Miocene Sands Research Articles

Stopping rate and energy loss of cosmic ray muons in sand

The stopping rate of negative cosmic ray muons in an outcropping Miocene sand was determined by using scintillation techniques to be (1.29±0.05)×10−5 exp (−0.103z) muon/cm3 s over the depth range of z from 3 to 11 m. This stopping rate is greater by a factor of 2–4 than previous emulsion measurements made in this depth range. The energy loss rate of cosmic ray muons over the same depth interval was determined to be nearly constant at 1.55±0.06 MeV cm2/g.

Perforations-A Prime Source of Well Performance Problems

As sure as technology comes up with a nifty solution to a persistent problem you can bet it will have to come up with equally nifty solutions problem you can bet it will have to come up with equally nifty solutions to the new problems caused by he original solution. This is called progress. progress. Introduction This investigation was undertaken to determine the cause of difficulties encountered in injecting fluids through perforations into unconsolidated permeable Pliocene and Miocene sand reservoirs. The particular Pliocene and Miocene sand reservoirs. The particular wells in question are in the South Pass Block 24 and Block 27 fields, located at the mouth of the Mississippi River. We felt that injectivity impairment, by preventing proper placement of sand-control, was a primary cause of the high incidence of sand-control primary cause of the high incidence of sand-control failure and associated casing damage. We expected that by understanding the source of injectivity impairment we could also obtain a better insight into the cause of productivity impairment common to those wells. Impairment of injectivity into unconsolidated sands can be a serious problem since a essential part of the completion is the injection of sand-consolidating fluids into the formation through the perforations, or the deposition of gravel in the perforation tunnels (the holes through the casing and cement sheath). Portions of an interval not accepting consolidating Portions of an interval not accepting consolidating chemicals would be subject to early sand-control failure. Treatment through impaired perforations could cause the impairment to become "locked in place" by the treatment plastics and result in seriously decreased well productivity. In gravel packing, the perforation tunnels must be filled with properly sized perforation tunnels must be filled with properly sized gravel to prevent the tunnels from becoming filled with fine formation sand when the well is put on production. Perforation tunnels filled with fine production. Perforation tunnels filled with fine formation sand severely restrict fluid flow. The tunnels can most likely be filled with gravel only if fluid can flow out of the wellbore through the perforation tunnels and carry gravel into them during perforation tunnels and carry gravel into them during gravel-packing operations. Perforation Flow Impairment Perforation Flow Impairment There has been widespread evidence of a severe perforation flow impairment problem in Shell's perforation flow impairment problem in Shell's Delta Div. in South Louisiana. Plastic consolidation fluids usually could not be pumped outward through the perforations without acid stimulation or fracturing, neither of which has assured uniform placement throughout the perforated interval. Gravel-packed wells have commonly required acidizing before full-depth-allowable production could be obtained. Recovered gravel-pack production could be obtained. Recovered gravel-pack screens and blast joints have frequently shown only one or two eroded holes (Fig. 1), suggesting that most of the produced fluid was coming from only a few of the perforations. Steps were taken, therefore, to isolate the cause of impairment of well injectivity and productivity. A process of elimination was begun in the field concurrently with laboratory investigations. The extent of perforation impairment and its relative importance with perforation impairment and its relative importance with respect to other possible sources of trouble (drilling mud or cement or completion fluid) were studied individually. Drilling mud and cement were considered to be possible contributors to impairment primarily because possible contributors to impairment primarily because of the way dispersant-type filtrates affect the clay material in the formation. P. 399

Lower Miocene Stratigraphy and Petroleum Potential, Offshore Galveston and Jefferson Counties, Texas: ABSTRACT

Lower Miocene sediments in the southeast Texas coastal area can be divided into 2 distinct trends. The basal Miocene interval from the top of the Oligocene Discorbis upward to the Robulus chambersi is a predominantly regressive-marine sequence that reflects the gradual progradation of Miocene sands into this area. The overlying sequence from Robulus chambersi to Amphistegina (B) consists of deltaic and delta-related sediments that reflect continued marine regression and seaward progradation of a large early Miocene delta system. In the nearshore Galveston and High Island areas, the basal Miocene interval contains a series of potential reservoir sandstones, most of which are above the abnormally pressured zones and occur at depths of less than 9,500 ft. Farther offshore, the younger Amphistegina (B) sandstones become favorable exploration objectives. Several lower Miocene biostratigraphic zones are identifiable throughout the area and an attempt has been made to relate each zone to particular lithologic conditions or depositional environments. Because of the general southward movement of the shoreline during the Miocene and a relatively limited supply of sand, prospective Miocene sandstone trends in the southeast Texas offshore occur in narrow belts approximately parallel with the present coastline. Identification of these favorable trends is essential to a successful exploration program in this area. End_of_Article - Last_Page 1695------------

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

Geologic Occurrence of Oil and Gas in Miocene of Gulf Coast of United States: ABSTRACT

Miocene sands have produced, through 1967, approximately 6.76 billion bbl of oil and 35 Tcf of gas in about 650 fields in coastal and offshore Louisiana and Texas. More than 80% of the production has come from fields in the Louisiana segment, where all 19 giant Miocene oil fields are located. The Miocene sediments of coastal and offshore Louisiana and Texas form a seaward-dipping and thickening wedge of interbedded marginal-marine sandstone and shallow-marine shale with maximum thickness at any locality of about 25,000 ft. A composite section in the Gulf Coast geosyncline is at least 45,000 ft thick. Rapid sedimentation in large deltas, where there were prolific organic production and accumulation and where the organic material was preserved by rapid burial, made possible the many large Miocene petroleum accumulations. These favorable conditions were confined mainly to the Louisiana coastal and adjacent offshore areas that subsided at a faster rate than the coastal interdeltaic regions on the east and west, and confined the Miocene Mississippi River to that part of the northern Gulf basin. Downward movement along faults that bound the deeply buried salt-filled grabens also took place as the major deltas prograded, causing diapiric structures and rollover anticlines to form where organic-rich deltaic mud, silt, and sand were deposited. The tectonic-sedimentation history of the Gulf Coast Miocene clearly demonstrates the close relation between depositional environments and petroleum occurrence. End_of_Article - Last_Page 866------------

The Bay Marchand Pressure Maintenance Project Unique Challenges of an Offshore, Sea-Water Injection System

The Bay Marchand Pressure Maintenance Project Unique Challenges of an Offshore, Project Unique Challenges of an Offshore, Sea-Water Injection System Extreme formation damage caused by the injection fluid; reservoir sands that broke down under injection; severe corrosion; and mechanical problems all spelled trouble in this large pressure maintenance project. Changes, based on test results, have turned it into a successful sea-water injection system. Introduction In the Bay Marchand Pressure Maintenance Project, one of the largest offshore injection systems in the U.S., sea water is injected at high pressures into deep Miocene sands. The need for pressure maintenance in this field off the coast of Louisiana was first recognized in the early 1960's. Six major reservoirs on the prolific east flank of this large salt-dome field exhibited only limited natural water influx after a period of rapid initial development. The early design of the injection system indicated large basic requirements. Injection volume exceeded 50,000 BWPD and injection pressures were anticipated to be as high as 3,650 psig. The injection wells were 11,000 to 12,000 ft deep. A series of unexpected problems developed soon after pressure maintenance began in 1963. First, reservoir sands, which had been sufficiently competent during the early production life of the field, broke down under injection. production life of the field, broke down under injection. In addition, corrosion and the pronounced pressure-rate effects on down-hole equipment were more pressure-rate effects on down-hole equipment were more severe than had been anticipated. Finally, there was severe formation damage, which later was found to be related directly to the use of sea water as an injection fluid. Description of Reservoirs The six major reservoirs under injection in Bay Marchand represent typical Miocene sand development along the flanks of a piercement-type salt dome (Fig. 1). The reservoirs overlie each other at depths between 8,300 ft subsea and 11,400 ft subsea. They are on the east flank of the structure and have an area ranging from 1,300 to 2,300 acres. Structural dip ranges from 24 degrees near the salt dome to 8 degrees at the original oil-water contact. Average net sand thicknesses range from 6 to 36 ft. Initial reservoir pressures varied from 4,600 to 5,291 psig. All but one reservoir were undersaturated initially. Reservoir temperatures vary from 182 to 197F. While initial GOR's averaged 450 scf/STB, oil gravities were between 21 and 30 degrees API. Since PVT properties varied with depth, small primary gas caps PVT properties varied with depth, small primary gas caps existed and the oil columns were undersaturated at their volumetric midpoints. Oil viscosities ranged from 1.1 to 1.9 cp, indicating favorable mobility ratios. Porosities were uniform and averaged 29 percent. However, permeabilities exhibited wide variations; three reservoirs had geometric-mean air permeabilities of less than 100 md, while the remaining sands had values up to 2,000 md. Initial water saturations exhibited a corresponding variation from 40 to 15 percent. percent. Drilling and Production History Initial development of the project sands began in Sept., 1958, with the completion of S. L. 1424 OCS-0387 S-9. Fig. 1 illustrates placement of the completions in a typical project reservoir. The U, W, X, BB and AA structures are 12-well units. JPT P. 389

Porosity and Permeability of Unconsolidated, Upper Miocene Sands From Grain-size Analysis

ABSTRACT Core analysis data for 78 cores taken from Upper Miocene sands were used to develop correlations between porosity and permeability of unconsolidated cores and their grain-size analyses. The grain-size distributions of these cores are best described mathematically by the Rosin-Rammler equation. The two parameters of this equation together with two other easily measured parameters of grain size were grouped to give correlations with porosity and permeability. Porosities were correlated to within 2 percent for 80 percent of the samples and permeabilities were correlated to within a factor of 2 for 70 percent of the samples.

Techniques for Treating and Completing Water Injection Wells in California

WADE, JAMES E., MEMBER AIME, CITY OF LONG BEACH, LONG BEACH, CALIF. Abstract Various techniques for completion, stimulation and profile improvement of water injection wells in unconsolidated sands have been field tested in the Wilmington field, Long Beach, Calif., since the start of waterflooding in 1953. The major problems confronting the operators are control of sand entry, maintenance of water injection rates and control of water advance into individual sands. Several methods of completing water injection wells include jet-perforated completions and pre-packed and floatpacked gravel liners. The most effective method of controlling sand entry is the float-packed gravel liner. Many methods tested for improving injectivity in water injection wells include acidizing, chemical washes, high rate pressure injection, back flow (drillstem tester), shock treatment with explosives and steam injection. The most effective methods of improving injectivity are high rate pressure injection and back flow (drillstem tester) and the notch and fracturing profiles in injection wells include selective acidizing, high rate pressure with temporary blocking agents, selective back flow (drillstem tester) and the notch and fracturing method. The most effective methods of profile improvement in water injection wells are selective back flow (drillstem tester) and selective acidizing. Introduction The Wilmington oil field, located in Long Beach, Calif., has been under active waterflood since 1953. At the present time, approximately 700,000 BWPD are being injected into 312 water injection wells. Cumulative injection to date amounts to more than 1,300,000,000 bbl. Most of the injection has taken place in the Pliocene and Upper Miocene sands of the Tar, Ranger, Upper Terminal and Lower Terminal zones. These zones consist of unconsolidated sands interbedded with shales and silt stones. The major problems encountered to date are control of sand entry, maintenance of water injection rates and control of water advance in individual sands. From 1953 to the present, many different techniques of completion, treatment and profile improvement have been used. This article presents a description of the techniques which have been used and a summary of the results achieved by each method. A total of 201 water injection wells are covered. Of this number, 76 are aquifer injectors and 125 are in-zone, pattern or line-drive injectors. Completion Methods In general, aquifer injectors were drilled as new wells whereas the in-zone injectors are predominantly converted producers or idle wells redrilled or recompleted. Originally, most of the new and redrilled wells were completed by selectively jet perforating. This method afforded a high degree of selectivity but resulted in severe sand problems. Current practice is to complete all new and redrilled wells with sand control liners. Water was injected originally down the casing of many wells. Excessive corrosion was encountered in subsequent casing surveys. Current practice is to inject water through tubing landed on a packer set at the top of the zone and to treat the water in the tubing-casing annulus with corrosion inhibitors. Selective Completion by Jet Perforating New and redrilled water injection wells were originally completed by selectively jet perforating. Standard practice was to set 9 5/8-in. casing at the top of the zone and establish a water shut-off on the 9 5/8-in. shoe. After drilling to total depth, run 6 5/8-in. liner equipped with 9 5/8 - X 6 5/8-in. top adapter, cement liner and lap, selectively jet perforate and pressure test liner lap and blanks (Fig. 1). Of the 94 wells completed in this manner, a total of 53 had a history of severe sand problems. As pressures increased around the injectors, particularly the aquifer injectors, temporary interruptions of injection plant service resulted in backflow bringing large amounts of sand into the wellbore. Serious problems were encountered in controlling sand entry during repair jobs and sand fill was often found when wells were put back on injection after remedial work. Sand problems are basically caused by the unconsolidated nature of the oil sands, but appear to be aggravated by the tendency of jet-perforated holes to become enlarged by abrasion or corrosion. Photographs of jet perforations taken in a water injection well by special camera equipment showed hole enlargement and casing fractures. Pieces of liner recovered from water injection wells also showed hole enlargement and fracturing. Two methods have been used effectively to combat sand problems in jet-perforated wells. One method is to sand pack the perforations and the other is to backflow the well by drillstem testing. JPT P. 49ˆ

The Stratigraphy and Sedimentary Petrology of Miocene Turbidites in the San Joaquin Valley: ABSTRACT

A thick Miocene marine basinal succession, dominantly sandstone, underlies the southern portion of California's San Joaquin Valley. Deposited in paleontologically defined depths of as much as 5,000 to 6,000 feet, the sands are pebbly and gritty to fine grained, largely angular, poorly sorted, often silty and micaceous, quartzose to arkosic and are interbedded with dark carbonaceous shales. Graded bedding is common and in conjunction with depth estimates is taken to imply turbidity current origin for most of the sands. Early Miocene turbidites spread far southwestward from the Sierra Nevada provenance, but by late Miocene, anticlinal barriers, rising from the sea floor, restricted the turbidites, including the highly productive Stevens sands, to the northeastern side of the basin. These late Miocene sands at first entered from discrete troughs or canyons but later from more widely dispersed sources as shelf sands encroached. Deep basinal transport seems to have been axially northwestward. Locally, thick Stevens synclinal channel sands spread eastward off the rising Temblor Range. Sudden cessation of basinal sand deposition was followed by deposition of chert, shale, and Pliocene neritic sediments. Detailed subsurface correlations show that Stevens sand bodies include sinuous channel fills bounded by major anticlines, sands flanking and covering lower structures, and lobate and branching apron sands in simple homoclinal areas. Compaction structures are shown to control some accumulations and offer clues for continuing exploration. End_of_Article - Last_Page 362------------

West Bastian Bay Field, South Louisiana: ABSTRACT

The large, domal structure at West Bastian Bay field, central Plaquemines Parish, Louisiana, is interpreted as a deep-seated salt dome. A large, east-west striking, south-dipping, contemporaneous normal fault traverses the dome and controls accumulation of oil and gas in multiple upper Miocene sands. At the time of maximum growth along the Bastian Bay fault, sediment was deposited approximately three times as fast in the downthrown block, where most of the hydrocarbon accumulation occurs. The relative thickness of sediments shows that domal uplift, deposition of upper Miocene and younger beds, and movement along Bastian Bay fault were contemporaneous. Reliable electric log correlations together with paleontological data from well samples in the field area, afford excellen data for a detailed study of contemporaneous normal faulting, a type of faulting common to Miocene sediments of the Gulf Coast and important to exploration for oil and gas. Microfaunal and lithologic data from conventional cores through productive intervals show that the R and S sands were deposited predominantly in nonmarine environments. These sands in turn are separated by dense homogenous gray-black shares, deposited in marine environments equivalent to those existing on the modern continental shelf. Production has been established in 20 sands ranging in depth from 8,677 to 15,305 feet. End_of_Article - Last_Page 351------------

Some Aspects of Oil Exploration in California

Today, many of the industry9s critical problems result from an oversupply of relatively cheap oil because, on a worldwide basis, recent exploration has been too successful. California has had a glorious role in this petroleum exploration for a period of nearly 100 years. During most of this time it has ranked as the first or second oil-producing state. Furthermore, it has been a substantial foreign exporter of crude oil and products. The state9s production history is characterized by substantial annual increases up through 1953, and an annual decline since that year. The annual discovered reserves during this same period, however, show great fluctuations; since 1940 the annual discovered reserves have been relatively small and much below annual production. The principal oil-producing areas of California are the San Joaquin, Los Angeles, Ventura, Santa Maria, and Cuyama-Salinas basins. To the end of 1961, the 295 oil fields in the state have produced about 12.3 billion barrels of crude. The changing exploration methods are illustrated by the discovery of 6 selected oil fields. The Midway-Sunset field was discovered in 1901 by drilling near oil seeps. The Ventura Avenue oil field discovery in 1916 marked the early application of surface geology and the anticlinal theory. The Santa Fe Springs field in 1919 is important as the first discovery attributed to the geomorphologic concept of domal structure being reflected in alluviated surface topography. The 1936 Wilmington field discovery was the result of the early use of the seismic reflection method. This field is also famous as the world9s largest water-flooding operation. The Russell Ranch field discovered in 1948 exemplifies the combination of surface and subsurface geology. The Wheeler Ridge oil field discovered in 1922 in shallow Miocene sands was rediscovered in 1952 in Eocene sands below a subsurface thrust fault, an example of success by subsurface geology and deeper drilling. Present oil exploration is high in state offshore areas partly because of new techniques for drilling and completing wells in water. All petroleum geologists are challenged to find petroleum reserves at competitive costs, to contribute to the science of geology and its applications, to advance the professional competence of geologists, and to contribute to the economic prosperity of our states and our nation.

Petroleum Developments in Mexico in 1960

A new mark was set by Petroleos Mexicanos with the drilling of 762 wells during 1960, this being a considerable increase over the 441 wells drilled during the preceding year. An all-time high for Mexico amounted to 5,273,314 ft., drilled with an average of 6,920 ft. per well. Of the total number of wells drilled, 176 wells were classified as exploratory holes, of which 87 were new-field wildcats resulting in the discovery of 15 new oil and (or) gas fields. Other exploratory holes were classified as follows: 21 new-pool wildcats, 11 deeper-pool wildcats, 8 shallower-pool wildcats, and 49 extensions, totaling 89 exploratory wells of which 61 were completed as producers. Of the total 762 wells drilled, 582 were completed as producers. The new fields discovered were located as follows: 2 in the Eocene and 2 in the Oligocene trends in Northeastern Mexico, 5 in Cretaceous formations in the Tampico Embayment; 5 in Miocene sands in the Isthmus and Tabasco region, and one outstanding discovery in Cretaceous limestones in the foothills of the Sierra Madre, south of the Saline Basin in the Isthmus region. Surface geological and geophysical exploration activities were concentrated in the coastal plain of the Gulf of Mexico although some exploration was also carried on in the Cretaceous trends in Northeastern Mexico in the state of Coahuila; seismological exploration was continued in the Sebastian Vizcaino Embayment in Baja California, and systematic gravity-meter surveys were made in north-central Chihuahua and in eastern Quintana Roo. Crude oil and distillate production in 1960 was 108,771,585 bbls., an increase of 9.7% over the previous year. Total gas production was 341,266,000 MCF with an increase of 9.6% over 1959.

Petroleum Developments in Mexico in 1959

Four hundred forty-one wells were drilled in Mexico during 1959 as compared with 379 drilled the preceding year. The average depth per well was increased to 7,035 ft. as compared with an average of 6,958 ft. per well during 1958. During the year of 1959, 133 wells were classified as exploratory holes, of which 82 were new-field wildcats, resulting in the discovery of 11 new gas and oil fields. Other exploratory holes were classified as follows: 9 new-pool wildcats, 9 deeper-pool tests, 8 shallower-pool tests, and 25 extension wells; 31 of these exploratory holes were completed as producers. Of the total number of wells, 298 were successful. The new fields discovered were located as follows: 1 in the Eocene trend in Northeast Mexico, 5 in Cretaceous and Jurassic limestones and calcarenites in the Tampico Embayment, and 5 new fields in Miocene sands in the Isthmus and Tabasco region, one of which is an off-shore prospect. The main exploratory effort, as in previous years, was concentrated along the coastal plain of the Gulf of Mexico where all the producing fields are located; however, seismic work in Baja California and gravity work in the Yucatan Peninsula and Northeastern Chihuahua were continued. One test was drilled to the Cretaceous in Northeast Mexico, and 5 tests were drilled to explore the productivity of the Upper Jurassic and Lower Cretaceous formations in the Tampico Embayment. In the Veracruz Embayment, as in the past year, drilling activities decreased considerably as only 4 wells were drilled in search of oil: 2 were drilled to the Middle Cretaceous, as yet unproductive in this area and 2 to the Eocene and Oligocene. Crude oil and distillate production in 1959 was 105,758,473 bbls., an increase of 9.5% over the previous year. Total gas production was 329,363,504 MCF, an increase of 79.7% over 1958.

Gravel Packing Controls Unconsolidated Sand in Venezuela Field

Abstract Sand control has been the major problem encountered in producing oil from the unconsolidated Miocene sands in the Lagunillas area of Venezuela. One of the first completions developed to prevent excessive sand production was the combination oil string in which pre-perforated casing was employed. In most cases this method was unsuccessful in controlling sand and was replaced in 1951 by a special slotted liner completion. The slotted liner technique has been effective in controlling sand and in obtaining high volume producers in the Bachaquero sand member. However, as a satisfactory completion depends upon the ability to wash the well into production outside the liner, this technique will soon become obsolete because of the declining reservoir pressure in the Bachaquero field. A program to evaluate gravel packing as a replacement for the slotted liner technique (see Fig. 1) and to provide a sand control method for use inside existing pre-perforated completions was initiated in April, 1956. Forty-three wells have been gravel packed in the Lagunillas Dist. through Sept. 25, 1957, with two jobs considered as failures. Thirty of these wells are producing at an average rate of 520 B/D of 12 to 180 API gravity crude as compared to 268 BOPD for the average offset well. Eight wells are awaiting installation of production equipment and are expected to be satisfactory producers when opened to production. Various problems concerning fluids, liner slot sizes and loss of gravel to the formation have been encountered. Solutions to these problems have been found and procedures for both open-hole and inside gravel packs have been developed that can be applied with confidence to the sand control problems that exist in the Bolivar coastal fields. Introduction A program to evaluate the applicability of gravel packing as a sand control method to wells in the Lagunillas Dist. was initiated in April, 1956.

A Review of the Production Performance of Three Deep Miocene Oil Pools in the Los Angeles Basin

Abstract A review is presented of the production performance of the City zone of the Inglewood city pool, Potrero field; the Wardlow pool of the Long Beach field and the Santa Fe zone of the Santa Fe Springs field. Production is from thick sections of Miocene sands with air permeabilities from 10 to 100 md. The pools have produced at near capacity rates from early in their history; oil recovery to date has been primarily from pressure depletion. Maximum gas-oil ratios were reached at recoveries of 46 to 58 per cent of the gas originally in place and 6 to 10.5 per cent of the oil originally in place. Early oil rate vs oil recovery trends indicate 13.5 to 23 per cent ultimate oil recovery. The Wardlow pool is now producing primarily by gravity segregation and considerably higher ultimate oil recovery is foreseen than was indicated front earlier performance. From a depletion standpoint, the substantial oil recovery following maximum gas-oil is largely due to permeability and mobility ratio variation within the thick section. Introduction This paper presents a review of the production performance of three deep oil pools in the Los Angeles basin, Calif., which produce from thick sections of Miocene sand in the low permeability range. The pools are the City zone of the Inglewood city pool, Potrero field, the Wardlow pool of the Long Beach field, and the Santa Fe zone of the Santa Fe Springs field. The location of these pools within the basin is shown in Fig. 1. In reference to the central area of the city of Los Angeles, the Inglewood city pool is 8 miles to the southwest, the Wardlow pool 18 miles to the south, and the Santa Fe Springs field 12 miles to the southeast. This paper is in the nature of a case history of these pools with the purpose of (1)describing the accumulation, (2)reviewing the oil and gas production performance and the indicated oil recovery efficiency, and (3)comparing the behavior and recovery experience of the three accumulations.

Developments in Louisiana Gulf Coast in 1957

Again in 1957 activity in the Louisiana Gulf Coast was greater than in the preceding 5 years. In all, 2,317 tests were drilled, 845 of which were exploratory tests (33.8% successful) and 1,472 of which were development wells (79.2% successful). Oil production showed an increase of 11% during 1957 and gas production an increase of 14%. However, the 55 new-field discoveries indicated a decrease of 23.6% from the 72 new fields found in 1956. Montegut, Terrebonne Parish, is the most important new-field discovery. The southward extensions of the Bastian Bay field, Plaquemines Parish, were the most important onshore developments. The new-pool discovery at Ship Shoal Block 28 constituted the most significant addition to offshore reserves. There were also 169 new pools and 62 ext nsions to known fields discovered in 1957. Seismic activity during 1957 showed a decrease of 8% from the previous year. Reflection seismograph was used in the discovery of 54 of the 55 new fields in the Louisiana Gulf Coast. There was an increase in the use of subsurface geology and the core drill. Gravity activity continued to show a slight decrease in 1957. Miocene sands were the objectives of the majority of the exploration effort. Terrebonne Parish was first with ten new-field discoveries. The average depth of successful new-field wildcats was 12,660 feet. Federal and State leasing of offshore lands in the disputed zone has been discontinued pending the settlement of the United States-Louisiana tideland controversy.

Racetrack Hill Anticlinal Trend, Kern County, California: ABSTRACT

The Racetrack Hill anticlinal trend, approximately 7 miles east of Bakersfield, Kern County, consists of an area 10 miles long and one mile wide. On it are three oil fields of moderate economic importance--Racetrack Hill, Graham, and Jeppi--that have produced approximately 10,000,000 barrels of high-gravity oil from lower Miocene sands. The Racetrack Hill anticlinal trend plunges approximately 500 feet per mile southwest which is almost perpendicular to the main structural trends in this part of California. It can be traced in the lower Miocene sediments as far as North Mountain View. Seismic data suggest that it probably extends southwest. The anticlinal structure, limited in general to the lower Miocene sediments, upward becomes less pronounced, and, in one place is displaced by a broad syncline in the younger sediments. Production along it is caused by actual domal closure in the Racetrack Hill oil field. Graham and Jeppi have been caused by cross-faulting in conjunction with nosing. This structure is bounded on the east by a major, possibly pre-middle Miocene fault having maximum vertical displacement of 2,000 fe t. The lower Miocene in this area is represented by a series of sediments ranging in thickness from 1,500 feet at outcrop to at least 4,000 feet in the vicinity of the North Mountain View area. The Nozu in this area reaches a maximum thickness of more than 400 feet in the Graham area where it consists mostly of a series of very coarse conglomerates. The underlying Freeman is a dark brownish gray siltstone. Beneath this the lower Miocene productive zones occur--the Jewett consisting of a series of siltstones and permeable sands having maximum thickness of 250 feet, the Pyramid Hill sand, a 20-foot ash bed beneath this characterized by a basal grit believed to be the base of the Saucesian stage, and the underlying probably Zemorrian stage sediments that are referred to as Vedder except whe e they grade into the non-marine Walker series. The Walker is non-productive. End_of_Article - Last_Page 217------------

Peripheral Faulting at Bayou Blue Salt Dome, Iberville Parish, Louisiana

The Bayou Blue field is on an intermediate-depth salt dome, where shallow oil in Pliocene and Miocene sands was discovered in September, 1929. The initial productive area, located on the apex of the dome, was considered depleted in 1932. First significant production from Miocene sands on the west flank was established in February, 1940. This led to active development of the northwest, west, and southwest flanks of the dome and re-establishment of shallow production on the crest. East-flank production from lower Miocene sands was first obtained in 1941. Deep Oligocene sand oil was discovered in 1954 on the northeast flank, but appears to be non-commercial. Through December, 1955, 13,108,421 barrels of oil had been produced. The dome is elliptical in outline and is characterized by peripheral faulting, which generally parallels the elongate axis of the dome. These faults, which are downthrown away from the salt plug, change direction, producing an arcuate or sinuous trace on any particular datum. They may join the salt face with depth or along strike of the salt mass. The dominant peripheral fault of Bayou Blue offsets lowermost Miocene beds, which are present on the apex of the dome, to a position 4,600 feet structurally lower on the northwest flank of the dome. The major producing area of the structure is located southwest of the dome's crest on the downthrown side of this peripheral fault zone in beds of Miocene age which terminate abruptly against the steep salt face. A system of complex radial and co plementary faulting is present in the shallow beds above the apex of the plug. Contoured fault maps are included of all important radial and peripheral faults. The over-all structural aspects of the dome are illustrated by an upper Miocene (Bigenerina 3) map and a lower Miocene (Siphonina davisi) map and six electric-log structural cross sections. Nineteen typical reservoirs encountered in the Bayou Blue field are included, to illustrate the local structural conditions and productive areas.

Castaic Hills Oil Field, Los Angeles County, California: ABSTRACT

The Castaic Hills field is located in Los Angeles County northwest of, and adjacent to, the Honor Rancho field. It is believed to be completely separate from the latter field both from a structural and stratigraphic standpoint although only one location separates the two areas. The field was discovered by Ted Sterling, operator for Paul W. Trousdale's Rynne-Fisher well No. 1 (now Continental Oil Company's well), which was completed on September 13, 1951, from the interval 4,632-4,697 feet, flowing 233 b/d, 33° gravity, 0.1% cut, 27/64^Prime bean, 90# T.P., 485# C.P., and 185 MCF. As of September 30, 1952, 29 wells have been completed in the area, 5 wells abandoned, and several wells are still drilling. The stratigraphy in the field is characterized by the great thickness of conglomerate and abrupt facies changes. The general geologic section above the basement granite consists of the following. 1. 1,400-2,700 feet of non-marine Saugus (Pleisto-Pliocene) conglomerate, sands, and clays 2. 1,400-1,000 feet of marine Pico with possibly some Repetto at base (Pliocene) conglomerate, sands, and siltstones 3. 6,500± feet of Modelo upper and middle Miocene sands, conglomerate, and shales, of which there are: a. 50-200 feet of Delmontian conglomerate and siltstone b. 1,700-2,500 feet of upper Mohnian conglomerate and sand c. 4,500± feet of lower Mohnian shales, conglomerates, and thin sands The producing sand (Sterling zone) is 30-220 feet thick and occurs in the uppermost part of the lower Mohnian or in basal upper Mohnian. Tar sands occur in the Saugus and Pico formations. The field is on the steeply dipping south flank of the east-west Loma Verde (Devils Canyon) anticline, the surface axis of which is ½ mile north. The discovery well was drilled on the assumption that sands coming up toward the north on this flank would either pinch out or be faulted in such a manner that north and west closure would occur. It was expected that east closure should be provided by the large northwest-trending San Gabriel fault. This is in general what has been proved, although numerous faults made complications. It now appears that the closure on the west is caused by facies change, closure on the east by faults probably related to the San Gabriel fault, and on the north by both faulting and facies change, although this is not definitely determined. The field contai s fault blocks which affect accumulation. The field, which is producing about 4,340 b/d (August average), is composed of about 280 proved acres with possibly 50 additional definitely proved acres to be drilled. However, with very little End_Page 185------------------------------ imagination, one can visualize the field being twice its present size. Also there are possibilities of deeper producing sand or sands being present and the shallow tar zones being produced. End_of_Article - Last_Page 186------------

Geology and Exploration for Oil in the Huasna District, San Luis Obispo County: ABSTRACT

The Huasna district, an area of approximately 100 square miles, lies at the southern end of the Santa Lucia Range in the California Coast Range province about 12 miles northeast of the town of Santa Maria. Geologically it consists of a synclinal basin filled with Miocene sediments and interbedded volcanics. The basin is roughly limited on the east and west by two nearly parallel faults. On or near these boundaries Miocene strata are found in fault or depositional contact with Franciscan rocks on the west and Cretaceous sediments on the east. Anticlines have formed on the flanks of the major syncline. Middle and upper Miocene (Monterey) shales and sands crop out along the eastern flank of the syncline. Basinward they are overlain by 2,000 feet of Santa Margarita sands and shales. Wells drilled within the deeper portion of the basin penetrate 4,000-6,500 feet of brown cherty and siliceous shales and dark brown calcareous shales representing all the foraminiferal stages from upper Mohnian to Relizian. Shows of tarry oil occur throughout this interval both in outcrop and in wells, probably accounting for many of the shows of oil recorded by early tests in the district. At and throughout the basal portion of this predominantly shale section volcanic interbeds of tuff, agglomerate and ashy sands of middle and lower Miocene (Saucesian ?) age are encountered. Incomplete records on earlier wells and lack of deep stratigraphic penetration in more than one well near the center of the basin lead to some conjecture as to the nature and distribution of lower Miocene sediments. Thirty-five wells have been drilled in the Huasna district since 1898. Two or three wells have produced a small amount of oil. The Barneberg No. 2, drilled on the Tar Springs anticline, has produced 11,400 barrels of 16 degrees A.P.I. oil, which appears to have come from near the Santa Margarita-Monterey gradational contact and from within the underlying locally fractured shales. Recent wells drilled nearby failed to develop production. The possibilities of stratigraphic traps at depth within the basin and of better structural position on some of the asymmetric anticlines are indicated as being the objectives of future exploration in the district. End_of_Article - Last_Page 2630------------