Cockfield Formation Research Articles

Identification of Breaches in a Regional Confining Unit Using Electrical Resistivity Methods in Southwestern Tennessee, USA

Electrical resistivity and borehole data are applied to delineate lithostratigraphic boundaries and image the geometry of confining-unit breaches in Eocene coastal-plain deposits to evaluate inter-aquifer exchange pathways. Eight dipole–dipole array surveys were carried out, and apparent resistivity was inverted to examine the lateral continuity of lithologic units in different water-saturation and geomorphic settings. In addition, sensitivity analysis of inverted resistivity profiles to electrode spacing was performed. Resistivity profiles from Shelby Farms (SF) highlight the effect of varied electrode spacing (2.5, 5, and 10 m), showing an apparent ~0.63 to 0.75 depth shift in resistivity-layer boundaries when spacing is halved, with the 10 m spacing closely matching borehole stratigraphy. Grays Creek and Presidents Island profiles show clay-rich Eocene Cook Mountain Formation (CMF), with resistivity ranging from 10 to 70 Ω-m, overlying the Eocene Memphis Sand—a prolific water-supply aquifer. Resistivity profiles of SF and Audubon Park reveal sandy Cockfield Formation (CFF) paleochannels inset within and through the CMF, providing hydrogeologic connection between aquifers, and clarifying the sedimentary origin of confining-unit breaches in the region. The results underscore the efficacy of the electrical resistivity method in identifying sand-rich paleochannel discontinuities in a low-resistivity regional confining unit, which may be a common origin of breaches in coastal-plain confining units.

Fruits, seeds and flowers from the Puryear clay pit (middle Eocene Cockfield Formation), western Tennessee, USA

Fruits, seeds and flowers from the Puryear clay pit (middle Eocene Cockfield Formation), western Tennessee, USA

Assessment of undiscovered conventional oil and gas resources, onshore Claiborne Group, United States part of the northern Gulf of Mexico Basin

The middle Eocene Claiborne Group was assessed for undiscovered conventional hydrocarbon resources using established U.S. Geological Survey assessment methodology. This work was conducted as part of a 2007 assessment of Paleogene–Neogene strata of the northern Gulf of Mexico Basin, including the United States onshore and state waters (Dubiel et al., 2007). The assessed area is within the Upper Jurassic–Cretaceous–Tertiary composite total petroleum system, which was defined for the assessment. Source rocks for Claiborne oil accumulations are interpreted to be organic-rich, downdip, shaley facies of the Wilcox Group and the Sparta Sand of the Claiborne Group; gas accumulations may have originated from multiple sources, including the Jurassic Smackover Formation and the Haynesville and Bossier shales, the Cretaceous Eagle Ford and Pearsall (?) formations, and the Paleogene Wilcox Group and Sparta Sand. Hydrocarbon generation in the basin started prior to deposition of Claiborne sediments and is currently ongoing. Primary reservoir sandstones in the Claiborne Group include, from oldest to youngest, the Queen City Sand, Cook Mountain Formation, Sparta Sand, Yegua Formation, and the laterally equivalent Cockfield Formation. A geologic model, supported by spatial analysis of petroleum geology data, including discovered reservoir depths, thicknesses, temperatures, porosities, permeabilities, and pressures, was used to divide the Claiborne Group into seven assessment units (AUs) with three distinctive structural and depositional settings. The three structural and depositional settings are (1) stable shelf, (2) expanded fault zone, and (3) slope and basin floor; the seven AUs are (1) lower Claiborne stable-shelf gas and oil, (2) lower Claiborne expanded fault-zone gas, (3) lower Claiborne slope and basin-floor gas, (4) lower Claiborne Cane River, (5) upper Claiborne stable-shelf gas and oil, (6) upper Claiborne expanded fault-zone gas, and (7) upper Claiborne slope and basin-floor gas. Based on Monte Carlo simulation of justified input parameters, the total estimated mean undiscovered conventional hydrocarbon resources in the seven AUs combined are 52 million bbl of oil, 19.145 tcf of natural gas, and 1.205 billion bbl of natural gas liquids. This article describes the conceptual geologic model used to define the seven Claiborne AUs, the characteristics of each AU, and the justification behind the input parameters used to estimate undiscovered resources for each AU. The great bulk of undiscovered hydrocarbon resources are predicted to be nonassociated gas and natural gas liquids contained in deep (mostly 12,000-ft [3658 m], present-day drilling depths), overpressured, structurally complex outer shelf or slope and basin-floor Claiborne reservoirs. The continuing development of these downdip objectives is expected to be the primary focus of exploration activity for the onshore middle Eocene Gulf Coast in the coming decades.

Geology of Subsurface Eocene Cockfield Formation, Southern Allen Parish, Louisiana: ABSTRACT

A regional study of the subsurface Cockfield Formation (Eocene), southern Allen Parish, Louisiana, reveals that it was deposited as a result of the action of longshore currents and deltaic distributary channels within a nearshore marine environment. The juxtaposing of reservoir quality sands and marine shales within this environment created favorable conditions for the formation and entrapment of hydrocarbons. The Cockfield trend, a major oil and gas producing belt through the study region, appears to be composed mainly of fields that have combination stratigraphic-structural style entrapments. Localized sand pinch-outs and permeability barriers on rollover anticlines that developed on the downthrown sides of faults are responsible for most accumulations. Faults evident y controlled sand deposition in some parts of the study area, resulting in thicker deposits of sand on their downthrown blocks. Thickening of section within the Cockfield is present in isolated areas, and is confined to relatively short stratigraphic intervals. End_of_Article - Last_Page 1678------------

A Study of the Conroe Field

A study of fluid movement in the complex Conroe field indicated that gas was migrating from the Main Conroe sands to the lower-pressure Upper Cockfield sands, causing shrinkage of the Main Conroe gas-caps and loss of oil as residual saturation. Interim measures have been successful in temporarily stopping gas-cap shrinkage, and studies of long-range solutions are under way. Introduction The Conroe field is a 30-sq-mile, highly faulted structure producing from Cockfield sands that are prorated as two producing from Cockfield sands that are prorated as two separate fields. The thin Upper Cockfield sands have produced primarily as a depletion-drive gas reservoir, produced primarily as a depletion-drive gas reservoir, while the thick Main Conroe sands have produced more than 500 million bbl of oil by combination water and gas cap drive. A study of fluid movement indicated that gas was migrating from the Main Conroe sands to the lower-pressure Upper Cockfield sands, causing shrinkage of the Main Conroe gas caps and loss of oil as residual saturation. A computer model of this complex field showed that unless remedial action was taken migration would continue and future shrinkage losses could amount to more than 40 million bbl of oil. As an interim measure to alleviate the shrinkage, the Texas Railroad Commission increased the Main Conroe MER from 50,000 to 60,000 BOPD, which will slightly accelerate pressure decline and expand the remaining gas caps enough to offset the gas migration loss. A joint technical subcommittee is now studying the need for injection projects to stop permanently the migration and the need to form a field-wide permanently the migration and the need to form a field-wide unit for this purpose. Field Description The Conroe field is located 40 miles north of Houston on the upper Texas Gulf Coast. The structure is a large domal uplift, probably underlain by a deep-seated salt dome, and is highly faulted, as shown by the structure map in Fig. 1. The field produces from sands of the Cockfield formation of Eocene age at an average depth of 5,000 ft. Fig. 2 is a type electric log depicting the sandshale sequence, which is remarkably uniform across the structure. The field was discovered in 1931 and was developed rapidly on 20-acre spacing with 1, 100 wells. Essentially all the drilling took place before development of the electric log, and screened open-hole completions were made, generally through several sand members. The field currently consists of 150 leases operated by 27 companies. The Cockfield sands are prorated as two mews, as shown on the right side of Fig. 2. The Conroe field consists of six, thick, high-permeability sands that have provided 95 percent of the cumulative oil production. provided 95 percent of the cumulative oil production. For study purposes, they are designated the First through Sixth Main Conroe sands. Overlying the Main Conroe sands is the Conroe (Upper Cockfield) field. which consists of two thin, shaly sands that are primarily gas productive. productive. Production History and Reservoir Behavior Production History and Reservoir Behavior The Main Conroe sands had a thick (160-ft) original oil column, with uniform gas-oil and oil-water contacts in all sands. The original gas-cap/oil-zone volume ratio was 0.37. Cumulative oil production to Jan. 1, 1971 (the effective date of this study) was 461 million bbl. At that time, the field's assigned reservoir MER was 50,000 BOPD, produced from 600 active wells. JPT P. 813

The Long-Range Planning Function as Related to Katy Field Gas Sales

Devising an Optimum depletion plan for the fourth largest gas field in the United States required a detailed volumetric study for each of the twelve Katy reservoirs. All of the reservoirs have different water drive strengths, so the erect of producing rate on ultimate recovery is different for each reservoir. This is a key consideration in total-field optimization. Introduction The Katy gas field is presently under a 20-year gas sales contract, begun in 1967, and is in the last stages of gas cycling, begun in 1943. The field is located 35 miles west of downtown Houston, covers an areal extent of 50 sq miles, and comprises 12 reservoirs in the Cockfield formation, located at depths ranging from 6,000 to 7,400 ft subsea. Each reservoir has a different water-drive strength, depending on rock permeability, sand thickness, ratio of aquifer radius permeability, sand thickness, ratio of aquifer radius to reservoir radius, and reservoir geometry in general. Thus, the effect of the producing rate on ultimate recovery is different for each reservoir, and is a key consideration for total field optimization. Reservoirs with weak water drives exhibit high recoveries as a result of the combined action of pressure depletion and water influx over a long production life. Reservoirs with strong water drives are more sensitive to the producing rate, and should be depleted very quickly in order to maximize ultimate recovery. To determine the optimum production and investment schedules for the entire Katy gas field it was first necessary to develop mathematical models for each reservoir from pressure-production performance over the past 27 years. Anomalies caused by interreservoir communication and pressure interference from other fields producing from the Cockfield formation were considered in developing these models so that reasonably accurate predictions could be made regarding future reservoir pressure and well deliverability. Water influx data for reservoirs that have already undergone a significant amount of blowdown was determined by volumetric balance calculations. For the reservoirs that have experienced little or no depletion, however, these factors had to be estimated. After reasonable reservoir models were determined, it was necessary to impose certain constraints on the long-range blowdown scheduling. Two of the reservoirs have an associated thin rim-type oil column that must be essentially depleted before full-scale gas blowdown can occur. In addition, certain reservoirs are separated by very thin shale barriers and therefore must be depleted simultaneously to prevent large pressure differentials across these thin barriers. This precaution minimizes potential interreservoir communication and thus conserves potential interreservoir communication and thus conserves reservoir energy. Since most of the existing wellbores penetrate the productive areas of all the Katy reservoirs, it was productive areas of all the Katy reservoirs, it was necessary to develop models for estimating, the time at which wells water out and are available for recompletion to other zones. Wells now used for gas cycling in four of the upper reservoirs are also made available for recompletion as they drop out of the cycling program. Other factors to be considered for total field optimization are liquid recovery factors for each reservoir and development of sufficient deliverability to meet contract sales rates and peaking requirements. peaking requirements. JPT P. 145

Influence of Jackson Dome on Sedimentary Facies and Effect on Water-Bearing Properties of Claiborne in Jackson Area, Mississippi: ABSTRACT

This paper summarizes the importance of diastrophic uplift of the Jackson dome, which occurred during pre-Tertiary time and may have continued more or less active in the middle Eocene, and its influence on the sedimentary cycles in the Claiborne. The uplifting together with compaction of underlying sediments in the rim-syncline area affected the thickness, character, and attitude of the formations and established controls on the occurrence and quality of the ground waters. Isopachous maps and stratigraphic sections are presented to show the thicknesses of the Sparta sand and Cockfield formation on and around the dome; they indicate facies and thickness distribution of the sediments in these and several other units, and the size of the structure. Local concentration of lignitic material in the aquifers causes various degrees of straw-colored water affecting its usefulness for certain specific purposes. The pertinent stratigraphic units and the two principal aquifers are described. End_of_Article - Last_Page 2516------------

Conroe Oil Field, Montgomery County, Texas

The Conroe oil field, located in Montgomery County, Texas, was discovered in 1931. It is a broad ovate structure crossed by several normal faults which form a central graben area. The maximum vertical displacements of these faults range from 130 to 165 feet. Production is obtained at an average depth of 5,050 feet from the Cockfield formation of Upper Claiborne (Eocene) age, which has been uplifted more than 800 feet above its normal position. The average thickness of the Conroe producing sand throughout the field is 60 feet. The recoverable reserves have been estimated to be about 600 million barrels. Currently the field is producing daily 47,700 barrels of oil from 829 wells, of which 53 wells are producing salt water in varying amounts. There is free communication and equalization of fluid across the fault planes so that there exists a unit reservoir wherein the fluids segregate themselves at uniform levels throughout the field. The interval within which sand may contain oil is 130 feet, or between the -4,860-foot and -4,990-foot datum planes. A large gas cap overlies the oil and occupies an interval of 170 feet, or between the datum planes of -4,690 and -4,860 feet. Conroe has a proved area of 17,200 acres and has produced a little more than 40 million barrels of oil up to January 1, 1935. Reservoir pressures became stabilized after the field has produced about 29 million barrels of oil and the pressure decline since then has been less than one pound per million barrels of oil produced.