Berea Sand Research Articles

Adsorption study of acrylamide-tertiary-butyl sulfonate (ATBS)/ acrylamide copolymer in polymer flooding enhanced oil recovery (EOR) process

Polymer flood is known as the most important enhanced oil recovery technology due to its various advantageous and relatively cheaper price. However, it comes with associated problems of polymer adsorption that leads to injectivity loss. This work aims in studying various parameters that may affect the ATBS/ Acrylamide copolymer adsorption in a porous medium to optimize the polymer scheme. Synthetic D brine with D sand sample was mixed and tested in static and dynamic condition. These tests were conducted at room temperature and 90°C whereby the core flooding experiments were conducted with varied flowrate through Berea Sand Core sample. Results show that a higher brine salinity and a longer aging time leads to higher adsorption rate whereas adsorption static test conducted at replicated reservoir condition of 90°C resulted in lower adsorption capacity than at room temperature. Also, static adsorption was found to be higher than the dynamic adsorption due to the changes in the specific surface area and the extent of mechanical retention present in the dynamic core flood experiment. In conclusion, the type of polymer used in polymer flooding must be carefully chosen to serve the need for a specific reservoir condition so that the adsorption phenomenon is minimized.

Polymer-Stabilized Multi-Walled Carbon Nanotube Dispersions in High-Salinity Brines

Carbon nanotubes (CNTs) exhibit promising properties for potential applications in oil and gas reservoirs. CNTs can be used as delivery vehicles for contrast agents or catalyst nanoparticles deep inside the reservoir. Dispersing 100 ppm of CNTs in deionized water is easily achieved by sonication of CNTs using properly selected surfactant or polymer solutions. These surfactants and polymers are non-covalently adsorbed to the nanotube surface, inducing dispersion stability. In oil reservoirs, high salinity is the norm; therefore, because the electrostatic double layer is compressed as a result of the high ionic strength found in a typical reservoir brine, colloid CNT dispersions lose stability and CNTs flocculate and precipitate. To maintain a stable colloidal dispersion of CNTs, a dispersant with functionality providing steric repulsion between the dispersed tubes is needed to prevent aggregation. In this work, suspensions of multi-walled carbon nanotubes (MWNTs) were generated using two polymers, gum arabic (GA) and hydroxyethyl cellulose (HEC-10), in 10% API brine (8 wt % NaCl and 2 wt % CaCl2). GA was used as a primary dispersant, which is able to debundle the tube aggregates. After the first sonication with GA, the secondary dispersant, HEC-10, is added to provide the steric repulsion needed to keep the tubes dispersed in high-salinity brines. Polymer adsorption to the nanotube surface was observed using scanning electron microscopy. Focusing the electron beam for an extended period of time induced damage to the polymer layer around the individual nanotubes, leaving the tubes intact, as clear evidence of polymer adsorption. Adsorption experiments showed low to negligible adsorption of MWNTs to crushed Berea sand at 80 °C in both 10 and 20% brines. Dispersion injection in column and coreflooding tests showed successful propagation of CNT dispersions through porous media, with total nanoparticle recovery exceeding 80% in reservoir rock. This work demonstrates the potential of using polymer-stabilized carbon nanoparticle dispersions in a range of applications to advance current oilfield technology.

Investigation of permeability, formation factor, and porosity relationships for Mesaverde tight gas sandstones using random network models

Replicating the pore topology/structure of tight gas reservoirs is essential to model fluid flow through such porous media. Constitutive relationships between the macroscopic properties of the medium can often help with such modeling efforts. Permeability and formation factor are rock properties providing useful information for assessing the potential of hydrocarbon recovery. Pore topology/structure and pore–throat radius distributions are the major factors having influence on permeability and formation factor estimation. A stochastic random generation algorithm is employed to study the effect of pore structure and geometries on the relationships of formation factor–permeability and permeability–porosity on physically realistic 3D random networks. These relationships are derived by constructing two sets of physically equivalent pore networks of tight porous media and are validated using experimental measurements of Mesaverde tight gas sandstones. The first set of networks were based on Berea sand network properties, which are then reduced and derived using a Weibull truncated equation to produce physically sound tight porous media. The second equivalent networks are constructed according to experimentally derived throat size distributions obtained from ambient mercury injection capillary pressure for 17 selected core samples from three Mesaverde tight gas sandstones basins in the U.S. Imperial college Pore-Scale Modeling software is used to model the single liquid flow properties through constructed equivalent networks. The estimated porosity, absolute liquid permeability and formation factor of the constructed physically equivalent networks are in good agreement with measured data obtained by Byrnes et al. (Analysis of critical permeability, capillary and electrical properties for Mesaverde tight gas sandstones from Western US basins: final scientific. Technical report submitted to DOE and NETL 355, 2009). However, a variation between estimated absolute permeability to liquid and measured routine gas permeability is accounted in core samples that have measured permeability smaller than 0.1 mD. Networks based on Berea sand properties show qualitative agreement between modeled data points and experiment data. However, modeled data are off by two orders of magnitude and all fall more or less on the same line.

Dispersion Stability and Transport of Nanohybrids through Porous Media

Single-walled carbon nanotube-silica nanohybrid particles are a very promising material that could be used for enhanced oil recovery because of their interfacial activity. To demonstrate the basic principle, aqueous nanohybrid particle dispersions were evaluated by looking at the effect of pH, surfactant, and polymer. The results showed that pH did not have significant effect on the dispersion stability of nanohybrid particles. Although surfactant could improve the dispersion stability, it reduced the interfacial activity of the nanohybrid particles, causing them to stay in the aqueous phase. The best nanohybrid particle dispersion stability was found upon polymer addition, where the dispersions were stable for more than a week even at low polymer concentration (50 ppm). One-dimensional sand-pack studies were performed to evaluate the flow of the nanohybrid particles through porous media. The results showed that most of the nanohybrid particles (>99%) could pass through a column packed with glass beads while a measurable fraction of the particles was retained in the column packed with crushed Berea. When the columns contained a residual saturation of decane, additional nanohybrid particles were retained at the oil/water interface in both glass beads and crushed Berea sand media. The sand pack studies showed that not only can the nanohybrid particles flow through porous media but also about half of the particles injected will go the O/W interface when the porous medium contains a residual saturation of hydrocarbon, where they could be used to support a catalytic conversion of components of the oil in reservoirs.

Low-Temperature Oxidation of Oils in Terms of SARA Fractions: Why Simple Reaction Models Don't Work

Abstract The low-temperature oxidation (LTO) reactions of the SARA fractions separated from two crude oils were studied in the presence of their reservoir sands at temperatures between 130 and 230 °?C. The results indicated that the usual approach to modelling LTO-the use of a very few single-step Arrhenius-rate equations-could not be made to reflect the observed reaction kinetics. Instead, this investigation found that the following reaction characteristics were needed for accurate reaction modelling:a change in the order of reaction with respect to oxygen concentration from ? to 1 as temperature rises;the repression of a saturates oxidation reaction by other fractions; and,a prominent induction period exhibited by the saturates fraction. The compositions and yields of the ultimate LTO reaction products were measured, and these included relatively stable residues with high oxygen contents. Because the LTO reactions play an important role in enhanced oil recovery by air injection methods, the above information is valuable for the simulation and prediction of these processes. Introduction Enhanced oil recovery processes need to be predictable before they can be seriously considered for widespread field application. One of the main problems limiting the development and application of new process variations for air injection or in situ combustion is that their field performance and consequently their technical success or failure can simply not be predicted with any reliability. The most serious questions frequently hinge upon the nature of stability of the combustion/oxidation zones. Many studies have provided valuable knowledge as to the nature of the related chemical reactions, but the usefulness of proposed reaction models for numerical simulation prediction is still limited. Three main types of reaction have been found to govern air-injection EOR processes: pyrolysis/coking, low-temperature oxidation, and high-temperature oxidation (combustion). This study was concentrated on the second category of reaction: low-temperature oxidation (LTO). The free-radical nature of low-temperature oxidation of hydrocarbons has long been known. In a 1958 review, Morton and Bell(1) confirmed that LTO occurs through a free-radical mechanism in which the production of hydroperoxides is an important first step. They also mentioned the role of inhibitors, discussed catalysis by metal surfaces and metallic salts, and described why long induction periods could occur before the onset of significant oxygen consumption was observed. Initially, most studies of the chemical mechanisms conducted both before and after Morton and Bell's review used pure compounds. The results varied between compounds, and could not be used directly to describe the oxidation of complex mixtures like crude oils in a petroleum reservoir. In 1968, Bousaid and Ramey(2), while investigating high-temperature oxidations, carried out three low-temperature oxidation tests on a heavy oil between 23 and 52 ° C. They reported very low values of oxygen consumption, with rates that were correlated with an activation energy of 53,200 J/ gmol. Later, Dabbous and Fulton(3) published much more extensive results for LTO of two whole oils on crushed Berea sand over the temperature range of 121 to 246 ° C.

The Effect of Changing Mobility Ratio on Displacement Efficiency in Polymer Flooding

ABSTRACT The effect of changing mobility ratio on displacement efficiency in polymer flooding was investigated. For this purpose, experiments on unsteady-state displacement were conducted with two Berea sand cores of different permeabilities. Each core was flooded by displacing fluids of three different viscosity ratios. Relative permeability ratio curves measured on the core by changing the viscosity of displacing fluid, showed similar pattern in the same saturation path regardless of changing the viscosity of displacing fluid. Fractional flow curves measured on the core showed that higher viscosity of displacing fluid resulted in more efficient displacement; that is, as the viscosity of displacing fluid was increased, mobility ratio was decreased and displacement efficiency was increased. The effect of changing viscosity ratio on mobility ratio was considerably higher on low permeability core than on high permeability core. The displacement efficiency measured on low permeability core was higher than that of high permeability core by 26 percent at the time of breakthrough. It was shown from the experiment that polymer flooding would be applied more effectively in low permeability reservoirs.

ポリマー水溶液の多孔質媒体内流動における振動効果の解析

In this paper, vibration theory of elastic body is applied as an analogy to the quantitative analysis of resistance factor of polymer solution measured when it flows through porous media.Resistance against flow of polymer solution through porous media is not caused only by viscosity of polymer solution, but also affected by the energy dissipation by experiencing rarefaction and compression of polymer solution while flowing alternately in the throat connecting pores and in the open pore spaces. Euler Equation is modified to express such elastic resistance of polymer solution caused by the oscillation of normal stress in the fluid. Flow equation comprised of both Euler Equation and Darcy Equation is introduced to calculate both elastic and viscous resistances against flow through porous media. New equation is applied successfully to demonstrate the dilatant flow behavior of polymer solution in the flooding experiences through a capillary tube packed by glass beads and through Berea sand cores.Diffusion equation modified to express the vibration effect of viscoelastic fluid is applied to solve the pressure loss of polymer solution flowing through porous media. Quantitative analysis of the resistance factor of flow of polymer solution through porous media is presented by the use of analytical solution of diffusion equation.

Flow properties of EOR polymers(Part 2). Flow resistance properties through cores.

This paper presents the results of an experimental study on the flow resistance properties of polymer solutions through Berea sand stone cores. The polymers tested in this study were co-polymers of N-Vinyl formamide and Acrylamide, respectively.The ion type and concentration in solution were varied for each polymer in order to examine their effects on the respective flow resistance properties.Di-valent cations in solution caused greater reduction in flow resistance properties than did the mono-valent cations. Polymers containing AMPS•Na, however, seemed to exhibit higher viscosities and resistance factors in the presence of di-valent cations than those by polymers containing AcA•Na.The viscosity, resistance factor and residual resistance factor of N-Vinyl formamide polymers were not greatly different from those of Acrylamide polymers. The screen factors of N-Vinyl formamide polymers, however, were much greater than those of Acrylamide polymers.

The mechanism of adsorption and a new method to reduce surfactant loss in chemical flooding

The effectiveness of surfactant-polymer flooding depends largely on the stability of its formulation. After coming into contact with reservoir rocks, the carefully screened optimal surfactant displacement system will lose its low interracial tension and high solubilization, because of a change in the compatibility formulations and a significant decrease of surfactant concentration. There are many reasons for the loss of surfactant concentration; at present, surfactant adsorption on the mineral surfaces of the rock has been most discussed (Boneau, 1977; Hanna and Somasundaran, 1977, 1979; Lawson, 1978; Zapak, 1980; Kalpakci et al., 1981; Clementz, 1982). To obtain a clear idea of the adsorption behavior of an anionic surfactant sodium alkyl benzene sulfonate (SDDBS; widely used in the formulation of a displacement reagent) it is necessary to study its adsorption on various minerals, i.e., quartz and clay (montmorillonite, kaolinite, illite, etc.), which are the main components of the reservoir rocks, and on carbonates. Wayman (1963) studied the adsorption of a dilute solution of SDDBS on various clays, and Scamehorn (1980) investigated the adsorption of alkyl benzene sulfonate homologous aqueous solutions on kaolinite, A1203. These workers indicated that the adsorption isotherms conform with the Langmuir equation and can be described by the Truber diagram. On the other hand, Meader (1952), Hanna and Somasundaran (1977,1979), Somasundaran (1980), and Trogus (1979), studied the adsorption of sodium alkyl benzene sulfonate on bioglass, kaolin, and Berea sand core, and pointed out that the adsorption isotherms do not conform with the Langmuir equation: a maximum adsorption value was observed, sometimes followed by a minimum value. There are various explanations for this type of adsorption isotherm, and experimental results on the influence of the selective wetting of a mineral surface on adsorption are also quite varied. Zapah (1980) and Kalpokei et al. (1981) pointed out that adsorption on an oil-wet surface is less than that on a water-wet surface. However, the results of Boneau (1977) are contrary to this. According to his investigation, Clementz (1982) indicated that adsorption of pure SDDBS (recrystallized) on organo-montmorillonite is less than that on montmorillonite, whereas commercial SDDBS (with a purity of less than 60%) has identical results when the concentration of SDDBS solutions is less than their critical micellar concentration. However, the results were

Chromatographie Transport of Alkaline Buffers Through Reservoir Rock

Summary Use of relatively low-pH alkaline buffers, such as sodium carbonate or sodium silicate, is explored as a means for overcoming sodium/hydrogen ion-exchange delay in alkaline waterflooding. A local-equilibrium chromatographic model is outlined to describe the concentration velocities for injection of alkaline buffers into a linear porous medium that exhibits reversible sodium/hydrogen exchange. The theory predicts a buffer ion-exchange wave that is substantially faster than that for equivalent-pH sodium hydroxide solutions. New experimental displacement data are presented for NaOH over a pH range from 11 to 13 and for 0.1, 0.5, and 1.0 wt% Na2CO3 flowing through a 1 wt% NaCl brine saturated Berea sandstone core at 50°C [122°F]. To permit a complete description of the system, column effluent concentrations are measured for sodium ions, hydroxide ions, H3-tagged water, and 14C-tagged carbonate. The experiments confirm that Na2C03 propagates through the Berea sand at a higher rate than NaOH. For example, at pH=11.4, Na2CO3 migrates with a velocity that is 3.5 times faster than NaOH. Comparison of experiment with the ion-exchange chromatography theory shows good agreement. We successfully model the concentration histories of tritium-labeled water, total carbon, sodium, and hydroxide, all with no adjustable parameters. This work establishes with both theory and experiment that buffered alkali significantly increases the propagation speed of hydroxide in reservoir sands in comparison with unbuffered alkali at equivalent sodium and hydroxide concentrations. Because lower-pH buffered alkali can also protect against rock dissolution loss, the validated reduction of buffer ion-exchange lag considerably improves the promise of the alkaline flooding process for field application.

Braided Rivers and Related Terrigenous Depositional Systems--Useful But Enigmatic Exploration Models: ABSTRACT

Closely related Holocene and Pleistocene braided-fluvial, eolian dune-sand flat, and playa-lake depositional systems in the eastern Texas Panhandle represent a useful but complex model for hydrocarbon exploration in ancient continental sediments. The modern South Canadian fluvial system and the Pleistocene Borger fluvial system are braided river deposits which are distinguishable from other sand bodies by multi-lateral sand-body geometry (high width/thickness ratio), low channel sinuosity, few sedimentary structure types, poor lateral and downstream continuity of individual depositional sequences, punctuations of these sequences by thin clay drapes, and a high sand/mud ratio. The main sand body of the South Canadian system averages two mi in width and 125 ft in thickness nd cuts into the coarse-grained and sometimes conglomeratic sand of the Borger system. Fine to medium wind-polished sand of the Lake Marvin eolian-dune system and the older vegetated Nix Ranch eolian-sand system is deposited in thin plane-bedded sheets and strongly cross-stratified parabolic and longitudinal dunes. These eolian units are derived from, and often continuous with, South Canadian fluvial deposits of different ages. The strongly vegetated and older Pampa eolian-sand system is related similarly to the Borger fluvial system. In addition, the surface of the Pampa system is pockmarked by small pre-Nix Ranch playa-lake deposits consisting of organically rich and finely laminated beds of clay and sandy silt. Hydrocarbon discoveries in fluvial and eolian sands illustrate the economic value of this depositional model. Among the many examples of production from fluvial sands are the Lower Cretaceous J sand bodies in Nebraska, lower Paleozoic Granite Wash in Alberta, and the Berea sand in Ohio. The Permian Queen sandstone in New Mexico produces from probable eolian deposits. Limited subsurface information leads to difficulty in recognizing separate depositional systems in sands of similar size and texture. For this reason the explorationist must be careful in application of depositional models. Realization of possible variation in sand-body geometry in a particular type of depositional system is essential. End_of_Article - Last_Page 914------------

Experimental Simulation of the Zones Preceding the Combustion Front of an In-Situ Combustion Process

Abstract A linear Berea sand pack, initially containing three phases -- oil, water and air - was used to simulate experimentally the processes in the zones from the water bank through the evaporation and visbreaking region. Simulations using such process parameters as oil composition, system pressure, parameters as oil composition, system pressure, and gas injection rate were conducted. Every simulation followed programmed ascending-temperature steps with each step being approximately isothermal. The relative importance of each mechanism causing nonisothermal liquid movement was quantitatively determined and liquid saturation distributions were obtained. Results of the experiments showed that gas stripping was one of the main mechanisms responsible for oil flow in the hot water bank and that steam distillation was the chief mechanism for the oil movement in the steam plateau. Both mechanisms were primarily controlled by oil composition, system pressure and gas injection rate. The oil- and water-saturation distributions were reconstructed from the experimental results. A first-order equation approximated the oil saturation in the regions simulated and a second-order equation approximated the water-saturation distribution. Introduction Laboratory experiments, mathematical models, and field tests have been widely used to investigate the in-situ combustion process. Invariably, the results of these investigations have confirmed that the complex in-situ process possesses a number of distinct transient regions of varying physical and chemical importance. physical and chemical importance. Mechanisms associated with each of these regions have been qualitatively described. In general, these descriptions are based on gross experimental observations such as production history, temperature profile, produced fluid properties, etc. These qualitative descriptions of properties, etc. These qualitative descriptions of in-situ mechanisms are principally sound, but the scarcity of quantitative demonstration of nonisothermal liquid behavior, liquid-saturation distribution and process parameter effects on the mechanisms demands further investigation. This paper attempts to provide some quantitative information on several important mechanisms associated with in-situ combustion. A simple linear laboratory model is used to simulate the processes in the regions, starting from the water bank and ending at the evaporation and visbreaking region, which immediately precede the cracking region and combustion front. The experimental results give oil- and water-saturation distributions which should be useful in mathematical simulation and oil recovery estimation. REGIONS OF IN-SITU COMBUSTION Kuhn and Koch observed at least four coexistent transient regions in their experimental work using linear combustion tubes. Tadema performed in-situ combustion in a glass tube and described the mechanisms that would take place in each of these transient regions. Wu estimated the relative length of these regions in a combustion tube process under various experimental conditions. process under various experimental conditions. A schematic diagram of these regions is shown in Fig. 1. These regions were discretely reconstructed based on the description of Tadema and liquid production and temperature histories at the outlet end of a typical combustion tube experiment (performed by the Gulf Research and Development Co.). Starting from the injection end, these regions may be designated as the burned zone, combustion zone, cracking region, evaporation and visbreaking region, steam plateau, water bank, oil bank and initial zone. Each region has definite temperature and fluid-saturation characteristics. SPEJ P. 38

Three-Phase Relative Permeability

Abstract The results of three-phase relative permeability tests on nine water-wet consolidated Berea sandstone samples are presented as composite ternary diagrams showing isoperms of oil, water and gas. Capillary pressure control was exercised over the flow of gas and oil in the presence of water. The water saturations ranged from 17 to 71 per cent pore volume. A method of calculating both the oil and water permeabilities of a three-phase system from the easily measured gas relative permeability is presented. Experimental Procedure and Results A renewed interest has been shown in three-phase relative permeability as a result of recent developments involving underground combustion processes, steam injection, and other multiphase displacement processes. The experiments and results described here involved simultaneous flow of oil and gas in consolidated Berea sand with brine present as the wetting phase. Gas and oil relative permeabilities were measured on nine cores with CaCl2 brine present as the wetting phase in saturations ranging from 17 to 71 per cent.

Developments in Ohio in 1951

Developments in Ohio in 1951

Geology and Occurrence of Oil in Medina Sand of Blue Rock-Salt Creek Pool, Ohio

The principal oil sand is a thin sandstone lying directly upon the Queenston red shale of Upper Ordovician age. This sandstone is known locally as the Medina sand. Although the greater part of the oil from this pool is obtained from the Medina sand, an important yield of natural gas comes from the Clinton sand within the areal limits of the underlying oil pool. Pennsylvania grade crude oil in relatively small and scattered quantity is obtained from the Clinton sand which lies above, and is separated from, the Medina sand by a shale interval of approximately 70 feet. A very small area in the south part of the pool produces some oil, inferior in quality to Pennsylvania grade oil, from the upper part of the ''Big lime and a few small gas wells have been completed in the Mississippian Berea sand along the east bank of the Muskingum River in the west part of the pool. The oil reservoir in the area which is of the greatest interest and which pre­ sents a new problem and a new possibility to the Appalachian producer is in the Medina sand. It may be described as one which produces under gas drive and is currently being developed by the completion of wells which are charac­ teristically small in original potentials, but which exhibit extraordinarily slow declines. The occurrence of this reservoir and the accumulation of oil found in it are believed to be the result of sedimentary processes rather than of migration and entrapment influenced by the structure of the region. This paper, therefore, presents a brief account of development, followed by the data of stratigraphy and structure from which this conclusion has been drawn and is concluded by the author's interpretation of the sedimentary con­ ditions relating to the formation of the reservoir and the means whereby the crude oil may have been transferred to it from the source material.

Hemlock Grove Oil Field: ABSTRACT

Two factors have seriously handicapped the presentation of this review. One is the lack of a thorough understanding of the nature of oil accumulation in the Berea sand and the other is the unavailability of sand data and production statistics within the field. Several cores have been taken but the results of their analysis have not been released. In the absence of such information this paper is confined to a historical review leading to the discovery well, the field development, and finally a limited discussion of the Berea sand. End_of_Article - Last_Page 2153------------

Structural Accumulation of Natural Gas in Oriskany Sand of Tri-State Area: ABSTRACT

In the Tri-State area, comprising east-central Ohio, southwestern Pennsylvania and northern West Virginia, between the highly folded structures (Chestnut Ridge anticline) on the east, and the area in which the Oriskany sand becomes patchy in its distribution on the west, seven gas pools have been found in the Oriskany sand on low-relief domes. The history of discovery, stratigraphy, structure of the surface rocks, structure of the Berea sand, convergence between the Berea and Oriskany sands, and structure on the Oriskany sand, together with development, operation, and reservoir data, are discussed for the three most important of these pools, which are Blackhawk, located in South Beaver Township, Beaver County, Pennsylvania, and the Knox and Round Knob located in Knox and adison townships, Columbiana County, Ohio, respectively. End_of_Article - Last_Page 2154------------

Gay-Spencer-Richardson Oil and Gas Trend in West Virginia: ABSTRACT

An outstanding example of the control of oil and gas production by sand distribution is provided by the Berea sand trend extending from Gay in Jackson County, northeastward through Spencer, Roane County, and Richardson, Calhoun County. With the exception of a few undeveloped edge areas, the producing area closely follows the extent of the sand. The producing area varies in width from less than one mile to about three miles. Cross sections show that the sand pinches out in both directions at right angles to the trend and the linear shape strongly suggests a buried beach. Although only the southwestern part of the trend is considered in the paper, the trend is known to continue northeastward to Fink Creek, Lewis County. A total length of over 55 miles. Within the sand body the adjustment of oil and gas to structure is very good, with oil in the synclines and gas on the intervening anticlines. No areas containing only water in the Berea sand are known along the trend. Secondary recovery of oil by means of gas drive is being tried near Spencer, on an experimental basis, with encouraging results. End_of_Article - Last_Page 942------------

Geology of the Saginaw Oil Field, Michigan, and Discussion of Michigan's Oil Prospects

The first drilling for oil at was in 1912 by the Valley Development Company. The wells were located on the south limb of the anticline. Oil was found, though not in commercial quantities, in the Saginaw sand--a dolomitic lime in the Traverse formation. The discovery well leading to the present development was drilled in the fall of 1925 by the Prospecting Company. Most of the production is from the Berea sand of Mississippian age, at depths ranging from 1,800 to 1,860 feet. Wells, after being shot, produce from two or three barrels to forty barrels a day, depending upon location on structure and tightness of sand. The oil is of 46-degree gravity and contains about 48 per cent gasoline. On June 1, two wells were producing from the lime at a depth of 2,300 feet. This lime is in the Traverse formation of Devonian age. Other wells drilled to this pay, and favorably located, have been dry. The total production of the field on June 1 was about 1,400 barrels a day from more than 190 wells. The limit of the field is approximately defined, except at the southeast, where the trend of the pool is into the business district. It is probable that additional production will be found in the eastern part of the state should conditions structurally favorable be found. The thickness of glacial drift and the absence of the Berea sand in western Michigan make this part of the state less favorable for oil and gas development.

Cabin Creek Field, West Virginia

The Cabin Creek field is located in central West Virginia, 20 miles southeast of Charleston, on the Allegheny Plateau. It is owned and operated almost entirely by The Pure Oil Company, and is, therefore, an excellent example of unit operation. The pool is strictly a monoclinal accumulation close to the axis of a syncline. Production comes from the thickened lensed portion of the lower part of the Berea sand found at depths from 2,700 to 3,200 feet. The lens extends parallel to the synclinal axis, over an area 12 miles long by ½ mile wide. There is no water in the Berea sand, and, therefore, the accumulation is by gravity, the oil occupying the lens as far down the slope as the pay lens exists, with gas occurring up the slope to about 1 mile northwest of the oil field The field has been developed since 1914 to the extent of 300 wells, but the known producing area is only a little more than half drilled. The oil averages 47° Be., and is remarkable for its lubricating quality.