Frio Sands Research Articles

Measurement of Unloading Pore Volume Compressibility of Frio Sand Under Uniaxial Strain Stress Path and Implications on Reservoir Pressure Management

Measurement of Unloading Pore Volume Compressibility of Frio Sand Under Uniaxial Strain Stress Path and Implications on Reservoir Pressure Management

Multiphase CO2-brine transport properties of synthetic fault gouge

Faults are key components in defining fluid migration pathways and seals in sedimentary basins. The sealing capacity of faults is closely related to the petrophysical and geomechanical properties of fault gouge. Clay smear, cataclasis, and diagenesis favor a high capillary breakthrough pressure and low permeability in clastic sediments, and therefore fault gouge seal. However, significant uncertainty remains in accurately predicting the sealing capacity of faults for CO2 storage. We conducted a series of experiments, including absolute permeability, breakthrough pressure, and post-breakthrough CO2 permeability measurements on synthetic fault gouge samples, made from homogeneous mixtures of Frio sand and Anahuac shale, lithofacies of tertiary sediments in the Gulf of Mexico basin. The results show that the permeability of synthetic fault gouge decreases by about one order of magnitude with increments of 10 wt% of clay (mostly smectite) from the Anahuac shale. Independent of clay content and bulk porosity, all permeability measurements scale with the void ratio of the clay fraction. The breakthrough pressure of synthetic fault gouge increases by approximately half order of magnitude with increments of 10 wt% clay. The samples with clay content above 40 wt% reach a breakthrough pressure equivalent to a (supercritical) CO2 column height of more than 100 m. The measurements on fault gouge properties are meaningful to quantitatively evaluate fault sealing capability and migration of buoyant fluids through faults in sand-shale sequences.

Quantification of a maximum injection volume of CO2 to avert geomechanical perturbations using a compositional fluid flow reservoir simulator

Abstract Subsurface CO2 injection and storage alters formation pressure. Changes of pore pressure may result in fault reactivation and hydraulic fracturing if the pressure exceeds the corresponding thresholds. Most simulation models predict such thresholds utilizing relatively homogeneous reservoir rock models and do not account for CO2 dissolution in the brine phase to calculate pore pressure evolution. This study presents an estimation of reservoir capacity in terms of allowable injection volume and rate utilizing the Frio CO2 injection site in the coast of the Gulf of Mexico as a case study. The work includes laboratory core testing, well-logging data analyses, and reservoir numerical simulation. We built a fine-scale reservoir model of the Frio pilot test in our in-house reservoir simulator IPARS (Integrated Parallel Accurate Reservoir Simulator). We first performed history matching of the pressure transient data of the Frio pilot test, and then used this history-matched reservoir model to investigate the effect of the CO2 dissolution into brine and predict the implications of larger CO2 injection volumes. Our simulation results –including CO2 dissolution– exhibited 33% lower pressure build-up relative to the simulation excluding dissolution. Capillary heterogeneity helps spread the CO2 plume and facilitate early breakthrough. Formation expansivity helps alleviate pore pressure build-up. Simulation results suggest that the injection schedule adopted during the actual pilot test very likely did not affect the mechanical integrity of the storage complex. Fault reactivation requires injection volumes of at least about sixty times larger than the actual injected volume at the same injection rate. Hydraulic fracturing necessitates much larger injection rates than the ones used in the Frio pilot test. Tested rock samples exhibit ductile deformation at in-situ effective stresses. Hence, we do not expect an increase of fault permeability in the Frio sand even in the presence of fault reactivation.

Occurrence of gas hydrate in Oligocene Frio sand: Alaminos Canyon Block 818: Northern Gulf of Mexico

A unique set of high-quality downhole shallow subsurface well log data combined with industry standard 3D seismic data from the Alaminos Canyon area has enabled the first detailed description of a concentrated gas hydrate accumulation within sand in the Gulf of Mexico. The gas hydrate occurs within very fine grained, immature volcaniclastic sands of the Oligocene Frio sand. Analysis of well data acquired from the Alaminos Canyon Block 818 #1 (“Tigershark”) well shows a total gas hydrate occurrence 13 m thick, with inferred gas hydrate saturation as high as 80% of sediment pore space. Average porosity in the reservoir is estimated from log data at approximately 42%. Permeability in the absence of gas hydrates, as revealed from the analysis of core samples retrieved from the well, ranges from 600 to 1500 millidarcies. The 3-D seismic data reveals a strong reflector consistent with significant increase in acoustic velocities that correlates with the top of the gas-hydrate-bearing sand. This reflector extends across an area of approximately 0.8 km 2 and delineates the minimal probable extent of the gas hydrate accumulation. The base of the inferred gas-hydrate zone also correlates well with a very strong seismic reflector that indicates transition into units of significantly reduced acoustic velocity. Seismic inversion analyses indicate uniformly high gas-hydrate saturations throughout the region where the Frio sand exists within the gas hydrate stability zone. Numerical modeling of the potential production of natural gas from the interpreted accumulation indicates serious challenges for depressurization-based production in settings with strong potential pressure support from extensive underlying aquifers.

Abstract: Fifty Year Old Frio/Vicksburg Cage Ranch Field in Brooks County, Texas is Rejuvenated with 3D

ABSTRACT Suemaur Exploration undertook a 3-D seismic shoot in 1994 over the apparently depleted 50-year-old Frio/Vicksburg Cage Ranch Field in central Brooks County, Texas. This 3-D survey has rejuvenated the field with the 1995-96 drilling of six wells, with eight completions in both normal pressure Frio sands and abnormal pressure Vicksburg sands. Cage Ranch Field, discovered in 1947 by Shell, had produced 99 billion cubic feet (BCF) of gas and 850 thousand barrels of condensate (MBC) from 36 wells, in 64 completions. By 1994, production was less than one million cubic feet of gas per day and 16 barrels of condensate a day. The 3-D interpretation identified three major differences between our pre- and post-drill maps. The first was that there was no roll, or west dip downthrown to the Vicksburg flexure on the west at the Middle Firo. Suemaur then drilled the highest Frio wells to date in the field. Secondly, the crest of the underlying Vicksburg structure was not coincident with the overlying Frio structure, but was over a mile south enabling us to make the first commercial Loma Blanca Sand Vicksburg age completion in the field, with the 710-1 well completed for 4.6 million cubic feet of gas per day (MMCPD) and 175 barrels of condensate per day (BCPD). Thirdly, a major arcuate, down-to-the-south embayment Vicksburg age fault was identified on the southeast flank of Cage Ranch, enabling us to drill the discovery well for Hook Field.

Cathodoluminescent textures and the origin of quartz silt in Oligocene mudrocks, South Texas

ABSTRACT In subsurface mudrocks of the Oligocene Frio Formation in South Texas, a substantial proportion of silt-size quartz (10-62 µm) manifests cathodoluminescence (CL) that varies greatly in intensity within each particle, giving rise to textures that differ greatly from grain to grain. In contrast, most quartz grains of sand size (>= 62 µm) have CL that is relatively homogeneous within individual grains. A substantial percentage of the quartz within silt grains is very weakly luminescent. No depth trend in the occurrence of luminescent textures in detrital quartz is observed, suggesting that the component of dark, possibly low-temperature silt-size quartz is not related to chemical processes in the present burial setting. Paleogene rhyolites of West Texas are a partial model for the source rocks that supplied sediment to the Frio Formation. Phenocrystic quartz in these volcanics has uniform CL similar to that observed in the Frio sand fraction, whereas complex CL structure seen in the associated groundmass bears many similarities to the CL textures observed in Frio silts. This observation further supports the idea that CL structure of detrital quartz in the Frio is most likely an inherited feature. If the quartz with dark CL is of low-temperature origin, it would help to elucidate the relatively 18O-enriched isotopic values reported for mudrock quartz in the Frio.

Borregos Field Surfactant Pilot Test

A pilot test of petroleum sulfonate flooding was conducted during the mid-1960's in the Borregosfield, Kleberg County, Tex. The test was run in a heterogeneous Frio sand containing considerable montmorillonite. Oil recovery was limited by excessive fractionation of the injected petroleum sulfonate and by poor sweep efficiency. Introduction A tertiary surfactant pilot test was conducted during 1965 and 1966 in the Borregos field, Kleberg County, Tex. Results of a more recent pilot test have been published. Aqueous surfactant flooding uses a preferentially water-soluble surfactant capable of drastically reducing water-oil interfacial tensions and, therefore, of reducing capillary forces trapping discontinuous residual oil. Although success with dilute petroleum sulfonate solutions had been demonstrated in laboratory core floods, a field test was needed to define the status of the process and to identify possible problem areas. Surfactant adsorption and process sweep efficiency were two major concerns. Description of Pilot Area Zone F-4 in the Borregos field is a thin Frio sand. Structurally, the field is a broad anticline. In the pilot area (Fig. 1), the F-4 sand has a gross thickness of about 8 ft. Elevation of the top of the sand at its highest point in the pilot (Well 238) is 4,998 ft subsea. Fluid contacts were pilot (Well 238) is 4,998 ft subsea. Fluid contacts were far removed from the pilot area. The oil-water contact was at 5,089 ft subsea and the gas-oil contact was at 4,972 ft subsea. At the time pilot operations were initiated in 1965, Zone F-4 was producing by gas-cap expansion and solution-gas drive. Reservoir pressure had dropped to 2,000 psi from a discovery pressure of 2,500 psi. psi. The pilot pattern was a 1.25-acre, isolated five-spot. An existing well, Well 238, was converted to an injector and four new wells were drilled. These wells were conventionally cored with natural mud to avoid alteration of rock wettability. One-hundred-percent core recovery was obtained in Wells 411, 412, and 414. Core recovery was very low in Well 420. Hole deviations during drilling caused the down-hole pattern to be somewhat skewed. Bottom-hole locations (Fig. 2) were determined by multishot directional surveys during drilling, except for Well 238, where a cased-hole survey was performed.A pressure coring operation conducted upon termination of the surfactant flood provided additional reservoir description. Core Hole 441-1 and Deviations 441-2 and 441-3 were drilled to determine residual oil saturations. The bottom-hole locations of these postflood core holes are also shown in Fig. 2. Geologic Study A detailed environmental-facies study was undertaken to provide a geologic framework for the pilot area. The provide a geologic framework for the pilot area. The external form of the F-4 sand is a tabular sheet; internally, it consists of a number of elongated, individual channel deposits that coalesce and cross one another. Each channel consists of an impermeable basal clay-clast bed, fine-to medium-grain sandstone, and another impermeable bed of siltstone. Channel-to-channel communication occurs through the sides of the channels and across erosional boundaries. The clay minerals are chiefly montmorillonite. Matrix (less than 0.03 mm) clay content is unusually high, averaging 8.5 weight percent. Porosity and permeability are also influenced by local zones of calcite cementation. Calcite cement was most prevalent in Well 414 and, to a somewhat lesser extent, in Well 412. JPT P. 695

Developments in South Texas in 1973

Drilling activity in South Texas decreased from 1,777 wells in 1972 to 1,733 wells in 1973. This is a decline of 2%. Exploratory wells were slightly more successful than last year with 14% of the wildcats being discoveries. Development successes were down 4.3% from 1972's 76.3%. The Paleozoic trend (Pennsylvanian) has received much attention in Edwards County, whereas, on the other hand, Real County has turned in its first production. Cretaceous drilling has been quite active with the San Miguel and Olmos sands being of prime importance. The Cretaceous Sligo did not yield any new production. Eocene discoveries were led by drilling for the Wilcox Group in Webb and Duval Counties. Frio sands continued to be attractive for both exploration and development. San Patricio, Goli d, Victoria, and Jackson Counties all have turned in new-field discoveries. Offshore drilling increased by 92% over last year with 27 successful wells being put down.

A Reservoir Study of the Friendswood Field

To temporarily stop migration of oil into the original gas cap, the existing gas injection project in this Texas Gulf Coast field was expanded. For the purpose, water turned out to be a more efficient displacing medium than gas. By unitizing the field and then injecting 80,000 barrels of water a day, oil migration can be stopped and 55 million more barrels of oil will be recovered. Introduction The Friendswood field (sometimes referred to as Webster) was discovered by Humble in 1937. It is located on the upper Texas Gulf Coast immediately south of Houston (Fig. 1), and has productive sands originally encompassing more than 4,100 acres. Approximately 215 wells were required to fully develop the field to 20-acre spacing. The sands are very prolific and the average well exhibits a productivity index of approximately 29 B/D per psi productivity index of approximately 29 B/D per psi drawdown. Cumulative Frio sand oil production has been 310 million bbl, and reservoir pressure has dropped only 340 psi since discovery. Principal production has been from upper Frio sands of Miocene age. Although prorated together, these sands have been divided into 17 members for reservoir control purposes. A small amount of oil (2 million bbl) has been produced from the Marginulina sands, which lie just above the Frio. The field contains several fault systems, and, because of fault juxtaposition, communication occurs between some of the sand members. Several studies, resulting in MER hearings, workover programs, and a gas injection program, have been conducted in the past. For the study discussed here, those past programs were reviewed and additional necessary programs were determined. Current fluid contacts for each sand member were ascertained on the basis of conventional neutron logs, pulsed neutron logs, induction electric logs, and well production histories. Oil and gas volumes were then production histories. Oil and gas volumes were then mapped for original and current conditions. Material balance and unsteady-state water influx calculations were used to match past reservoir behavior and to predict future performance. predict future performance. JPT P. 685

Adverse Influence of Stratification on a Gas Cycling Project

Described here is a gas cycling project that failed. The premature dry-gas breakthrough and subsequent poor recovery in this Gulf Coast field was probably caused by horizontal permeability stratification. probably caused by horizontal permeability stratification. Introduction The subject field in this study is a small fault-block gas-condensate reservoir in Galveston County, Tex. The reservoir is in the Frio sand and has an average net pay thickness of 64 ft. The displaceable porosity for gas cycling (the total porosity less the saturation of connote water) averaged 0.19 over this thickness. The reservoir is believed to be completely isolated by four sealing faults, as shown in Fig. 1. The surface area of the reservoir is given as 234 acres. These figures give a displaceable pore volume af 123.85 MMcf at the average reservoir conditions (320 atm pressure and 727 degrees R) at the start of the cycling project. This is equivalent to 29,352 MMscf of wet gas as the potential recovery, which would result in nearly 3 million bbl of condensate. The first well in the reservoir (Well 1) was the sole production well until it was converted to an injection production well until it was converted to an injection well upon completion of Well 2 in Nov., 1966. Prior to that time, 11,504 MMscf of wet gas was produced, and the reservoir pressure declined to near the dew point (320 atm). point (320 atm). Since no core information was available from the earlier well, a full 4-in. core was taken during the drilling of Well 2. Representative samples were analyzed by a commercial laboratory (Table 1). The remainder of the core was taken for the detailed analysis described in the next section. It was hoped that with such an analysis an accurate prediction of the cycling results could be obtained. The analysis was to pay particular attention to permeability variations, which particular attention to permeability variations, which would have a large effect on cycling results. Cycling was started on Jan. 20, 1967, with injection into Well 1 and production from Well 2. Over all, a volumetric replacement of the produced gas was closely achieved. Water production was relatively stable at 50 to 100 B/D. Core Analysis A complete description of the analysis procedure and results may be found in another publication. Briefly, those parts of the core that were suitable were subjected to a whole-core type of permeability measurement similar to a flood-pot analysis. These tests were designed to detect horizontal permeabilities of individual strata as small as 0.1 in. in height. The core samples were first formed into a right cylinder with concentric center hole. The ends were sealed so that flow would be between the center hole and the outer curved surface of the core. The cores were saturated with naphtha, and this was displaced from the inside by the same naphtha carrying a red dye and at a constant flow potential difference. The inner surfaces of the sandstone were pretreated with a surface active agent that prevented adsorption of the dye from solution, and the outer surfaces were dusted with a white clay so that the arrival of the red dye could be seen and photographed. P. 191

Control of Unconsolidated Sands in Waste-Disposal Wells: ABSTRACT

Sand control methods were first used in water wells, and later, modified methods were applied to oil and gas wells. The most recent application for sand control is in waste-disposal wells. The increasing use of unconsolidated sands as disposal zones has created a need for better sand-control systems. We suggest that the primary causes of sand control problems in disposal wells are: (1) greater completion intervals, (2) intermittent operation of the well, and (3) chemical characteristics of the injected effluent. Therefore, successfully to prevent sand production in disposal wells, consideration must be given to: (1) formation characteristics, (2) completion fluid, (3) type of completion, and (4) completion method. Two universally used methods of sand exclusion, with suggested modifications when applied to disposal wells, are the method of in-place sand consolidation with plastics, and the use of gravel packs in conjunction with sand screens. Sand consolidation has limited application owing to the large completion intervals normally used in disposal wells, and to possible chemical reactions with injected effluent. However, a gravel-packed-sand-screen completion generally eliminates the three primary causes of sand production in disposal wells. Factors of prime importance are (1) the drilling and completion fluids, (2) formation grain size and composition, (3) size and amount of gravel, (4) pumping rate, (5) pressure, and (6) gravel concentration. Field and laboratory data show that the method of gravel-packed-sand-screen completions can be used successfully over intervals as large as 500 ft in unconsolidated Frio sands. End_of_Article - Last_Page 2084------------

Pressures, Hydrocarbon Accumulation, and Salinities Chocolate Bayou Field, Brazoria County, Texas

The hydrocarbon accumulation at Chocolate Bayou field appears to be intimately related to the fluid environments there. An understanding of the processes at work in this field can be used in planning the development of active fields where comparable fluid data are available. Introduction The Chocolate Bayou field is located in east-central Brazoria County, about 25 miles south of Houston, Tex. Production in the field is from Oligocene Frio sands ranging in depth from 8,600 to 12,200 ft. About half the approximately 2Tcf of gas reserves in the field is found in reservoirs with pressures substantially above hydrostatic. Data collected since the discovery of this field in 1939 permit an evaluation of the effects of abnormally high pressures on the migration and entrapment of hydrocarbons and the salinity of formation waters in the field. An understanding of the relationship between fluid properties and hydrocarbon entrapment in this field may be applicable to the development of other Gulf Coast fields. Geology The Chocolate Bayou field produces from a faulted anticline in the downdip Frio trend. A large growth fault divides the field into two producing areas. Fig. 1 shows the producing area of the field and the approximate location of the fault separating the two principal producing segments. The downthrown, eastern fault producing segments. The downthrown, eastern fault block produces from a closed anticlinal structure; the upthrown, western fault block produces from a closure against the regional fault crossing the field. A number of minor faults are present, but have little effect on the pattern of hydrocarbon accumulation in the field. The two major fault blocks are referred to as East Chocolate Bayou and West Chocolate Bayou in this paper. Structural maps of the field are given by Allen and Allen and Myers. The producing Frio section is an alternating sand and shale sequence overlying a thick section of Oligocene and older shales. Above the Frio is the Anahuac shale wedge, which is about 2,200 ft thick in the field. About 6,500 ft of undifferentiated Miocene and younger massive sands interbedded with comparatively thin shales extends from the top of the Anahuac to the surface. Radical changes in the lithology and thickness of the Frio section across the growth fault bisecting the field indicate that movement along this fault was contemporaneous with deposition of the Frio field pays. Movement continued intermittently along the fault during the deposition of the Anahuac shales and the lowermost Miocene sands. The increased Frio sand deposition in the area of the present structural high suggests that movement of the producing structure had already begun by Frio time. Uplift continued well into Miocene, where the feature is expressed as a faulted nose at depths as shallow as 6,000 ft. This long history of structural uplift has resulted in an increase of structural relief with depth and an abundance of minor faults associated with this structural deformation. JPT P. 411

Storage of LPG in Gas Reservoirs

To store great volumes of LPG at minimum cost, nonassociated gas reservoirs have proved satisfactory in the Borregos field of South Texas. For maximum success, this method of storage requires an exhaustive geologic description of the reservoir, or, lacking this, careful monitoring of reservoir pressure. Introduction The petroleum industry has rapidly responded to the increased demand for refined LPG to serve as feed stocks for the petrochemical industry. Many of the new natural gasoline plants being constructed have been designed to recover a maximum amount of the lighter products in anticipation of the expanding market for these products. Since the demand for these products products. Since the demand for these products in most cases is highly variable, the continuous output from the gasoline plants necessitates some form of temporary storage facilities. This paper reviews field experience with underground storage of LPG in gas condensate reservoirs in the Borregos field near Corpus Christi, Tex. In 1960, Humble Oil and Refining Co., realizing that markets soon would become available for the temporarily surplus ethane, propane and butane from the King Ranch Gas Plant, propane and butane from the King Ranch Gas Plant, began storing these products in two virgin nonassociated gas reservoirs, using dual-purpose injection and production wells. Peak storage volumes ranged from 275,000 bbl of butane to 2.5 million bbl of propane. Injection rates as high as 7,000 B/D and withdrawal rates as high as 4,500 B/D were achieved. Storage Reservoirs Although three reservoirs have been involved in storage operations, only the two with significant history are considered in detail here. The productive limits of the two major storage reservoirs, Borregos Zones H-5 and H-7, are shown in Fig. 1. These reservoirs are two of the many found in the large anticlinal structure of the Borregos field. They are shallow Frio sands deposited in a strandline type of environment and are considered to be near-shore or lagunal deposits. Originally, both reservoirs were of nonassociated gas; the properties of the native gases are shown in Table 1. Fig. 2 is a representative cross-section of the storage reservoirs. Borregos Zone H-5 is found at an average depth of 5,275 ft and varies in thickness from 0 to 25 ft, averaging 10.4 net ft in the storage area. This sand grades from a clean sand of moderate thickness on the flank of the structure to a tight (lower permeability) thin sand on the crest. Borregos Zone permeability) thin sand on the crest. Borregos Zone H-7 occurs approximately 50 ft stratigraphically below Zone H-5. Zone H-7 ranges in over-all thickness from 0 to 24 ft, averaging 5.5 net ft in the area of LPG storage. The continuity of this reservoir is complicated by re-entrant shale-outs and rapidly changing lithology. The exact depositional environment has not been established but is probably related to Zone H-5. Both Zones H-5 and H-7 dip from west to cast at an angle of about 1 degrees. Borregos Zone D-5, not discussed in detail in this report, is found at an average depth of 4,700 ft and averages 9.7 ft in thickness. A summary of storage reservoir properties is shown in Table 2. JPT P. 587

Big Hill Field, Jefferson County, Texas: ABSTRACT

ABSTRACT Big Hill Field is in the Frio Sand Trend on the western flank of Big Hill Salt Dome. Multiple reservoirs in Miocene and Oligocene sands are on the downthrown side of a regional up-to-coast growth fault that expands the thickness of Lower Miocene and older sediments 57%. One Hackberry reservoir is bounded by two growth faults and an erosional surface. The hydrocarbons trapped therein are evidently indigenous to the surrounding rocks. An isopach map, Top of Frio to the Hackberry Unconformity, indicates that Big Hill salt dome was formed prior to the end of Frio time; the crest of the dome at that time was north of the present salt spine. This map also locates a buried down-to-coast growth fault that traverses the west flank of Big Hill Field but does not intersect any wells. Pressure performance histories of two reservoirs, and also of two wells not producing from these reservoirs, are shown graphically in order to illustrate the problems involved in explaining wells that are in pressure communication. Four gas-fluid contacts in a continuous Marginulina reservoir differ in elevation by 600 ±. These original gas contacts were created by hydrocarbons migrating into a complexly faulted area. Accumulation of oil downdip from these gas contacts can be reasonably explained in terms of gravity segragation effects.

Structure and Stratigraphy of Rayne Field: ABSTRACT

The Rayne field is in east-central Acadia Parish, Louisiana. The primary production from this field is gas condensate from multiple Frio sands ranging from Marginulina texana to Nodosaria blanpiedi. The important geological significance of this field lies in the pronounced effect on the stratigraphy and structure of two major down-to-the-south depositional faults. Pronounced thickening of the stratigraphic section occurs on the downthrown side of both faults. The northernmost fault on the north flank of the Nodosaria structure is the older and influences the older sediments from Nomion struma time to Nodosaria blanpiedi time, and the southern fault is the southern boundary of Nodosaria production and influences primarily the younger sediments from Cibicides hazzardi time nto Nonion struma time. End_of_Article - Last_Page 1603------------

Frio Formation of Upper Texas Gulf Coast: ABSTRACT

A study group of the Houston Geological Society has concerned itself with the Tertiary Frio formation as it exists in the subsurface in the area from Jackson County, Texas, to Louisiana. To facilitate study, the formation was divided into upper and lower units and each was traced over the area of interest by means of electrical log characteristics. An electrical log correlation point in the Marginulina zone of the overlying Anahuac formation was used as a practical expedient for the of the Frio. A horizon near the Nodosaria blanpiedi faunal zone in the middle of the Frio served as the top of the lower Frio unit. No specific electrical log datum was used for the base of the Frio. The number of feet of porous and permeable sand within each unit was counted from the electrical End_Page 2513------------------------------ logs. From these data, sand percentage and net sand maps were constructed for the upper and lower Frio units. Lower Frio sand values range from 2 feet to 1,600 feet. Maps tend to indicate that the center of deposition of the lower Frio unit is in Matagorda and Brazoria counties. Thick sequences of sand and shale occur in this area, particularly in the Textularia seligi (mississippiensis) and Anomalina bilateralis faunal zones. Wells here indicate as much as 1,600 feet of sand in a total interval of more than 2,600 feet. The center of deposition of the upper Frio unit appears to be in Jefferson and Orange counties. This is accentuated by the occurrence of thick sands in the Hackberry zone, which results in more than 1,200 feet of sand in an interval exceeding 3,600 feet. Sand values range from 16 feet to 1,289 feet and sand percentages from 3% to 62%. Efforts were made to minimize the effects of local structure and local lithologic variations. Nevertheless, such large subregional features as the western Jefferson County graben; the Red Fish Reef-South Mayes complex of Chambers County; the Chocolate Bayou complex, Danbury dome, and the Chenango complex of Brazoria County; and the Old Ocean complex of Matagorda County exhibit lithologic anomalies coincident with the area of their structural influence. These anomalies indicate that structural movement was taking place during deposition. End_of_Article - Last_Page 2514------------

Review of Hitchcock Field, Galveston County, Texas: ABSTRACT

The stratigraphy and structure of Hitchcock field, located about 40 miles southeast of Houston, are discussed in light of the 27 wells drilled there since Halbouty and Simmons' original study in 1941. The producing structure appears to be an east-west anticline, the crest of which has been downfaulted to form a graben. Maximum stratigraphic throw of the faults in the field is 280 feet. The large regional strike fault that passes north of the field has a stratigraphic throw of 830 feet. The greatest structural growth seems to have occurred during late Miocene or early Pliocene time. The sand in which oil was first discovered (5,100-foot sand) is still the most important reservoir in the field. It is absent over the crest of the anticline, but is present on the west, south, and east flanks. Cumulative production from Hitchcock field through 1957 was 4,115,421 barrels of oil, 1,889 barrels of condensate, and 1,180,919 MCF of gas. All of the oil and most of the gas come from the Miocene. Some gas is produced from the Pliocene. Three wells drilled to the Oligocene Frio sands failed to find production in that section. End_of_Article - Last_Page 2515------------

Twelve Years of Gas Injection in a Frio Sand

Introduction The purpose of this paper is to contribute to the existing knowledge of the economic recovery of oil by methods other than normal depletion. A case history is presented of a gas injection project in one zone of the multiple producing zone Frio sands of south Texas. Approximately 75 per cent of the produced gas has been returned to the formation for 12 of the 13 years of producing life. The study is an example of the performance which has been experienced by return of a large portion of the produced gas to the gas cap of a thin non-homogeneous sand. Geology The producing zone is the Frio sand of lower Oligocene age. The oil and gas accumulation is a combination of a structural and stratigraphic trap. The structure consists of a large asymmetrical nose plunging gently to the northeast. The reservoir is limited on the west flank by an oil-water contact, on the north and south by the sand lens grading into shale, and on the east by a steep fold or fault parallel to the axis of the structure. The dip of the west flank or oil producing flank is approximately 130 ft per mile, or only 1.5 degrees. There are 11 separate Frio producing zones in the field but this paper is limited to only one of the zones. The sand lenses are separated vertically by 25 to 75 ft of shale and were correlated across the field by means of markers picked from the electric logs. A portion of a typical cross section is shown on Fig. 1 and the section is located with reference to the area on Fig. 2. The D-5 reservoir is the large sand lens which appears in the D zone on the cross sections. It covers an area of approximately 2,100 acres. The structural map of the D zone (Fig. 2) was contoured on the subsea correlation points on the top of the D zone. The reservoir rock is predominately firm, medium to fine-grained gray, argillaceous sandstone but lenses of soft, loosely consolidated sandstone occur throughout the producing zone. An x-ray diffraction indicates the clay content to be chiefly of the montmorillonite group and solubility tests indicate a low carbonate content. The porosity ranges from 8 to 28 per cent with a weighted average of 23 per cent. The majority of the horizontal permeability ranges from 100 to 500 md and averages 194 md. The vertical permeability is approximately one-half of the horizontal permeability.

New Exploration Possibilities on Piercement-Type Salt Domes Established by Thrust Fault at Boling Salt Dome, Wharton County, Texas

The South Boling field, Wharton County, Texas, on the south flank of the Boling piercement-type salt dome, was discovered in November, 1951, by the side-tracking of Michel T. Halbouty's Gary Estate No. 1-A, a dry hole. Four dry holes including the 1-A well were drilled in the area by the operator in the attempt to discover the field. After discovery, development proved the controlling structural feature to be a thrust fault associated with the Boling piercement-type salt dome. Some wells penetrated as much as 1,000 feet of overthrust Jackson (Eocene) shale before reaching the younger Frio (Oligocene) beds below the plane of the thrust fault. Ten productive Frio sands and one productive Marginulina sand have to date been established in the field. The significance of the th ust fault to Gulf Coast geological thinking and its expected effect on future exploration of piercement-type salt domes are discussed.