemistry (Mitchell-Tapping, 1990). The Dollar Bay 

Formation was deposited in a tidal flat depositional environment resulting in mudstones and wackestones 

with intervening anhydrites, all of which overlay the anhydrites of the upper part of Gordon Pass 

Formation (Mitchell-Tapping, 1990), which seal the down-section Gordon Pass and Marco Junction 

Formations SAU C50500103. 

Anhydrite and gypsum beds in the Panther Camp Formation (Naples Bay Group) are the proposed 

seals for the Dollar Bay Formation SAU. The SAU is restricted to a minimum continuous evaporite 

thickness of 20 ft in the Panther Camp Formation. Additional evaporite beds and low-permeability 

dolostone strata in the up-section Rookery Bay Formation could also provide secondary sealing.

Thicknesses were observed through well-log investigation and then interpolated across the potential SAU 

area. Final SAU boundaries extend over much of southern Florida, with a northern boundary crossing 

from west to east: Sarasota, DeSoto, Hardee, Polk, Osceola, and Brevard Counties. The SAU stretches 

south of these counties and terminates along the State-water lines surrounding the Gulf Coast, Florida 

Keys, and Atlantic Coast of the State with an area of 16,085,000 acres (fig. 6).

Well data provided by the Florida Geological Survey and proprietary databases were used to 

determine depths and thicknesses for the SAU. The depth from surface to the reservoir formation in the 

SAU ranges from 7,000 to 10,000 ft (IHS Energy Group, 2011). Total thickness of the Dollar Bay 

Formation was determined from interpolation of well-log interval thicknesses picked from 34 wells. 

Thicknesses range from 200 to 500 ft, with a most likely thickness of 350 ft for the SAU. Analyses of 

neutron formation-density logs to determine the porosity of the reservoir provided potential thicknesses for 

the porous intervals within the total thickness of the formation. Well-log data obtained from nine wells were 

plotted and interpolated in ArcGIS, and histograms of the data layers were used to estimate net-porousinterval thickness resulting in a thickness range of 80 to 200 ft with a most likely thickness of 140 ft.

Porosity and permeability properties for Dollar Bay Formation reservoir rocks (Mitchell-Tapping, 

1990) are the main sources of inputs chosen in this assessment. A likely range of inputs for porosity, 

mainly for porous dolostones, are between 8 and 18 percent. Permeability from the same sample set

ranges from 0.2 to 200 mD. Water quality was not available for the Dollar Bay Formation; however, other 

Big Cypress Group reservoir formations stratigraphically below the Dollar Bay Formation are quite 

saline; data from Breit (2002) indicate that TDS contents of formation-water is over 100,000 mg/L.

Structural data for the reservoir are not widely available; therefore, any potential implications for 

CO2 storage are not clear. As such, it is assumed that the structures and mounds present in the Sunniland 

Formation can serve as a general analog for what may occur in the Dollar Bay Formation. Oil and gas 

production in the Dollar Bay Formation is not currently active at a commercial scale; however, the USGS 

has assessed the formation as a potential source of undiscovered oil and gas resources (Pollastro, 2001; 

Pollastro and others, 2001).
14

Figure 6. Map of the U.S. Geological Survey storage assessment unit (SAU) boundaries for the Dollar Bay 

Formation SAU in the South Florida Basin. Grid cells (one square mile) represent counts of wells derived from 

ENERDEQ well database (IHS Energy Group, 2011) that have penetrated the reservoir-formation top.
15

Cedar Keys and Lawson Formations SAU C50500105

By Tina L. Roberts-Ashby

Carbonate intervals within the Upper Cretaceous Lawson Formation and Paleocene Cedar Keys 

Formation form a potential CO2 storage reservoir within the South Florida Basin that extends throughout 

south-central and southern Florida (figs. 2 and 7), identified here as the Cedar Keys and Lawson 

Formations SAU. The geologic units and reservoir properties of the Cedar Keys and Lawson Formations 

SAU directly correlate with the Cedar Keys/Lawson Injection Zone (CKLIZ) of Roberts-Ashby and 

others (2013). The Lawson Formation is assigned to the Navarroan Provincial Stage of the Upper 

Cretaceous and was deposited on a shallow, partly restricted marine shelf that had little to no terrigenous 

influence (fig. 2; Applin and Applin, 1967; Miller, 1986). Although some authors suggest that the Lawson 

Formation is restricted to the northern regions of Florida and that the Navarroan rocks of southern Florida 

are represented by the chalks of the Pine Key Formation, this author concurs with other researchers who 

have recognized the Lawson Formation throughout the Florida peninsula (Applin and Applin, 1967; 

Kaiser Aluminum and Chemical Corporation, 1971; Roberts-Ashby and others, 2013). The Lawson 

Formation has historically been separated into lower and upper members based upon lithologic and fossilassemblage differences (Applin and Applin, 1967; Miller, 1986). The lower member of the Lawson 

Formation is largely composed of a soft chalk with low permeability and minor amounts of gypsum and 

anhydrite interbedded with thin lenses of chalky dolostone and dolomitic-chalk, mostly in the basal and 

upper portions of the member (Applin and Applin, 1967; Roberts-Ashby and others, 2013). The porosity 

and permeability in the upper member of the Lawson Formation is considerably higher, and in the area of 

the SAU, it is largely composed of an algal and rudistid biostrome that has undergone extensive 

diagenesis (Applin and Applin, 1944, 1967; Kaiser Aluminum and Chemical Corporation, 1971; Miller, 

1986; Winston, 1994). The lithology of the upper member in the area of the SAU is mostly a coarsely 

crystalline dolostone with nodular and interbedded lenses of gypsum and anhydrite (Roberts-Ashby and 

others, 2013). The boundary that separates the two members is gradational, where the dolomitic lenses 

within the upper part of the lower member grade into the dolostones found in the basal part of the upper 

member (Roberts-Ashby and others, 2013). The Cedar Keys Formation overlies the Lawson Formation 

and is assigned to the Midwayan Provincial Stage of the Paleocene (fig. 2). The Cedar Keys Formation is 

a thick anhydrite and dolostone sequence thought to have been deposited in a regionally extensive tidal 

flat environment that had intermittent periods of open-marine conditions during the Paleocene, possibly 

continuing into the Eocene (Applin and Applin, 1967; Miller, 1986; Winston, 1995; Pollastro and others, 

2001). Winston (1994) divides the Cedar Keys Formation into six subunits (units A–F) based on a 

detailed evaluation of anhydrite content; however, for this assessment, the Cedar Keys Formation was 

evaluated in a more simplified manner following that proposed in Roberts-Ashby and others (2013) for 

the CKLIZ, which presents three informal subunits: lower, middle, and upper Cedar Keys Formation.

Within the area of the Cedar Keys and Lawson Formations SAU and the CKLIZ, the lower part of the 

Cedar Keys Formation is a porous dolostone with some thin interbedded and nodular anhydrite that has a 

porosity of at least 10 percent (Miller, 1986; Roberts-Ashby and others, 2013); this section of the Cedar 

Keys Formation forms the upper part of the porous reservoir interval within the Cedar Keys and Lawson 

Formations SAU and CKLIZ, as defined by Roberts-Ashby and others (2013). Within the confines of the 

SAU and CKLIZ, the middle Cedar Keys Formation is the section directly overlying the porous dolostone 

of the lower part of Cedar Keys Formation that consists of one or more thick (on average 650–985 ft) and 

laterally extensive anhydrite layers (Roberts-Ashby and others, 2013) that form a robust regional seal for 

CO2 storage. The upper part of the Cedar Keys Formation is a porous, carbonate, reservoir-like interval 

that is not included in the Cedar Keys and Lawson Formation SAU or CKLIZ (fig. 2; Miller, 1986; 

Roberts-Ashby and others, 2013).
16

One potential CO2 storage reservoir is identified within the Lawson and Cedar Keys Formations of 

the South Florida Basin between 3,000 and 13,000 ft subsurface depth—Cedar Keys and Lawson 

Formations SAU C50500105 (fig. 7). The Cedar Keys and Lawson Formations SAU encompasses an area 

of about 22,454,000 acres (+10 percent), which is slightly larger than the area defined for the CKLIZ due 

to the fact that the SAU boundary for this assessment extends all the way to the State-water boundary, and 

the CKLIZ study area did not. 

The boundary of the Cedar Keys and Lawson Formations SAU is defined by the 3,000-ft and 

13,000-ft reservoir-top depths interpreted from geophysical logs for more than 100 wells, and the 

presence of a thick (>50 ft) anhydrite seal within the middle Cedar Keys Formation (Roberts-Ashby and 

others, 2013). The rocks within the Cedar Keys and Lawson Formations SAU deepen to the south and 

southwest and on average are 500 to 800 ft thick with a most likely thickness of 700 ft, as determined 

from geophysical logs for over 100 wells (Roberts-Ashby and others, 2013).

Secondary, intercrystalline porosity dominates the upper member of the Lawson Formation and 

lower Cedar Keys Formation; however, some primary interparticle and intraparticle porosity is present 

within thin, localized limestone intervals of these units (Applin and Applin, 1944, 1967; Kaiser

Aluminum and Chemical Corporation, 1971; Miller, 1986; Winston, 1994; Roberts-Ashby and others, 

2013). Average porosity in the porous intervals of the Cedar Keys and Lawson Formations SAU ranges 

from 21 to 25 percent with a most likely porosity of 23 percent. Net-porous-interval thickness was 

estimated from geophysical logs for more than 100 wells resulting in an average net-porous-interval

thickness that ranges from 160 to 240 ft, with a most likely value of 220 ft (Roberts-Ashby and others, 

2013). Average permeability in the Cedar Keys and Lawson Formations SAU ranges from 0.1 to 430 mD, 

with a most likely permeability of 100 mD (Hickey and Wilson, 1982; Okwen, 2009).

The Cedar Keys and Lawson Formations serve as reservoirs for wastewater disposal, typically 

nonhazardous industrial or municipal waste, which is permitted by the Florida Department of 

Environmental Protection Underground Injection Control (UIC) program (Hickey and Wilson, 1982; 

Tampa Electric, 2011). Water sampled from wells that penetrate the Cedar Keys and Lawson Formations 

SAU indicate saline formation waters, with TDS values well above 10,000 mg/L (Hickey and Wilson, 

1982; Breit, 2002). Because groundwater within the Cedar Keys and Lawson Formations SAU does not

fall below the 10,000 mg/L TDS lower limit emplaced by the EPA (EPA, 2010), 100 percent of the SAU 

is considered to be potentially suitable for geosequestration of CO2.

In order to calculate the maximum buoyant pore volume within structural and stratigraphic 

closures for the Cedar Keys and Lawson Formations SAU, upper bounds on regional reservoir thickness 

and porosity were used along with the Sunniland Formation SAU analog.
17

Figure 7. Map of the U.S. Geological Survey storage assessment unit (SAU) boundaries for the Cedar Keys and 

Lawson Formations SAU in the South Florida Basin. Grid cells (one square mile) represent counts of wells derived 

from ENERDEQ well database (IHS Energy Group, 2011) that have penetrated the reservoir-formation top.
18

Acknowledgments

The authors thank Paul G. Schruben and Brian Verela, who helped to compile and process the 

drilling and hydrocarbon production data for the region, and Troy A. Cook, Mahendra K. Verma, and 

Hossein Jahediesfanjani, who helped to interpret the petroleum engineering data. The authors also thank 

Rodney DeHan, Andy Smith, Alan Baker, Dave Taylor, and others at the Florida Geological Survey for 

their gracious time and effort in supplying geologic information on Florida, which greatly aided this 

assessment. The content and presentation of this report benefited greatly from the technical reviews of

Guy “Harley” Means and Kevin Cunningham.

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