Vugular Porosity Research Articles

Petrographical and petrophysical characterization of pre-salt Aptian carbonate reservoirs from the Santos Basin, Brazil

Reservoir quality in carbonates is influenced by various factors such as the depositional environment, burial history and diagenesis processes. Understanding these geological heterogeneities is essential for successful petroleum exploration. This study characterizes Brazilian pre-salt reservoirs and aims to understand how their heterogeneity impacts reservoir quality. We analysed carbonate samples from the Barra Velha Formation (Santos Basin) through an integration of petrographical and core plug descriptions, petrographical facies characterization, porosity and permeability measurements, and image analysis to identify the principal controls on porosity and permeability, pore-size distribution, and groups with similar petrophysical properties using the hydraulic flow unit (HFU) concept. Five facies groups were recognized: Spherulitestone (F1); Shrubstone (F2); Intraclastic Grainstone (F3); Intraclastic Packstone, Spherulitestone with mud and Shrubstone with mud (F4); and Shrub–Spherulite Intercalations and Bioclastic Grainstone (F5). The analysis of porosity and permeability showed that their variations are associated with pore type and cementation rate. Greater contributions of inter-aggregate, interparticle and vugular porosity, combined with a reduced amount of cement, results in higher porosity and permeability but an increase in cement tends to reduce the porosity and permeability. Among the facies groups, F2 and F3 exhibited the best porosities and permeabilities, followed by F1, F4 and F5. From image analysis, small pores (1.5 × 10 −5 –0.01 mm 2 ) are the most common in all rocks. However, these small pores contributed significantly to total porosity only in F4 and some samples of F3. For F2 and F3, the large pores (from 0.01 mm 2 to a maximum of 19.62 mm 2 ) are the main contributors, while F5 has a homogeneous contribution. Finally, the data were grouped into five HFUs: HFU1 and HFU2 represent the zones with the best reservoir quality, primarily composed of F2 and F3.

Low- and High-Resolution X-Ray Tomography Helping on Petrophysics and Flow-Behavior Modeling

Summary Reservoir studies involve spatial scales ranging from pore models to field-simulation grids. X-ray tomography is a nondestructive technique of inspection and characterization of samples that works from microns in the pore scale to centimeters in drill cores, which makes it a useful tool for modeling porous systems in reservoir-rock samples. The generated models serve to simulate physical phenomena helpful to determine both static and dynamic properties. Various techniques of preprocessing, porous-medium modeling, and simulation are applicable depending on the degree of heterogeneity of the sample. This work presents a workflow to make the porosity and permeability models from images acquired with axial computed tomography (CT) at different resolution scales. The workflow was used in sandstone and carbonate samples from Brazilian outcrops. The density and porosity of the sample were determined at the millimeter scale using a medical scanner and the distributions of pore size, grain size, and absolute permeability were determined using a synchrotron beamline, which provided high-resolution data at the micrometer scale. Integrating the data obtained from both scales, the combined description of the drill-core porosity served as a base to build a permeability model for the sample with the dimensions of that one scanned by the medical CT. The approach to generate the model depends on the type of heterogeneities associated with the sample. The homogeneous sandstone sample was modeled as a matrix with undefined porosity at the resolution of the medical tomography. The carbonate sample showed defined porosity at different scales: Moldic and vugular porosity were defined on the medical scale, while interparticle porosity was set on the synchrotron scale. Permeability was simulated in the micrometric model using an approach that integrates Stokes law and Darcy’s law in a percolating porous medium. Subsequently, the permeability was transferred to the millimetric model, creating the 3D distribution of porosity and permeability. Finally, the upscaled value for the samples was determined. This study contributes to the approaches regarding techniques of rock upscaling and digital rock physics and presents a workflow and some discussions of the multiscale approach.

A multivariate Bernstein copula model for permeability stochastic simulation

This paper introduces a general nonparametric method for joint stochastic simulation of petrophysical properties using the Bernstein copula. This method consists basically in generating stochastic simulations of a given petrophysical property (primary variable) modeling the underlying empirical dependence with other petrophysical properties (secondary variables) while reproducing the spatial dependence of the first one.This multivariate approach provides a very flexible tool to model the complex dependence relationships of petrophysical properties. It has several advantages over other traditional methods, since it is not restricted to the case of linear dependence among variables, it does not require the assumption of normality and/or existence of moments.In this paper this method is applied to simulate rock permeability using Vugular Porosity and Shear Wave Velocity (S-Waves) as covariates in a carbonate double-porosity formation at well log scale. Simulated permeability values show a high degree of accuracy compared to the actual values.

Evidence of Paleokarstic Phenomena and Burial Diagenesis in Ordovician Arbuckle Group of Oklahoma: ABSTRACT

Cores from various localities in south-central and north-central Oklahoma display surprisingly similar suites of karstic and diagenetic phenomena. Vadose dissolution tubes, solution-enlarged fractures, collapse breccias, and vugular porosity, where present are considered evidence of karstification. Primary speleothemic precipitates were not readily observed; either they were not present or were obscured by later hydrothermal dolomitization. A complex history of exposure and subsidence is recorded in these rocks. Immature karst profiles may have subsided at rapid rates under conditions that prevented low-temperature phreatic cementation, thus preserving the open pore network of the karst profile. Deep burial diagenesis is evidenced by the appearance of highly ferroan baroque dolomite cement partially or entirely occluding vugular and fracture porosity. In addition, host-rock carbonates were extensively replaced by typical thermal xenomorphic dolomite. Cathodoluminescent microscopy indicates that the hydrothermal dolomite is uniform in composition and was precipitated under highly reducing conditions. Dolomite cementation was arrested when oil migrated into the remaining pore space. A complex multistage fracture network is present in cores from the Healdton oil field. Early fracture systems are healed by highly ferroan, dull luminescent baroque dolomite, and later fractures are cemented with nonferroan, brightly luminescent cement.

Lima-Indiana Fields (1884-1910): The Shotgun Approach to Exploration and the Infancy of Petroleum Geology: ABSTRACT

An estimated 100,000 wells helped to delineate the Lima-Indiana trend in Ohio and Indiana. While the first discoveries from the Ordovician Trenton carbonate were made near known seeps, subsequent wildcat drilling in all directions eventually outlined more than 60 producing oil and gas fields. Cumulative production from this trend is close to 500 MMbo and 800+ Bcfg. Edward Orton, Sr., state geologist of Ohio, identified the reservoir rock as dolomitized limestone with vugular porosity (1888). With the help of structural contour mapping, he correctly predicted future oil discoveries. He also warned of the close spacing of wells which destroyed reservoir pressure. Companies of the Standard Oil Trust under John D. Rockefeller were largely responsible for the development of the Lima-Indiana fields.

Alternative Hypothesis for Development of Vugular Porosity in Mission Canyon Formation: ABSTRACT

Several writers have discussed the development of vugular porosity in carbonates of the Mission Canyon Formation along the eastern margin of the Williston basin. Suggestions have included dissolution of carbonates by fresh water in the mesogenetic and/or telogenetic zones, or dissolution by meteoric waters in a vadose setting. An alternate model in which dissolution occurred in an eogenetic, subaqueous, marine setting is proposed here. Apparently, the most pervasive vugular or enlarged-fenestral porosity is located near the contact between limestone and penecontemporaneously deposited gypsum bodies. During deposition, gypsum (now anhydrite) precipitation occurred in less oxygenated water than that from which the limestone formed. Microbial processes within a less oxygenated, gypsum-precipitating area can reduce sulfate ions to sulfides. This process, in the study area, produced sulfide-rich brines that flowed seaward into the more oxygenated, limestone-forming areas. The introduction of sulfides into a more oxygenated environment may produce an acid corrosive to limestone by the reaction HS/sup -/ + 2O/sub 2/ ..-->.. SO/sub 4//sup 2 -/ + H/sup +/. Dissolution of limestone by this acid probably took place near the sediment-water interface and to a shallow depth in the underlying sediments. Vugs formed by this process would be morphologically similar to those formedmore » by vadose processes. Implications of this model to hydrocarbon exploration include the possibility of extensive dissolution porosity occurring near depositional-topographic lows and near limestone-anhydrite contacts. The occurrence of stacked porosity zones can also be explained by this model.« less

Focusing on SEG Continuing Education: Borehole gravity surveys

Can accurate density and porosity be determined for important drillhole intervals where conventional well logs perform poorly, where old casings shield rocks from standard evaluation methods, or where irregularly distributed porosity (e.g., fracture or vugular porosity) defies conventional assessment? Can porous zones not penetrated by the drill but within production distances of the well be detected? Can the extent or proximity of subsurface structural features or stratigraphic units be determined from borehole measurements? Under what conditions are these achievable goals of a borehole gravity (BHG) survey? Can repeated surveys made during the lifetime of a petroleum reservoir provide useful information about reservoir mass changes? What information can be extracted from the integrated analysis of BHG data, conventional well logs, and other geophysical and geological information? What are the limitations of BHG surveys?

Design Concepts of a Heavy-Oil Recovery Process by an Immiscible CO2 Application

Summary Bati Raman oil field, in southeast Turkey, represents Turkey's biggest single oil reserve. The rapid production decline of the field and increases in the price of crude oil has led Turkish Petroleum Corp. (TPAO) to consider intervening with EOR techniques. Since 1967, various recovery schemes have been attempted, including steam and water injection. Extensive laboratory, modeling, and comparative engineering studies of various immiscible CO2 application techniques resulted. This paper presents the reservoir engineering aspects of immiscible CO2 application as applied to Bati Raman oil field. Introduction Bati Raman Oil Field. Bati Raman field, discovered in 1961 in southeast Turkey (Fig. 1), contains low-pressure, low-gravity (12 deg. API [0.986-g/cm3]) oil at an average depth of 4,300 ft [1310 m]. It is the largest oil field in Turkey, with an estimated initial reserve of about 1.85×10–9 STB [300×10–6 stock-tank m3]. The producing formation is Garzan limestone, a long, partly asymmetric anticline oriented in the east-west partly asymmetric anticline oriented in the east-west direction. The field is 10.5 miles [17 km] long with a width of 2.5 miles [4 km]. The reservoir is limited by an oil/water contact (OWC) at 1,970 ft [600 m] subsea in the north and west, by a fault system in the southwest and south, and by a permeability pinchout in the southern and southeastern part of the field (Fig. 2). The formation has a gross thickness of 210 ft [64 m]. The oil column from the top of the structure to the OWC is about 690 ft [210 m]. The Garzan limestone is of Cretaceous age, has a reefal origin, and exhibits rather pronounced heterogeneities both areally and vertically. The reservoir rock is a fractured vuggy limestone in the western and central parts, but is chalky and tighter to the east. Average porosity is 18% and mainly vugular and fissured in type. The typical matrix permeability by core analysis is 10 to 100 md; however, well tests show effective permeabilities in the range of 200 to 500 md, confirming the contribution of secondary porosity (fractures, vugs, and connecting cracks). In the central and western parts of the field, a well-developed system of secondary porosity and copyright 1985 Society of Petroleum Engineers permeability is believed to exist. In these areas, a permeability is believed to exist. In these areas, a secondary vugular porosity interconnected by fissures appears to be superimposed over a low primary porosity matrix. The main production mechanism is rock and fluid expansion. Water drive appears to be insignificant, except for a very weak aquifer influence at the central north-flank wells. The solution GOR is 18 scf/bbl [3.24 std m3/m3], resulting in a low bubblepoint pressure of 160 psi [1100 kPa]. There is practically no solution gas drive below the bubblepoint. The reservoir oil is just above the bubble-point pressure with a viscosity range of 450 to 1,000 cp [0.45 to 1.00 Pa s]. The original reservoir pressure was about 1,800 psi [12.4 MPa] at a datum of 1,970 ft [600 m] subsea. The average reservoir pressure has now declined to 400 psi [2758 kPa], after a cumulative production of 30 million STB [4.8 × 106 stock-tank m3] oil production of 30 million STB [4.8 × 106 stock-tank m3] oil (Fig. 3). The field was developed on 62 acres [251 000 m2] per well spacing. There are 103 active producers. All are on pump with a total oil production of 2,600 B/D [413 pump with a total oil production of 2,600 B/D [413 m3/d], compared with a peak rate of about 9,000 B/D [1431 m3/d] in 1969. Initial well producing rates ranged up to 400 B/D [64 m3/d] but now are averaging about 25 B/D [4 m3/d]. Reservoir and fluid characteristics are summarized in Table 1. Because of the unfavorable oil properties (such as low gravity, low solution gas, and high viscosity), low reservoir energy, and the type of driving mechanism, primary recovery prospects are very low. It is estimated that ultimately 1.5 % of initial oil in place (IOIP) can be produced from Bati Raman field through primary production. produced from Bati Raman field through primary production. The current trend in primary recovery and the rapid decline in reservoir pressure suggest the need for a suitable EOR method to produce a significant fraction of the vast reserve. In the past, we carried out laboratory and engineering studies as well as some field tests to enhance recovery, including water injection, steam cycling, steamdrive, and air injection (for in-situ combustion). Most of these studies, however, were empirical, exploratory in nature, and of limited scope. Of these, only the five-spot waterflood project proved conclusive. About 3.2 million bbl [500 000 m3] water were injected in the central area of the field between 1971 and 1978. JPT P. 275

Recent Field Results With New Bits

Summary Multiple pulse tests were conducted in Saudi Arabia to yield information about permeability anisotropies in the Ghawar oil field. Because of wide well spacing and high permeability, sensitive quartz pressure gauges were used to record pressure changes. Pressure data from observation wells were processed to filter out noise and to provide easily definable pulse responses. Calculated pulse test results then were analyzed for indications of directional permeability. Introduction To date, three Multiple production pulse tests have been conducted in the Ghawar oil fileld in Saudi Arabia in a continuing effort to improve the reservoir description used in reservoir simulation models of the area. Results from and procedures used in a 1977 test are presented by McIntosh et al.1 The results of the other two tests, which were conducted in 1979, are the subject of this paper. The performance and accuracy of any reservoir simulation study are related intimately to the completeness of the reservoir description of the field being modeled. Pulse tests, interference tests, and single-well pressure transient tests all provide valuable information without reservoir properties. The three pulse tests conducted in Ghawar were run to investigate the area distribution of permeability and, in particular, to test for the presence of area permeability anisotropies in the productive formation. Major directional permeability can have a dramatic effect on fluid movement in the reservoir; therefore, the description of permeability trends is a key element in reservoir modeling. Results from the pulse tests are being integrated with results from cores, logs, and other well tests to improve overall description of the reservoir. The previous pulse test conducted in 1977 proved the feasibility of pulse testing in the high-permeability, wide well-spacing environment of Ghawar. The two tests discussed in this paper were located to provide good areaI coverage over the central portion of Ghawar. One test was run near an area that previously had been identified by buildup testing as having ultrahigh permeability. Of the three well pairs involved in this test, one of them indicated very high interwell transmissibility. We believe that this high permeability is associated with a localized thin facies near the top of the reservoir, which has not been described geologically to date. For the six well pairs comprising the two tests discussed here, interwell distances varied from a minimum 2,921 ft (890 m) to a maximum 4,499 ft (1371 m). The observed time lags and pressure responses varied from 72 to 1,728 minutes and from 0.12 to 7.05 psi (0.83 to 48.6 kPa), respectively. First pulse responses and first inverse pulse responses were recorded in three well pairs. For the other three well pairs, second pulse responses were recorded also. Reservoir Description The reservoir tested and described in this paper is in the Arab-D formation, the major productive formation in the Ghawar field. This formation is a massive carbonate structure grossly subdivided into five separate zones. The reservoir of interest comprises interbedded layers of limestone and dolomite, and it is quite heterogeneous both vertically and areally. In general, there is a degradation in both porosity and permeability vertically with increasing depth in the reservoir. Some vugular porosity occurs throughout the reservoir, in both limestone and dolomite facies.

HYDROCARBON POTENTIAL OF THE ARCKARINGA REGION, CENTRAL SOUTH AUSTRALIA

The Arckaringa region is a large area which lies between the Officer Basin and the Peake and Denison Ranges in central South Australia. It includes sedimentary rocks of Jurassic-Cretaceous, Permo-Carboniferous and ?Cambrian ages. The thickest sequence of sediments (about 2000m) occurs in the Boorthanna Trough, located immediately to the west of the Peake and Denison Ranges. Cretaceous sediments of the Eromanga Basin form a veneer over much of the area. Oil shows at very shallow depths in immature sediments at Oodnadatta 1 raise speculations about the possibility of shallow generation of hydrocarbons in the Eromanga Basin. However, most of the petroleum exploration in the region has been aimed at delineating the underlying Permo-Carboniferous Arckaringa Basin sequence. The Arckaringa Basin is not a simple sedimentary depression but rather a series of peripheral depressions surrounding a central platform region. Unlike the Cooper and Pedirka Basins, it contains some marine sediment, suggesting the possibility of an oil-prone rather than a predominantly gas-prone province. Due to the thin nature of the sequence and its shallow depth of burial, most of the Arckaringa Basin is predicted to be immature for hydrocarbon generation in traditional terms. However, source-rock and vitrinite studies in the Boorthanna Trough indicate that the basal units are marginally mature to mature in this area. Early Cambrian carbonates are interpreted to extend southeastwards in an arc from Byilkaoora 1 in the Officer Basin, through the Boorthanna Trough, and onto the Stuart Shelf. In the Boorthanna Trough these carbonates are named the Cootanoorina Formation. They are of varied lithology and are associated with terrigenous clastics and minor evaporites. Vugular porosity occurs sporadically in the sequence, which may be thicker than 1000m in some of the deeper parts of the trough. Source-rock studies suggest that the sequence is immature to marginally mature in Weedina 1 and Cootanoorina 1.It is emphasised that the Arckaringa region is largely unexplored for hydrocarbons, with only two wells drilled on structural targets in the entire area of about 60 000 sq km. This report presents source-rock and maturation data which suggest that the sequence is more mature than originally predicted, and that the deeper parts of the Boorthanna Trough may have a modest potential for oil, both in the basal Permo-Carboniferous and in the ?Cambrian Cootanoorina Formation. An active exploration programme has begun, with several hundred kilometres of seismic surveys planned for 1982.

Miscible And Immiscible Displacement Studies On Carbonate Reservoir Cores

Introduction The use of nitrogen injection to stabilize water encroachment and to improve gas recovery from carbonate reservoir cores has been investigated. A series of linear displacement experiments was conducted on full-diameter plugs representing selected facies of the reservoir. Miscible displacement of methane by nitrogen and immiscible displacement of methane by water were measured. The recovery of trapped methane from the water flooded cores by nitrogen injection was also obtained. The rate of methane recovery was found to depend on the initial water saturation, the displacement rate within the plug and the lithology of the individual rock samples. A composite core made up of three plugs showed that the individual, plug tests gave conservative results for methane recovery efficiency. In order to compare methane recovery in a homogeneous system with the heterogeneous carbonate system, a Berea sandstone plug was subjected to the same suite of tests. It was found that the role of mass transfer had different effects on the rate of recovery of methane in the two systems. Introduction The effect of an active bottom water drive on gas recovery from an Alberta carbonate reservoir led to the initiation of this laboratory study. Gas displacement with water was conducted on cores from the reservoir facies in order to quantify trapped gas saturations. The effectiveness of nitrogen injection to reduce this trapped gas content by miscible displacement of the reservoir gas was also determined. Previous studies of displacement(1,2), and pore geometry(3,4) in sandstone or carbonate cores have involved the use of small plugs which have only given the effects of the matrix geometry. Unfortunately, interpretation of displacement data obtained using reservoir cores which contain vugular porosity can be somewhat subjective(5,6) and the dimensions of the heterogeneities must be relatively less than the size of the core being examined. Thus, the dolomite cores employed were full diameter and as long as possible in order to better reflect the presence of vugs and other types of porosity and their influence on gas recovery. Three selected non-preserved, full-diameter cores, which represented typical facies within the reservoir, were subjected to gas-gas, water-gas and gas-water displacement. The three cores, labelled A, B and C, are described in Table 1. They are all characterized by well-developed moldic to vuggy porosity with varying degrees of fracture development and matrix permeability. Similar displacements were conducted on a composite core made up of the three cores, a homogeneous Berea sandstone and a fractured carbonate core with well-developed inter-crystalline porosity. Each carbonate core is pictured in Plate 1. A qualitative description of the porosity types represented in each core could be summarized as:vug – tight matrixvug – fracturevug – matrixcompositematrix. (Berea Sandstone)matrix -fracture All measurements were conducted at constant flow rate and 6900 kPa (1000 psig) core outlet pressure. The tests included:Downward displacement of methane by nitrogen at several rates in dry cores.

Waveland Field, Unique Structural and Stratigraphic Trap: ABSTRACT

Waveland field, located in Hancock County, Mississippi, and currently being developed, was discovered in 1965 by Humble Oil and Refining Co. Gas Unit 1, Sec. 22, T8S, R15W. One additional field well was drilled, a northwest diagonal in Sec. 16, T8S, R15W. After these two field wells were completed and put on production, there was no additional development until 1975, when lease blocks were assembled by Phillips Petroleum Co., Saga Petroleum, Marshall R. Young Oil Co., and others. There is no massive deposition of Ferry Lake Anhydrite in the area. Because of the lack of massive anhydrite, actual definition of the formations of the Trinity Group (Lower Cretaceous) is difficult to impossible. However, it is interpreted that the primary reservoir of Waveland, a porous limestone, is the Mooringsport Formation. The depositional environment of the Mooringsport limestone reservoir is extremely complex because of the influence of the large regional carbonate banks on the south. For convenience, the Mooringsport porosity zones are lettered A through G. To date, the A and B zones are the primary contributors to production. The B zone may be subdivided within the field proper. The reservoir rock is best described as a two-porosity system--matrix porosity (range 6 to 12%) and vugular porosity (range 7 to 16%) directly related to the mineralogy, lithology, and diagenetic history. Matrix permeability is generally low, not exceeding 2 md and usually less than 1 md. Fractures are essential for good productivity and intense fracturing is present in all the higher crestal positions. The Waveland field comprises the crestal 19,000 productive acres (7,600 ha.) of a north-to-south-elongated nose having no apparent structural closure, fault closure, or north dip at the Mooringsport limestone level. Structural elevation at the Mooringsport level is a major factor in determining hydrocarbon saturation, but no direct relation has been found among pore-throat size, rock type, porosity, structural elevation, and hydrocarbon saturation. The Waveland field is a complex combined structural and stratigraphic trap. End_of_Article - Last_Page 1428------------

Detecting Microporosity To Improve Formation Evaluation

If you can't see the trees for the forest, get a scanning electron microscope. It can get you close enough to discover precisely what conditions are, and in conjunction with other devices may keep you from turning down some promising reservoirs. Introduction Evaluation with the most recently developed logging tools has revealed anomalous conditions of high water saturation in productive intervals and has indicated the need for a supplemental evaluation tool or technique for such circumstances. The anomalies were observed in both clastics and carbonates over a broad geographic area. The scanning electron microscope (SEM) bas been useful forgrain surface studies related to environments of deposition,microfossil investigation for biostratigraphic dating and alteration of sediments, anddocumentation of microporosity in carbonate rocks Use of the SEM has improved our understanding of the actual pore configuration of reservoir rocks characteristics that can be observed only at high magnification. Core and cutting samples from numerous wells have been inspected with the SEM. Observations indicate that where the reservoir rock contains microporosity, the upper limits for water saturation determined by log analysis can be increased. The minimum water saturation depends in part on the relative amount of microporosity in the rock. Detection of Microporosity Reservoir rocks are divided into two basic categories:clastics, which include slits, sands, and gravel; andcarbonates, which encompass limestones and dolomites. The pore space between sand or carbonate grains as originally deposited is called intergranular porosity. Vugular porosity, another well known type, porosity. Vugular porosity, another well known type, can be formed by leaching of carbonate grains or other soluble material, which results in pores larger than the grain size of the rocks. Both intergrain and vugular porosity can be detected visually or at low magnifications porosity can be detected visually or at low magnifications (50 x or less), Inspection of both clastic and carbonate samples with the SEM can reveal another type of porosity: microporosity. No limits on physical measurements have yet been established to define a micropore. Rather, it has been accepted that a micropore is so small that it cannot be seen at magnifications of less than 50 x and requires 100 x to 5,000 x to be studied in detail. The presence of microporosity in a reservoir increases the presence of microporosity in a reservoir increases the capillary attraction to water, frequently resulting in very high immobile water saturation. The microporosity is formed by one of several methods, including recrystallization of grains and oolites, dolomitization, formation of intercrystalline pores, and secondary cementation. Thus far, no completely reliable method has been established for recognizing reservoirs containing microporosity except inspection of samples with an SEM. Several techniques have, however, offered valuable assistance in revealing such reservoirs. The use of mud loggers during drilling has in some cases revealed shows where log calculations indicated high water saturation. Subsequent testing has sometimes yielded hydrocarbon production where examination of samples revealed microporosity. JPT P. 1080

Developments in East-Central States in 1970

One deep Precambrian and 3 deep Cambrian tests were drilled in the east-central states in 1970. The Precambrian test, in Elliot County, Kentucky, was reportedly completed with production from the Tomstown and a shallower pay. The 3 Cambrian tests were in Humphreys County, Morgan County, and Sequatchie County, Tennessee. All 3 were abandoned, although the well in Morgan County had a slight show of oil in the Lower Mississippian and some vugular porosity in the Knox Dolomite, and the well in Sequatchie County had several small gas shows in the lower Knox Dolomite. Production in Oneida West field, a 1969 discovery in Scott County, Tennessee, was extended. At the end of 1970, 20 oil wells in the field had initial flow rates of from 100 to 1,200 BOPD. Production is from Missis ippian Fort Payne. In Indiana, exploration in Greene County and adjacent Daviess County was up significantly as a result of the discovery of Plummer field in 1969. The most significant discovery in Illinois was Roby East field, a Silurian producer in Christian County. At the year end 18 wells were producing. Initial production rates averaged 218 BOPD and reached a maximum of 1,008 BOPD. Oil production in the 4 states was 63,080,000 bbl, down 11.8% from 1969. Only Tennessee showed an increase in production, from 31,532 bbl in 1969 to 309,305 bbl in 1970. Gas production in Kentucky was down 14.3%, from 88.6 Bcf in 1969 to 76.0 Bcf in 1970. Gas production in the other 3 states is insignificant. The total number of wells drilled for oil and gas was 1,865, a decrease of 16.4% from 1969. Discoveries in 1970 did not increase reserves significantly.