U.S. DEPARTMENT OF THE INTERIOR

U.S. GEOLOGICAL SURVEY

Lambert Conformal Conical Projection

Units: Meters, Standard Parallels: 33 00 00, 45 00 00

Meridian: −94 00 00, Latitude of Origin: 29 00 00

False Easting: 0, False Northing: 0

Original data accurate at scale of 1:500,000.

Digital base from U.S. Geological Survey.

Manuscript approved for publication July 7, 1995
OIL AND GAS INVESTIGATIONS

MAP 0M−226
1

U.S. DEPARTMENT OF THE INTERIOR OIL AND GAS INVESTIGATIONS

U.S. GEOLOGICAL SURVEY MAP OM–226

PAMPHLET

MAPS SHOWING HYDROCARBON PLAYS OF THE FLORIDA PENINSULA,

USGS PETROLEUM PROVINCE 50

By

Richard M. Pollastro and Roland J. Viger

1998

PROVINCE INTRODUCTION AND

GEOLOGIC SUMMARY

The Florida Peninsula, USGS petroleum

Province 50 as defined by the 1995 USGS

National Oil and Gas Assessment (Gautier and

others, 1995), includes all of the State of Florida

east of the Apalachicola River, and the adjoining

State waters; the part of the Florida Panhandle

west of the Apalachicola River is part of USGS

petroleum Province 49 (Mississippi-Louisiana Salt

Basin). The Apalachicola River generally trends

north-south, separating Gadsden, Liberty, and

Franklin Counties on the east from Jackson,

Calhoun, and Gulf Counties on the west. USGS

petroleum Province 50 (hereafter referred to as

Province 50), inclusive of State waters, is

approximately 150 mi wide and about 400 mi

long, totaling about 70,000 mi2. It is bounded to

the north by the State boundary with Georgia and

to the east, south, and southwest by the

boundaries of the Florida State waters. The State

water boundaries extend to 3 leagues (10.36

statute miles) on the Gulf of Mexico side of Florida

and to 3 mi on the Atlantic Ocean side (the GulfAtlantic boundary line runs westward from the

Marquesas Keys along latitude 24°35' N. and then

turns southward, just west of the Dry Tortugas,

along longitude 83° W.).

The most prominent positive structural

element within the province is the Peninsular arch,

which is a crystalline basement high plunging

south-southeast along the axis of the Florida

Peninsula (map A). Other smaller positive

structural elements generally define the boundaries

of the associated South Florida basin, the

Apalachicola embayment, and the Southeast

Georgia embayment (map A). The South Florida

basin is the most prominent of these features and

has the greatest petroleum potential.

The South Florida basin is a structurally

simple basin containing 25,000 ft or more of

sediment in the apparent depocenter that lies

northwest of the Florida Keys under present-day

Florida Bay. Sedimentation in the South Florida

basin kept pace with subsidence, producing nearly

continuous carbonate-evaporite deposition from

the Jurassic(?) to the present (fig. 1). The South

Florida basin covers some 50,000 mi2 and

incorporates the southernmost one-third or more

of the peninsula of Florida including the Florida

Keys and the easternmost Gulf of Mexico.

Onshore, the basin exhibits only subtle structures

with no major faults or vertical fractures.

However, more complex structural elements are

believed to exist in the offshore part of the basin,

which, if present, may provide excellent potential

for hydrocarbon accumulations. The basin has a

generally low (~1.0°F/100 ft) geothermal gradient;

however, the gradient of some onshore oil fields

may reach 1.5°F/100 ft.

The Southeast Georgia embayment in the

northeastern part of the province contains as

much as 6,000 ft of sedimentary rock. Because

this area contains only shallow, thermally

immature sequences and lacks potential petroleum

source rocks, its potential for undiscovered

petroleum resources is estimated as slight. The

Apalachicola embayment in the northwestern part

of the province, however, has petroleum potential

in the Jurassic Smackover Formation, which

produces in the Florida Panhandle in Province 49.

Six conventional hydrocarbon plays are

defined for Province 50. These plays were

developed for the 1995 USGS National Oil and

Gas Assessment (Gautier and others, 1995). Two

plays are confirmed: Upper Sunniland Tidal Shoal

Oil play (5001) and Lower Sunniland Fractured

Dark Carbonate Oil play (5002). The other four

are hypothetical: Dollar Bay Shoal-Reef Dolomite

Oil play (5003), Lower Cretaceous Carbonate

Composite Oil play (5004), Extended Upper

Sunniland Tidal Shoal Oil play (5005), and Wood

River Dolomite Deep Gas play (5006). The

easternmost part of the Smackover

Alabama/Florida Updip Oil play (4911) also

extends into Province 50 but has been assigned to

Province 49; therefore, this play is not shown or

defined here.
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EXPLORATION CELLS AND

FIELD OUTLINES

Each cell on the maps represents 0.25 mi2

in which exploration has taken place. Cell data

from this map were summarized from the

December 1993 version of the Well History

Control System of Petroleum Information, Inc. of

Houston, Texas. Solid green squares indicate

explored cells with oil production; solid blue

squares indicate explored cells, but no

hydrocarbon production. Field outlines were

established from a variety of sources including: (1)

the exploration cells and (2) well data, structure

contour maps, and oil/water contact maps

published by the Florida Geological Survey (Lloyd,

1991).

PLAY DESCRIPTIONS

MAP A. UPPER SUNNILAND TIDAL SHOAL

OIL PLAY (5001)

Known only in the subsurface, the Lower

Cretaceous Sunniland Formation is the basal unit

of the Ocean Reef Group (fig. 1). Onshore, the

formation is relatively uniform in thickness and

consists of limestone, dolomite, and anhydrite.

The upper part of the Sunniland Formation

produces heavy, marginally-mature crude oils

onshore from porous bioclastic debris mounds,

banks, and pods on the eastern margin of the

South Florida basin. The region of productive

reservoir facies of the upper Sunniland Formation

is defined in part by eight fields that have produced

more than one million barrels of oil (MMBO) and

five smaller fields; most of the smaller fields are

abandoned or shut in. Combined, these fields

form an arcuate northwest-southeast trend, the

“Sunniland trend,” which is about 20 mi wide and

150 mi long. Generally, the updip limit of the

Sunniland varies from about 50 to 60 mi northeast

of the producing trend. The first upper Sunniland

oil field discovery was the Sunniland field in 1943;

the largest is the West Felda field, discovered in

1966, with total production through July 1993 of

over 44 MMBO. Cumulative production for all

upper Sunniland Formation reservoirs through July

1993 was about 100 MMBO.

The northern and updip play boundary for

the Upper Sunniland Tidal Shoal Oil play (5001) is

defined here by an area in which the upper

Sunniland consists of only micritic limestone and

contains no reservoir mounds within its intertidal,

lagoonal-mudflat facies. Moreover, the lower part

of the Sunniland dark carbonate source rocks is

also absent. The downdip southern boundary of

the play is limited by an area where wells identify

an anhydrite-cemented, nonporous, sabkha-like

facies.

The existing reservoir facies in the upper

Sunniland Formation consist mostly of isolated

fossil-shell hash (skeletal grainstones). These

bioclastic buildups represent probable storm

deposition as shoals in a regionally restricted,

back-reef lagoonal area in the warm, shallow

marine shelf setting of the eastern South Florida

basin during the late Early Cretaceous (MitchellTapping, 1984, 1987). These tidal shoals were

deposited on subtle bathymetric highs probably

related to underlying basement structure. Later,

the upper parts of these porous shoal mounds

were subaerially exposed, leached, and dolomitized

during a low sea-level stand, further enhancing the

reservoir quality of the upper porous zones.

Individual debris mounds vary in thickness between

about 40 and 100 ft (Means, 1977; Montgomery,

1987). Depth to the upper Sunniland tidal shoal

reservoirs in the producing trend is from about

11,200 to 11,600 ft. Most mounds are sealed by

overlying impermeable lagoonal mudstones and

wackestones, some of which have been

dolomitized. Porosities of primary (interparticle)

and secondary (dissolution and dolomitization)

origin range from 10 to 25 percent and average

15–18 percent (Mitchell-Tapping, 1984, 1987).

Impermeable micritic carbonate and nodular

anhydrite beds within the upper Sunniland enclose

and seal many of the individual porous reservoir

mounds. Moreover, the entire Sunniland

Formation is sealed above and below by thick

anhydrite units (fig. 1). Most hydrocarbon traps are

stratigraphic; however, some mixed

stratigraphic/structural traps have been

recognized.

Oils produced from the upper Sunniland

grainstones are immature, having API gravities

that range from about 21° to 28° and average

25°–26°; on average, the gas-to-oil ratio (GOR) is

about 85 (Palacas, 1984; Palacas and others,

1984; Tootle, 1991). The source rocks are a

dark, micritic carbonate unit (informally referred to

as the dark carbonate interval) in the lower part of

the Sunniland Formation. These micritic

carbonates are commonly algal laminated and

have total organic carbon (TOC) ranging from

<0.4 to 3.0 weight percent. Potential source

rocks (as identified by >0.4 weight percent TOC)

average 1.8 weight percent TOC. Greater than

80 percent of the organic matter within these

source rocks is composed of algal-amorphous (oilprone) kerogen (Palacas and others, 1984). The

hydrocarbon-generating potential of the lower

Sunniland dark carbonate facies ranges from poor

in wells updip from the producing trend to good

just downdip to excellent near the depocenter of
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the basin (Applegate and Pontigo, 1984).

Onshore, the dark carbonate facies varies in

thickness from zero at the updip limit of the

Sunniland to >150 ft in the producing trend. Oil

produced from reservoirs in the Sunniland trend

was probably generated downdip where the

organic matter in the dark carbonate facies is

richer and more mature. The petroleum then

migrated updip and accumulated in the porous

grainstone facies of the upper Sunniland (Palacas

and others, 1984).

Exploration and development of the upper

Sunniland Formation has been minimal based on

the drilling history and well distribution within the

play area, which is shown by the limited number of

explored cells on the maps. The eight upper

Sunniland fields containing >1 MMBO are Bear

Island, Corkscrew, West Felda, Lehigh Park, MidFelda, Raccoon Point, Sunniland, and SunocoFelda (see map A for outlines and locations). At

least three of these eight fields are located in the

Big Cypress Swamp drainage and (or) National

Reserve, an area of critical environmental concern

(Lloyd, 1991). Factors such as environmental and

political concerns and the present oil prices

probably have discouraged full resource

development. Minimal exploration and

development of petroleum resources because of

these factors, coupled with the success of wells

drilled in the past few decades, indicate that the

Upper Sunniland Tidal Shoal Oil play has good

potential for undiscovered oil accumulations of

moderate size.

MAP A. EXTENDED UPPER SUNNILAND

TIDAL SHOAL OIL PLAY (5005)

This hypothetical play is an extension to the

east and south of the productive Sunniland trend

in the Upper Sunniland Tidal Shoal Oil play

(5001). Thus, reservoirs and source rocks are the

same as those for play 5001. Shown on map A,

this play forms a southwest-to-northeast arcuate

trend approximately 20 mi wide and 250 mi long

from the State waters of the Dry Tortugas

northeast through the Florida Keys and along the

southeastern Atlantic Coast of the Florida

Peninsula to Broward County. Bioclastic mounds

of smaller size than those in currently productive

units from the upper part of the Sunniland

Formation accumulated on subtle structural highs

in this updip, less thermally mature area of the

basin to the east and far south. Prominent positive

structural elements include the Pine Key arch and

the Largo high. Some heavy oil shows having low

API gravity (10°–14°) have been reported in wells

in the northern part of the play area; however,

22° API gravity oil was reported in shows from

wells near the Marquesas Keys in the west and

southernmost part of the play area (Faulkner and

Applegate, 1986; Lloyd, 1991).

The Extended Upper Sunniland Tidal Shoal

Oil play (5005) is delineated by an area of

suspected porous tidal-shoal facies forming on

topographic/bathymetric highs. The dark

carbonate source unit in the lower part of the

Sunniland Formation thins toward the east and

south margins of the basin south of the play area,

making it less favorable than the proven Upper

Sunniland Tidal Shoal Oil play (5001). The

Sunniland in this area is also less thermally mature

than in play 5001. The eastern and southern

Atlantic coastal boundaries of the play are

determined by the 3-mi line, and the northern,

Gulf of Mexico boundary by the 3-league (10.36

mi) Florida State waters boundary.

MAP B. LOWER SUNNILAND FRACTURED

DARK CARBONATE OIL PLAY (5002)

The Lower Sunniland Fractured Dark

Carbonate Oil play is based solely on the discovery

of the Lake Trafford field in Collier County. The

Lake Trafford field (shown on map A) is

represented on maps A–E by one productive cell.

The dark carbonate unit of the lower part of the

Sunniland Formation is believed to contain the

primary source beds for oils produced in the tidal

shoal grainstones of the upper part of the

Sunniland Formation (plays 5001 and 5005).

Although no oil accumulations are proven of

minimum (>1 MMBO) size, the one discovery well

(Mobil Oil Corporation) defining the Lake Trafford

field has produced commercial quantities of oil

since its discovery in March 1969, from fractured

limestone at a depth of about 11,800 ft. The

producing zone is commonly referred to as the

rubble zone of the dark carbonate unit in the lower

Sunniland Formation (Means, 1977). The matrix

porosity of the producing zone, as measured by

well logs, is about 9 volume percent, and the pore

space is oil saturated. Core of the rubble zone

from the discovery well has been described as

burrowed, fractured, and stylolitized (Lloyd, 1991);

these characteristics are thought to be responsible

for enhancing the porosity and permeability for

commercial production. In March 1988, the

discovery well was shut in after oil production

totaled about 278,000 barrels. Two offset vertical

wells, located to the northwest and south of the

producing well, and a recent horizontal test well

were dry holes. Based on the production history

of the one vertical well, horizontal wells

penetrating the rubble zone of the dark carbonate

unit could potentially produce a few hundred

barrels of oil per day (BOPD). Owner/operator
4

Brian Richter (oral commun., 1994) reports that

the horizontal test missed the targeted pay zone.

The play boundary is defined by thickness

(>60 ft) of the dark carbonate unit, as partly

determined from cross sections and isopachs

(Applegate and Pontigo, 1984), and from offshore

well summaries of Lloyd (1991). In addition to

thickness, the area defined for the Lower

Sunniland Fractured Dark Carbonate Oil play was

further delineated from reference wells having a

combination of good source-rock qualities and

evidence of either the rubble zone or some

fracturing present (Montgomery, 1987). This play

is assigned fair potential for undiscovered oil

resources. The most favorable part of the play is

in an area northwest of the Lake Trafford field.

Expected depths of production within the play

area are estimated between 10,000 and 13,000

ft, with a median depth of about 11,800 ft.

Potentially productive fractured reservoirs are

within the lower dark carbonate zone of the lower

Sunniland and are enclosed by impermeable,

micritic, tidal flat, lime mudstones. The unit is

sealed below by the Punta Gorda Anhydrite.

Indigenous hydrocarbons are produced from

brown and medium-dark-gray micritic and

argillaceous limestones with total carbonate

content averaging 76 weight percent, and ranging

from 50 to 98 weight percent. These micritic

carbonates are commonly algal laminated and

have TOC ranging from <0.4 to 3.0 weight

percent. Potential source beds (>0.4 weight

percent TOC) within the unit average about 1.8

weight percent TOC. Oil produced from the one

well at the Lake Trafford field has an API gravity

of about 26°, similar to the oil in the upper

Sunniland producers (API gravities ranging from

21° to 28°). Inasmuch as oils in the upper

Sunniland are derived from sources in the lower

dark carbonate, the similarity in API gravities is

expected. Similarly, lower Sunniland oils are

expected to have a GOR range of that of upper

Sunniland oils from about 80 to 100.

MAP C. DOLLAR BAY SHOAL-REEF

DOLOMITE OIL PLAY (5003)

The hypothetical Dollar Bay Shoal-Reef

Dolomite Oil play is based on (1) interpretations of

well-log data from a series of onshore wells

reporting numerous shows (Winston, 1971) and

(2) the paleoenvironmental reconstructions of

Winston (1971) and Mitchell-Tapping (1990) of

the reservoir tidal shoal and patch reef facies; the

data of Faulkner and Applegate (1986) were also

used in the definition of this play.

The youngest formation in the onshore

portion of the South Florida basin that shows

characteristics favorable for petroleum generation

and accumulation is the Lower Cretaceous Dollar

Bay Formation, the uppermost unit of the Big

Cypress Group (fig. 1). The unit lies about 1,500

ft or more above the Sunniland Formation and is

as much as 620 ft thick in some parts of the basin.

Onshore, the unit ranges in thickness from about

475 to 550 ft. Many wells penetrating the Dollar

Bay Formation in south Florida have reported

low-gravity (~17° API) oil shows or tarry residues

in both limestone biohermal deposits and an upper

dolomite section; however, no commercial

production has occurred from this play. Like the

Sunniland Formation, the Dollar Bay commonly

consists of evaporite-carbonate cycles of

anhydrites, dolomites, and limestones. These

evaporite-carbonate beds formed during a

transgressive-regressive cycle; some thin beds of

calcareous shale, salt, and lignite are also present

(Applin and Applin, 1965; Mitchell-Tapping,

1990). In certain areas of the basin, however,

limestone is the predominant lithology of the

formation. Speculative production in the Dollar

Bay Formation will be from leached limestones in

the middle part of the formation, or from a

dolomite section in the upper part.

Reservoirs are believed by Mitchell-Tapping

(1990) to exist in tidal shoal deposits and patch

reefs in a tidal flat, lagoonal, restricted-marine

setting, and in a subtidal platform, open-marine

setting. Potential reservoirs include (1) porous,

leached, and dolomitized grainstones in the upper

parts of isolated debris mounds, (2) isolated patch

reefs in the middle part of the Dollar Bay

Formation, and (3) a porous dolomite in the upper

part (Mitchell-Tapping, 1990). These potential

reservoirs have measured porosities ranging from

about 10 to 30 percent and permeabilities on the

order of 5–60 millidarcies (mD). Traps are created

because these reservoirs are draped with

impermeable, micritic, tidal flat deposits, and in

some cases argillaceous lime mudstones and

anhydrite. The formation is underlain by thick,

dense, nodular and nodular-mosaic anhydrites of

the Gordon Pass Formation.

Oil and tarry residues recorded in Dollar Bay

wells are believed to originate within the formation

(Palacas, 1978a, b; Winston, 1971). The organicmatter content of the Dollar Bay Formation ranges

from very lean to fairly rich, with some beds

containing more than 3 weight percent TOC; the

average TOC of the Dollar Bay is about 0.6

weight percent (Palacas, 1978a, b). Most

petroleum explorationists infer that the Dollar Bay

Formation located updip and to the northeast of

the Sunniland trend is thermally immature and has

probably not generated hydrocarbons of

commercial quality and quantity (Montgomery,
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1987). Others strongly disagree, however, and

predict that the Dollar Bay Formation has been

overlooked and should be a considered a primary

oil target with good potential (Winston, 1971;

Palacas, 1978a, b; Mitchell-Tapping, 1990).

Offshore, in the more central part of the

basin where the Dollar Bay lies at depths >10,000

ft, the formation should be more thermally mature.

Based on one major show, which consisted of 15

ft of free oil, API gravity measured 17° at a depth

of about 10,000 ft . Thus, API gravities of oil

from this play are expected to be low, probably

ranging from 15° to 20° (Mitchell-Tapping, 1990).

Sulfur contents are similar to those of Sunnilandtype oils (2–4 percent). Moreover, the inferred

presence of patch reefs and more complex

structures in the Federal offshore, and increased

thermal maturity for the Dollar Bay in the offshore

part of the basin, enhances the potential for new

field discoveries and commercial oil production.

MAP D. LOWER CRETACEOUS CARBONATE

COMPOSITE OIL PLAY (5004)

The hypothetical Lower Cretaceous

Carbonate Composite Oil play comprises two units

in the South Florida basin: the brown dolomite

zone of the Twelve Mile Member of the Lehigh

Acres Formation, and a potentially porous

dolomite unit within the underlying Pumpkin Bay

Formation (fig. 1). Both units in this play are

believed to contain oil derived mainly from

organic-rich beds in the upper part of the Pumpkin

Bay Formation.

The extent of the play is delineated by two

separate areas: one centered in Lee County and

intersecting the Sunniland trend, and the other

centered near the Marquesas Keys. The northern

area (Lee County and vicinity) includes the area

outlined by Applegate (1987) of the porous brown

dolomite and the area within the Pumpkin Bay

Formation shown to contain live oil in porous

dolomite (6–16 percent porosity). The section is

the thickest (as much as 1,200 ft thick) in these

areas, as measured from reference wells in State

waters near Charlotte Harbor and onshore in

Collier and Hendry Counties, and has good to

excellent source-rock potential from geochemical

and thermal maturity measurements (Means,

1977; Applegate and others, 1981; Palacas and

others, 1981; Attilio and Blake, 1983; Faulkner

and Applegate, 1986; Applegate, 1987;

Montgomery, 1987). The northern segment also

corresponds to an area of brown dolomite where

high porosity is caused by epigenic dolomitization

from an active geothermal lineament system (Saul,

1987). Several oil shows are reported in thick,

porous dolomite sections in the southern segment

of the play area (Faulkner and Applegate, 1986;

Lloyd, 1991).

The informally named brown dolomite zone

refers to a dolomite unit commonly found within

the Twelve Mile Member of the Lower Cretaceous

Lehigh Acres Formation (Aptian). The brown

dolomite lies about 300 ft below the base of the

Punta Gorda Anhydrite and about 1,000 ft below

the Sunniland Formation (fig. 1). The unit is best

developed where thickest (~100 ft) and most

porous (10–22 percent) onshore in Charlotte

County and surrounding counties at a depth of

about 12,000 ft . Good oil shows are reported,

and because it is about 1,000 ft lower in the

stratigraphic section than the Sunniland

Formation, oils from the brown dolomite are

predicted to have higher API gravity (20°–50°?)

and thermal maturity than Sunniland oils.

Reservoir rocks consist of sucrosic dolomite

and exhibit pinpoint to vuggy porosity in beds

found at least 50 ft below the top of the Twelve

Mile Member of the Lehigh Acres Formation. As

much as 50 ft of porous dolomite has been found

onshore where the brown dolomite zone reaches a

maximum thickness of about 100 ft. An area

having highest potential onshore is defined mostly

by the porous zones shown by Applegate (1987)

in Charlotte, Lee, Hendry, Collier, Highlands, and

Glades Counties and adjacent State waters. Good

oil shows were observed in the Bass Collier 12-2

well in Collier County in dolomite having sonic

well-log porosities ranging from 10 to 22 percent

and core porosities as high as 18 volume percent.

Good potential is also predicted offshore in both

State and Federal waters. In particular, oil stains

were noted in wells where about 350 ft of mostly

porous dolomite has been penetrated near the

Marquesas Keys (Faulkner and Applegate, 1986;

Lloyd, 1991).

The thickest and deepest interval in the

South Florida basin with significant reservoir

potential is the Lower Cretaceous Pumpkin Bay

Formation. The formation is mostly limestone

except at its northern limit, where it has been

found to be mostly dolomite. Within Province 50,

the Pumpkin Bay is as thick as 1,200 ft in offshore

Florida State waters of Charlotte Harbor; the

formation is projected to thicken westward in the

Federal offshore and into the basin depocenter

(Faulkner and Applegate, 1986). Onshore, the

Pumpkin Bay Formation is found at depths from

about 12,500 to 14,000 ft. Core porosities for

the Pumpkin Bay are as high as about 20 percent,

and its sonic well-log porosities measure slightly

higher. Porosities are generally lower in the

Pumpkin Bay Formation than in potential

reservoirs found in younger units. Generally, the

best potential for the Pumpkin Bay Formation is
6

predicted in the Pulley Ridge area of Federal

offshore waters in the Gulf of Mexico (Faulkner

and Applegate, 1986). Projections suggest that

the formation is as much as 1,500 ft thick in this

area and that good reservoirs exist within a thick

porous dolomite zone (300–350 ft thick; pinpoint

to vuggy porosity as great as 25 percent) in the

middle to upper part of the formation, at depths

from about 12,500 to >15,000 ft.

Source-rock studies by Palacas and others

(1981) suggest that organic rich beds in the upper

Pumpkin Bay Formation are likely source rocks for

oils that could be reservoired both within the

middle and upper part of the Pumpkin Bay and in

the porous brown dolomite zone. Palacas and

others (1981) identified organic-rich, argillaceous

carbonate beds with high (0.43–3.2 weight

percent) TOC in the upper Pumpkin Bay and

concluded that these beds had the greatest

petroleum-generating potential of all rocks older

than the Punta Gorda Anhydrite.

The TOC contents of these rocks, however,

varies within the basin. Most rocks within the

Twelve Mile Member of the Lehigh Acres

Formation contain insufficient organic matter

(average ~0.3 percent TOC) to have generated

commercial amounts of petroleum. Some richer

source beds occur within this unit, however, having

marginal (~0.5 percent TOC) to good source

potential. Particularly, greater than 2.0 percent

TOC is contained in a relatively thin (~1 ft thick)

limestone bed in the West Felda field.

The thermal maturation level for oil

generation is greater in this play than that for the

upper and lower Sunniland plays (5001 and

5002). Thus, oils of this play are expected to be

marginally to moderately mature and to have

higher API gravities (25°–50°) and higher GOR

than Sunniland oils.

MAP E. WOOD RIVER DOLOMITE

DEEP GAS PLAY (5006)

In the hypothetical Wood River Dolomite

Deep Gas play, the Upper Jurassic(?) and Lower

Cretaceous Wood River Formation averages about

1,700 ft thick and is the lowest sedimentary unit in

the South Florida basin (fig. 1). The few wells that

have penetrated this formation show that a 100-

to 150-ft-thick clastic unit forms the basal part of

the Wood River Formation and consists of darkred shale and fine- to coarse-grained arkosic

sandstone and calcareous sandstone (Applegate

and others, 1981). These basal clastics possibly

represent fan, fan-delta, and fluvial-lacustrine or

marine deposits. Below the basal clastic sequence

in Collier County is a rhyolite porphyry with an

age of 189 Ma. Overlying these clastic rocks is a

thick sequence of anhydrite, dolomite, and

limestone with occasional interbedded salt

stringers, indicating marine transgression

(Applegate and others, 1981).

One well, the Mobil-Phillips Seminole C in

Hendry County, produced measurable gas and

water flows at depths of about 15,700 ft from

perforations in a dolomite zone averaging about 8

percent porosity. Moreover, logs from the well

indicated higher porosities and increased

resistivities just above the perforated section,

possibly indicating the presence of gas (Applegate

and others, 1981; Palacas and others, 1981).

Although formation damage occurred in the well

bore, this well had potential for commercial gas

production (J.G. Palacas, oral commun., 1994)

and the occurrence of a potentially commercial

well indicates a possible source of deep gas.

Marine beds, generally regarded as potential

petroleum sources, are predominant, and the

depositional environment, especially in the

southern areas, probably favored reef growth; thus

a source, a seal, and a reservoir should be present.

Organic geochemistry studies of well

samples from the Wood River Formation indicate

that the hydrocarbon-generating potential of the

unit ranges from poor to excellent (Palacas and

others, 1981; Faulkner and Applegate, 1986).

The scarcity of wells penetrating the Wood River

Formation, however, makes any evaluation

inconclusive. Potential reservoirs in the Wood

River are porous (8 percent or greater) dolomites

enclosed by anhydrite, salt stringers, and (or)

micritic limestone at depths from about 15,000 to

19,000 ft onshore and in State waters. The play

area includes areas of the southern part of the

basin where reef growth is favored. It is possible

that gas in the Wood River in the area of the

Sunniland trend may have originated in deeper

parts of the basin and migrated updip, perhaps as

a single, large accumulation.

REFERENCES CITED

Applegate, A.V., 1987, Part II—The Brown

Dolomite zone of the Lehigh Acres

Formation (Aptian) in the South Florida

basin—A potentially prolific producing

horizon offshore: Florida Geological

Survey Information Circular No. 104, pt.

2, p. 46–66.

Applegate, A.V., and Pontigo, F.A., Jr., 1984,

Stratigraphy and oil potential of the Lower

Cretaceous Sunniland Formation in south

Florida: Florida Bureau of Geology

Report of Investigations No. 89, 40 p.

Applegate, A.V., Winston, G.O., and Palacas,

J.G., 1981, Subdivision and regional
7

stratigraphy of the pre-Punta Gorda rocks

(lowermost Cretaceous–Jurassic?) in South

Florida: Gulf Coast Association of

Geological Societies Transactions, v. 31,

p. 447–453.

Applin, P.L., and Applin, E.R., 1965, The

Comanche Series and associated rocks in

the sub-surface in central and south

Florida: U.S. Geological Survey

Professional Paper 447, 84 p.

Attilio, D.E., and Blake, Bruce, 1983, Petroleum

potential, exploration possibilities of South

Florida basin, Florida Keys: Oil and Gas

Journal, v. 81, p. 148–153.

Faulkner, B.M., and Applegate, A.V., 1986,

Hydrocarbon exploration evaluation of

Pulley Ridge area, offshore South Florida

basin: Gulf Coast Association of

Geological Societies Transactions, v. 36,

p. 83–95.

Gautier, D.L., Dolton, G.L., Takahashi, K.I., and

Varnes, K.L., eds., 1995, 1995 National

assessment of United States oil and gas

resources—Results, methodology, and

supporting data: U.S. Geological Survey

Digital Data Series DDS–30, one CDROM.

Lloyd, J. M., 1991, 1988 and 1989 Florida

petroleum production and exploration:

Florida Geological Survey Information

Circular No. 107, p. 1–62.

Means, J.A., 1977, Southern Florida needs

another look: Oil and Gas Journal, v. 75,

no. 5, p. 212–225.

Mitchell-Tapping, H.J., 1984, Petrology and

depositional environment of the Sunniland

producing fields of south Florida: Gulf

Coast Association of Geological Societies

Transactions, v. 34, p. 157–173.

———1987, Application of the tidal mudflat

model to the Sunniland Formation of

South Florida: Gulf Coast Association of

Geological Societies Transactions, v. 37,

p. 415–426.

———1990, New oil exploration play in Florida—

The upper Fredericksburg Dollar Bay

Formation: Gulf Coast Association of

Geological Societies Transactions, v. 40,

p. 607–621.

Montgomery, S.L., 1987, Success and sensibility

in South Florida: Petroleum Frontiers, v.

4, 52 p.

Palacas, J.G., 1978a, Distribution of organic

carbon and petroleum source rock

potential of Cretaceous and lower Tertiary

carbonates, South Florida basin,

preliminary results: U.S. Geological

Survey Open-File Report 78–140, 35 p.

———1978b, Preliminary assessment of organic

carbon content and petroleum source rock

potential of Cretaceous and lower

Tertiary carbonates, South Florida basin:

Gulf Coast Association of Geological

Societies Transactions, v. 28, p. 357–

381.

———1984, Carbonate rocks as sources of

petroleum—Geological and chemical

characteristics and oil-source correlations:

Proceedings of the 11th World Petroleum

Congress, 1983, v. 2, p. 31–43.

Palacas, J.G., Anders, D.E., and King, J.D.,

1984, South Florida basin—Prime

example of carbonate source rocks of

petroleum, in Palacas, J.G., ed.,

Petroleum geochemistry and source rock

potential of carbonate rocks: American

Association of Petroleum Geologists,

Studies in Geology, v. 18, p. 71–96.

Palacas, J.G., Daws, T.A., and Applegate, A.V.,

1981, Preliminary petroleum source-rock

assessment of pre-Punta Gorda rocks

(lowermost Cretaceous–Jurassic?) in South

Florida: Gulf Coast Association of

Geological Societies Transactions, v. 31,

p. 369–376.

Saul, W.L., 1987, Brown Dolomite zone of the

Lehigh Acres Formation, Lower

Cretaceous, South Florida: Lafayette, La.,

University of Southwestern Louisiana

Master’s thesis, 95 p.

Tootle, C.H., 1991, Reserves estimated,

production listed for Florida’s 22 oil fields:

Oil and Gas Journal, v. 89, p. 84–87.

Winston, G.O., 1971, The Dollar Bay Formation

of Lower Cretaceous (Fredericksburg) age

in South Florida, its stratigraphy and

petroleum possibilities: Florida Bureau of

Geology Special Publication No. 15, 99 p.
STRATIGRAPHIC UNIT

Corkscrew Swamp

Formation

Rookery Bay

Formation

Panther Camp

Formation

Dollar Bay

Formation

Gordon Pass

Formation

Marco Junction

Formation

Rattlesnake Hammock

Formation

Lake Trafford

Formation

Sunniland Formation

Punta Gorda Anhydrite

Able Member

West Felda

Shale Member

Pumpkin Bay Formation

Bone Island Formation

Wood River Formation

Glades Group

LOWER CRETACEOUS

Lehigh Acres Formation

Big Cypress Group Naples Bay Group Ocean Reef Group

UPPER

JURASSIC(?)

LITHOLOGY

Dolomite,

anhydrite,

limestone,

salt stringers,

and basal clastics

Limestone,

anhydrite,

dolomite

Limestone,

anhydrite,

dolomite

Calcareous

shale

Brown

dolomite

zone

Twelve Mile

Member

Brown dolomite,

limestone,

dolomite

Limestone, dolomite,

anhydrite

Anhydrite and salt,

limestone, dolomite

Limestone,

anhydrite

Limestone, dolomite,

anhydrite

Anhydrite,

limestone, dolomite

Limestone, dolomite,

anhydrite

Anhydrite,

limestone, dolomite

Limestone, dolomite,

anhydrite

Limestone, dolomite,

anhydrite8

Limestone, dolomite,

anhydrite

Limestone, dolomite,

anhydrite

Basal

clastics

PERIOD

Figure 1. General stratigraphic section for the South Florida Basin

[modified from Faulkner and Applegate (1986) and Lloyd (1991)].

8