Sand-shale Sequences Research Articles

Deep Tuscaloosa Gas Trend of South Louisiana: ABSTRACT

The deep Tuscaloosa gas trend of south Louisiana is one of most significant exploration plays in United States in recent years. This trend, productive from an expanded Tuscaloosa sand-shale sequence of Upper Cretaceous age, covers a band approximately 30 mi (48 km) wide and 200 mi (322 km) long, from Texas line on west and extending past Lake Pontchartrain on east. Regional studies begun by Chevron in 1964 demonstrated probability of an unexplored sedimentary section lying just south of Lower Cretaceous carbonate bank edge which crosses south Louisiana. Improved regional seismic data later verified presence of such a unit, termed the wedge, located between reflectors identified as Upper Cretaceous chalk and Lower Cretaceous carbonates. The discovery well of Tuscaloosa wedge was drilled in False River area in May 1975, when Chevron tested 20 MMCFG/D from a sand at 19,800 ft (6,035 m) in 1 Alma Plantation, 15 mi (24 km) northwest of Baton Rouge. Chevron confirmed trend with a discovery in December 1975 at Rigolets field, 125 mi (201 km) southeast of False River field. The productive section of Tuscaloosa is interpreted to be a shallow-water deposit built by progradation southward across Lower Cretaceous carbonate bank edge. Down-to-the-south faulting in this expanded section, together with deep salt movement, has produced most of structural features that are now productive from Tuscaloosa. One hundred and fifteen exploratory wells have been completed along Tuscaloosa trend, resulting in discovery of 19 fields. Several apparent discoveries are currently being tested. Proved plus potential reserves discovered through May 1981 are estimated to be approximately 5 TCF. This reserve estimate should increase significantly with continued drilling. End_of_Article - Last_Page 2467------------

Major Structural and Stratigraphic Features of Anadarko Basin: ABSTRACT

Abstract The Anadarko basin of western Oklahoma and the Texas Panhandle continues to be one of the most active and prolific petroliferous provinces of the continental United States. More than 150 companies and an equal number of independent geologists are actively engaged at the present time in the exploration for additional oil and gas reserves in this Mid-Continent basin. The sedimentary sequence in the Anadarko basin is represented by a wide variety of lithologic units ranging in age from Cambro-Ordovician through Permian. Important reservoir rocks are present and proven in each of these major systems. Regional facies changes from dense limestones to porous dolomltes, from porous sandstones to tight limestones, and regional pinchouts of sandstones in sand-shale sequences all provide the necessary trapping mechansims for the accumulation of hydrocarbons. In addition, three major unconformities truncate downdip reservoir rocks to create long regional trends of oil and gas production. The possibility of discoveries of additional trends of this nature is considered excellent as demonstrated by current industry activity. The southern boundary of the Anadarko basin is formed by the Amarillo-Wichita Mountain Front fault system. This fault system is characterized by substantial vertical block uplift and regional left-lateral strike-slip movement. The combination of these two Pennsylvanian-age tectonic movements creates a complex zone of tensional block faulting, compressional overthrusting, step faulting, and vertical dipping formations.

Gravitational Compaction and Abnormal Fluid Pressures: ABSTRACT

Pressures and fluid movements which occur over geologic time in compacting sand-shale sequences, both during and following deposition, are modeled. Improvements and accuracy limitations on such models will be discussed. End_of_Article - Last_Page 1424------------

Thermodynamics of Salinity Changes Accompanying Compaction of Shaly Rocks

Abstract When a clay or shale with fixed cation exchange capacity is saturated with salt water and the solid matrix is slowly squeezed, so that equilibrium is maintained between the remaining pore water and successive increments of squeezed-out water, these successive increments will contain salt of decreasing normality L N = --- [1 - (n/2L)2], 2 provided the water is conducted away from and out provided the water is conducted away from and out of diffusional contact with the clay as it is produced. Here, n is the cation exchange capacity per unit pore volume and L is a constant determined so that pore volume and L is a constant determined so that this equation correctly relates the initial concentration of solution in equilibrium with the clay, No, and the initial exchange capacity per unit pore volume, no. The pore water remaining in the clay or shale at any point in the squeezing process will contain positive and negative ions of normality: 1 N = -- [L n + n2/4L). 2 In the pores, the positive-ion concentration increases steadily while the negative-ion concentration and N decrease to zero for n 2L. The squeezed-out pore water, if collected and mixed, will contain pore water, if collected and mixed, will contain salt of decreasing normality: 1 N = ---- [L - non/4L]. 2 In deriving these equations, it is assumed that the ratio of activity coefficients of salt inside and outside the porous material is unity, and that there is no association between cations and either anions or exchange sites. Association of cations and exchange sites is treated briefly. Approximations used are thatan increment of salt water passing out of the porous medium does not change volume andthe matrix material does not compress during compaction. The process must be carried out so slowly that the changing porosity and salinity remain uniform throughout the porous material. The given thermodynamic results correspond to a common experiment in which a water-saturated clay cake is compressed and the squeezed-out water is conduced away through a short capillary of minimal volume and dropped into a receiver. The results also approximately describe some geologic situations in which compaction water from shales drains into comparatively thin sands that conduct the water away. Introduction A number of authors have reported progressive changes in the salinity of water squeezed out of clay cakes. The trend of the data is for the salinity of the squeezed-out water to decrease generally as the porosity is reduced. Chilingar et al. reported that the salinity decreases if the compaction is very slow, but can be made to increase if the compaction pressure increases abruptly. Experimental objectives have been to understand salinity changes in shales and sands in geologic settings. Knowledge of expected salinity changes can be applied to quantitative interpretation of electric logs, to interpretation of the direction of hydrodynamic flow over geologic time in compacting sand-shale sequences and to determining whether the more rapid water influx into producing petroleum reservoirs may have come from surrounding shales. Fowler has interpreted detailed data from the Chocolate Bayou field, Brazoria County, Tex., in terms of the last two phenomena. Patchett has shown that logged shale conductivities in wells from a number of sedimentary basins, when converted to a common temperature basis, fall within a narrow range for any given porosity. This is in accord with a finding here that ion concentrations in compacting shales should evolve to values depending on cation exchange capacity but not on the initial salt concentration in the depositional environment. SPEJ P. 377

Water Expulsion from Clastic Sediments during Compaction--Directions and Volumes

In an interbedded sequence of sand and shale, most compaction water would move horizontally from the basin center to its edges. The cumulative volume of water that has been expelled from, and moved through, sediments increases with the horizontal distance of migration. This volume also increases for the same horizontal distance with increase of burial depth or compaction. In thick shales unbroken by sandy zones, the main direction of water movement is vertically upward. In a vertical-movement model, the cumulative-water volume gradually increases with depth to a maximum at intermediate depths, then gradually decreases toward the base of the sedimentary column. The cumulative-water volume in this case generally is smaller than in the horizontal model with relatively long migration distance. The Tertiary sequence in the Gulf Coast area may resemble a third model, which combines features of the other two in that it consists of an upper interbedded sand-shale sequence (horizontal migration) and a lower monotonous shale sequence (vertical migration). The depth of the boundary between these two zones varies, ranging probably from 3,000 to 15,000 ft (900 to 4600 m) over all. A combination plot of the water volumes corresponding to the horizontal- and vertical-migration models would, therefore, simulate the volumes of water movement in this area; the cumulative-water volume increases rapidly toward the base of the interbedded zone, and then decreases in the underlying shale zone. It is interesting to note that these expelled-water volume plots resemble the oil-production freque cy plots constructed by Burst for this area. The similarity may suggest that explusion and movement of water in sediments is of primary importance in hydrocarbon occurrence.

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

Evaluation of Shaly Sands With Low Deliverability

Abstract Historically, wells encountering only shaly sands with low deliverabilities have been abandoned as dry holes, and exploration for such reservoirs has been considered uneconomical. With an increasing demand for hydrocarbons, however, shaly reservoirs such as the Second White Specks, Milk River, Medicine Hat and Belly River of southern Alberta and Saskatchewan, formerly considered uneconomical plays, have now become sought-after prospects. Evaluation of these very shaly reservoirs has proved to be neither simple not straightforward. Systems normally used for exploration and evaluation (logs, cores, drill-stem tests) were designed for clean sands with high deliverabilities. All these system have been hampered by the shale content of the sands. Recently developed methods of log analysis can define and adjust for shaliness effects. After adjustment for shaliness, the logs are capable of supplying such information on the reservoir thickness, hydrocarbon content, hydrocarbon type and identification of producible zones. Available logging programs and their interpretation, including an adjustment for shaliness, are discussed in this paper. The manner of interpreting logs, in the above shaly formations is developed in the discussion of the field examples, and the results of log interpretation are compared to the results of Core analysis and production tests. Introduction THE Second White Specks, Medicine Hat, Milk River and Belly River sand formations have several common characteristics. They extend from southwestern Saskatchewan through the Alberta plains as shalysand reservoirs with proven productivity. Generally their deliverability is low - less than 1 MMcf/D or 50 BOPD. Evaluation of these shaly sands is complicated by large variations in shale content, variable lithologies and low permeabilities. Current logging equipment and recently developed log interpretation techniques are capable of providing rapid, reliable evaluation of these zones. INTERPRETATION OF SHALY FORMATIONS The readings of many logs are affected by shaliness. The shalier a sand, the greater the effect. The formations named in the preceding paragraph can be productive with up to 50 per cent (by volume) of shale. Before any meaningful evaluation of these reservoirs is possible, a shaliness adjustment must be made. Shale, as seen by logs, consists of two components, silt and clay.(1) Silt is a very fine-grained lime, quartz, dolomite or other material that has infinite resistivity and may be radioactive. Clay is a hydrated mineral that is usually radioactive and has a low resistivity due to its ion-exchange properties. Both of these shale constituents affect log readings. Assuming the source rock to be sandstone, shaliness will cause the effects listed in the following table. (Table in full paper) In addition, the sonic and neutron logs are affected in sand-shale sequences by gas, which causes the sonic to read high and the neutron to read low. Lack of formation compaction also causes the sonic to read high. Log readings must be adjusted for shaliness effect, presence of gas, lithology and compaction before they can be used for accurate analysis. In the following examples, it is shown that an interpretation based on a single porosity log or a gamma-ray neutron log is not adequate for shaly formations.

Using CNL-FDC Logging To Distinguish Oil, Water, and Gas Zones-Texas Gulf Coast

The use of the dual-spacing neutron log (CNL) with the compensated formation density log (FDC) in a sand-shale sequence provides valuable reservoir fluid information. As confirmed by subsequent testing, this combination has been highly reliable along the Texas Gulf Coast in differentiating the reservoir fluids. Introduction To reduce the cost of completing new wells and of working over existing wells, it is imperative to know the poison of oil-, gas-, and water-bearing horizons in the wellbore. For many years the logging industry could assist the operators by predicting the presence of only hydrocarbons or water in a formation. The forecasts from log analysis were not so specific as desired in distinguishing between oil and gas and often differed considerably from the results obtained when the zones were tested. In recent years, because of great advances in logging techniques, actual results have more closely approached the predictions based on log analysis. The role of one of these advances, the CNL-FDC log combination, will be discussed in further detail. The use of the dual-spacing neutron log (CNL) with the compensated formation density log (FDC) in the sand-shale sequence provides valuable information regarding the type of fluid in the zone of interest. If one has a good concept of the fluid present, he can make the best economical decision present, he can make the best economical decision regarding a completion attempt and the type of completion to be made. The CNL-FDC logging combination has been very reliable along the Texas Gulf Coast in identifying the actual reservoir fluid, with identification subsequently confirmed by actual testing. In the sections that follow are cited 12 case histories of well completions in which the CNL-FDC combination was used. The cases represent fields scattered along the entire length of the Texas Gulf Coast and constitute about 15 percent of Texaco's CNL-FDC logging runs in this area. The case histories illustrate that the CNL-FDC logging combination is valuable for identifying gas/ oil and water/oil contacts, thus insuring against perforating gas- or water-bearing zones unknowingly. perforating gas- or water-bearing zones unknowingly. In the light of experience it is evident that if they differ on a specific interval, the combination log is more reliable than the sidewall core. Application of Combination CNL-FDC Logging Texaco uses the CNL log in conjunction with the FDC log primarily to identify the current gas/oil contact in a newly drilled well. This has been especially successful in several salt dome fields along the Texas Gulf Coast. Such fields are characterized by steeply dipping sands divided into many fault block with varying gas/oil contacts. The wells are drilled to develop the oil column, and the exact location of the gas/oil contact is very difficult to predict before drilling the well. The CNL-FDC log has proved to be a superior means of evaluating the sand in open hole. The determination of the pressure of gas or oil by this logging technique has successfully resulted in sidetracking wells to encounter the oil column. JPT P. 990

Successful Stimulation of a Thick, Low-Pressure, Water-Sensitive Gas Reservoir By Pseudolimited Entry

Thick, water-sensitive gas reservoirs with very low pressures and permeabilities are especially difficult to exploit. Nonetheless, a permeabilities are especially difficult to exploit. Nonetheless, a pseudolimited-entry technique been successful in stimulating such a pseudolimited-entry technique been successful in stimulating such a reservoir in northwestern Colorado. The method incorporates liquid carbon dioxide in a fracture fluid consisting of two percent potassium chloride in fresh water. Introduction With an increased demand for natural gas, operators in the Rocky Mountain region are devoting more attention to certain gas-bearing Tertiary and Cretaceous formations in the area - formations that, until the past 15 years, had been largely considered non-commercial. Typical of these are reservoirs occurring in the Green River, Wasatch, Mesa Verde, Mancos and Dakota sequences and their geologic equivalents throughout the region. Portions of these formations are often thick and porous enough to contain substantial gas reserves, but are also so impermeable that payout of well expenses is long or impossible without effective stimulation. To make matters worse, formation pressures are frequently less than 1,000 psi and the reservoir rock may be susceptible to damage from extraneous water. Fortunately, the advent of air drilling and improved hydraulic fracturing techniques has corresponded to the expanding gas markets, and these innovations are largely responsible for the success to date in providing commercial gas completions in these formations. providing commercial gas completions in these formations. They are not cure-alls, however, and billions of cubic feet of potential reserves will be untapped until new or improved stimulation techniques are developed. To this end, stimulation by chemical and nuclear explosives has gained attention. Continental Oil Co. owns or operates leases on considerable acreage located on the Douglas Creek Archin Rio Blanco County, northwestern Colorado (Fig. 1). in the early 1960's, the company began working to perfect a hydraulic fracturing technique applicable to Mancos "B" formation gas wells in the area. The Mancos "B" reservoir rock not only has low permeability but also is thick, water-sensitive, and of permeability but also is thick, water-sensitive, and of subnormal pressure. By applying principles only recently developed, these problems were overcome with a pseudolimited-entry fracturing technique, which is pseudolimited-entry fracturing technique, which is discussed here. The Mancos "B" Reservoir For the most part, the Cretaceous Mancos formation consists of a gray to black bentonitic marine shale, and on the Douglas Creek Arch it is about 4,000 ft thick. Somewhat below midway through the formation, the shale becomes thinly laminated with a very fine-grained, argillaceous, quartz sandstone containing 10 to 20 percent carbonates. This sand-shale sequence, which is about 400 ft thick, has been termed the Mancos "B" zone at Douglas Creek and is gas-productive on the Central Arch. Fig. 2 shows a section of typical Mancos "B" core. The top of the Mancos "B" is encountered 2,000 to 3,000 ft below the surface, depending on structural position and surface elevation. The average effective permeability over the 400-ft gross interval is about 0.7 md, with porosities of 10 to 11 percent and 50 percent water-saturation as determined from core data. Significantly, the reservoir pressure is an abnormally low 437 psia (0.17 psi/ft). In addition, the formation rock is extremely susceptible to damage from extraneous fluids. JPT P. 185

Log Analysis of Sand-Shale SequencesA Systematic Approach

Poupon, A., Poupon, A., Schlumberger Technical Services Clavier, C., SPE-AIME, Schlumberger-Doll Research Center Dumanoir, J., Schlumberger-Doll Research Center Gaymard, R., Schlumberger Technical Services Misk, A., SPE-AIME, Schlumberger Well Services A primary feature of this interpretation method is that it uses all the logging data in a coherent manner. The formations are analyzed for clay, shale, quartz, water, hydrocarbon content, and changes in sand-grain mineralogy. Even where hole conditions are adverse, reliable results can be achieved through extensive crosschecking for likeness. Introduction During the past 7 years methods have been developed for interpretation of clean and shaly sands using combinations of sonic, density, and neutron logs, along with resistivity and auxiliary logs. Corrections for the presence of light hydrocarbons in the formation, which affect the log readings of the sonic, density, and neutron logs, were also developed. For these methods the shale parameter values are either assumed or deduced from the log readings in adjacent shale beds. This is satisfactory as long as the shales have uniform properties. Frequently this is not so, and the log properties. Frequently this is not so, and the log analyst is faced with determining the properties of the shales occurring in the shaly sands. Intuitively it would seem that sands and shales deposited in sequence during a continuous sedimentation cycle should possess logging properties related to their common geological background. The study of neutron and density logs made in sand and shale sequences has substantiated this. From this study a conceptual model of shales and shaly sands has evolved that is consistent with geological considerations as well as logging tool responses, and in turn has led to the interpretation method described here. The method makes maximum use of all the following logs: neutron, density, resistivity,* gamma ray, SP, microresistivity, sonic, and caliper. Some of these logs may be omitted (microresistivity, sonic, caliper, and either SP or gamma ray); however, doing so decreases the reliability of the results. Formation clay content is determined from several clay indicators and the formation is analyzed for shale, quartz, water, hydrocarbon content, and changes in sand-grain mineralogy. In favorable cases an estimate of hydrocarbon density is made. The associated computer program, SARABAND, solves the interpretation, crossverifies the input data and results and determines automatically many of the required parameters. The interpretation results of main interest are listed in special tabulations and displayed on a film especially coded for easy identification. The Sand and Shale Models Fig. 1 is a neutron-density frequency crossplot generated by a computer. The plotted values of andD, are the apparent porosities from neutron and density logs. Each of the one- or two-digit numbers on the plot represents the total number of readings, over a 390-ft interval in a sand-shale sequence, having the values of N and D, corresponding to the location of the number. The distribution shown on Fig. 1 is typical of sandshale sequences. JPT P. 867

Sedimentary Structures in Ilhas and Sao Sebastiao Formations (Cretaceous), Reconcavo Basin, Brazil

The Ilhas and Sao Sebastiao Formations of Cretaceous age represent a part of the Mesozoic section in the Reconcavo Basin, Bahia, Brazil. This basin is an asymmetrical graben. The two formations form a thick sequence of interbedded lutites and very fine-grained arenites. Conglomerates are locally prominent and carbonates are present as concretions and cement. Sedimentary structures include lamination, asymmetrical ripple marks, cross-lamination, and cross-stratification on several scales, directional and non-directional substratal markings, including flute casts, groove casts, and load casts, and convolute bedding. Interstratal crumpling, pull-aparts, and distortion are locally prominent. In general, the sediments and structures resemble those found in sequences, but graded bedding is lacking. The orientation of fold axes in slumped beds, the areal geology, and the geometry of the formations indicate that the paleoslope dipped west. The most abundant paleocurrent indicators, ripple marks and cross-stratification, indicate a southerly paleocurrent which flowed parallel with the contours of the paleoslope. Substratal markings such as flute casts and groove casts trend parallel with the paleocurrent direction and do not indicate the dip of the paleoslope. Whereas many structures, particularly substratal markings, are identical to those in sequences, the lack of graded bedding and the textural, compositional, and structural similarities of these rocks to those of the modern Mississippi Delta indicate that the Reconcavo Basin rocks were of deltaic, rather than of turbidity-current, origin. Review of the turbidity-current literature suggests, to the writers, that graded bedding may be the only valid criterion for differentiating turbidites from non-turbidites. The indiscriminate application of the term turbidite to sand-shale sequences where graded bedding is indistinct or lacking only serves to divert the geologist from seeking another interpretation which may be more valid. It is important that the distinction between turbidites and non-turbidites be made carefully and repeatedly in every study of bedded shales, siltstones, and sandstones, because inferences of slope direction and other paleogeographic interpretations depend for their validity on this distinction.

Bellshill Lake--Thompson Lake Cretaceous Oil Fields, Alberta: ABSTRACT

The Bellshill Lake oil field, located in east-central Alberta, was discovered in 1956. The field represents a stratigraphic trap formed by updip (northeast) shale-out of a highly porous and permeable quartz sand within the Lower Cretaceous Mannville formation. A detailed lithofacies map of a 50-foot thick slice (including the productive unit) parallel with an overlying marker bed shows: (1) the updip limit of the productive sand is irregular, and (2) ridges of sand are built up on the upper surface of the main sand body and are responsible in part for maximum pay thicknesses. The field is overlain by a gas cap and underlain by water. The maximum oil pay thickness is 50 feet. Approximately 3,000 acres have been developed to date and primary recoverable reserves are estimat d at 40 million barrels of 27° gravity (API) oil. The Thompson Lake field discovered in 1958 is a similar but smaller field and lies on trend southeast. A new technique for determination of net permeable sand (in sand-shale sequences) from electric logs is presented. The technique involves: (1) analysis of drill-stem test and lithologic data, and (2) construction of a graph to correct the amplitude of the self potential (SP) curve for various mud resistivities. End_of_Article - Last_Page 1095------------

Composition of Crude Oil and Its Relation to Stratigraphy in Wyoming

Although the crude oils of Wyoming vary widely in their composition, nearly all of them can be classified into two major groups on the basis of the average composition of oils from each formation. These two groups of oils are found in rocks representing different environments of deposition. The high-sulphur, low-gasoline, aromatic-naphthene base crudes are associated with thick limestone, dolomite, and shale sequences which were deposited in broad shallow seas under conditions of prolonged crustal stability. The low-sulphur, high-gasoline, paraffin-naphthene base crudes are associated with sand-shale sequences deposited in areas of moderate tectonic activity with high rates of subsidence and deposition. Differences in oils within a formation are correlative with differenc s in environment of deposition and with depth of burial. In the Pennsylvanian-Permian formations of Wyoming the oils associated with the dolomite-evaporite facies at the east are more aromatic and naphthenic than the oils associated with the dolomite-shale facies at the west. Within the Frontier formation the oils from areas of low sand-shale ratios contain more paraffins and less sulphur than oils from areas of high sand-shale ratios. Oils from depths greater than 8,000 feet in the Tensleep sandstone of Wyoming generally contain more than 50 per cent gasoline, whereas oils from depths less than 3,000 feet in the sand generally contain less than 25 per cent gasoline. However, there is no change in the paraffinicity of the heavier fractions of the Tensleep oils with depth. Also, there is o correlation between oil composition and depth for oils from all the Wyoming formations. No correlation was found between the composition of the Wyoming oils and their age, or the possible catalytic activity of their reservoir rocks.