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By Bonnie Cooper

3D printing by fused deposition can be used on lunar soil. The soil can be precisely size-separated to make the 3D printing process work efficiently. Using a MASER instead of a LASER would allow us to use the finest fraction of lunar soil, AS-IS, to manufacture things on the Moon.

May 1, 2013

By Walraven F, Knott G. G

Using a typical small logging instrument (Neltronic KPD), a natural gamma reference section for part of the Brockman Iron Formation and part of the Mt. McRae Shale has been established in the Newman area. This is compared with the stratigraphic type section of Trendall and Blockley (1968). Folding and faulting are recognised using natural gamma logs. Because of the confidence with which stratigraphic horizons can be identified, less expenditure on diamond and percussion drilling is required to confirm stratigraphic position. Using natural gamma logs as stratigraphic control the apparent thinning of the Banded Iron Formation during iron enrichment is Demonstrated.

Jan 1, 1973

By Dwight H. Seely, Louis R. Records

A process for low-temperature dehydration of natural gas utilizing Joule-Thomson effect in expansion through a throttling orifice has been tested in a full-scale field installation. The results of these tests are presented in the form of performance curves from which the process may be easily evaluated. The effect of separation temperature on condensate recovery from the process is also shown. INTRODUCTION The transportation of natural gas from producing well to the consumer has always encountered the problem of hydrate prevention. This problem has become increasingly important in the past ten years due to the rapid increase in produced gas volumes, production pressures, transportation pressures and distance from producing wells to consumer. Natural gas, as normally produced from gas or gas-condensate wells, is saturated with water vapor at well-head conditions of temuerature and pressure. The solution of the hydrate problem require; but one basic process — dehydration of the gas to a water content which will result in a water dew-point below the minimum temperature to be encountered from the producing well to the point of consumption. Much of the recent development of gas and gas-condensate reserves in the Gulf Coast Area has been in locations which are accessible only by water. High well-head pressures, pipeline construction and maintenance costs and the desirability of final central gas-condensate separation facilities have stimulated the development of dehydration equipment which can be installed at each well and which will permit hydrate-free transportation of both gas and condensate in the same line to central facilities. There are four types of natural gas dehydration processes now used: 1. Adsorptive processes. 2. Absorptive processes. 3. Chemical reaction processes. 4. Refrigeration processes. The first three of these processes are indirect in that they require use of adsorbents, absorbents or reactive chemicals. These materials require regeneration and part of the total gas stream is consumed in the regenerative process. Indirect processes have a wide range of flexibility as defined by allowable operating pressure and temperature, but most are not easily adapted to automatic operation. The refrigeration process described in this paper was designed for installation at the producing well-head. It requires no regenerative cycle and with normal well-head temperatures no external source of heat. The flexibility of this process is limited only by the pressure drop which may be allowed between well-head and transportation line. THEORY There are three basic physical concepts involved in the low temperature dehydration process. These are: 1. Formation of hydrocarbon hydrates. 2. Joule-Thompson effect resulting from the expansion of gaseous mixtures through a throttling orifice. 3. The equilibrium composition characteristics of water vapor and gaseous hydrocarbon mixture.. The chemical composition and physical structure of hydrate; have been described by several investigators.3,4,5,10 Specific conditions of temperature, pressure and composition as well as the requirements for turbulence and presence of free water necessary for hydrate formation have been described by Katz.6 Natural gas hydrates, as they are found in plugged gas pipe lines, have the appearance of packed snow. The mass of these hydrates has low continuous porosity and permeability. Joule-Thomson effect. or the reduction in temperature which occurs when natural gas is throttled throusll a restrictive orifice, is the basic phenomenon which permits efficient use of refrigeration for the purpose of dehydrating natural gas. Joule-Thomson coefficients for gafeous mixture; of methane with ethane and with butane have been reported by Buder.-I~olzer, Sage and Lacey.2 Brown1 predicted temperature drops for pressure drops from enthalpy-entropy calculations. Aside from this work there were no fundamental data found which would be applicable to natural gas mixtures of varying spe-

Jan 1, 1951

By Dwight H. Seely, Louis R. Records

A process for low-temperature dehydration of natural gas utilizing Joule-Thomson effect in expansion through a throttling orifice has been tested in a full-scale field installation. The results of these tests are presented in the form of performance curves from which the process may be easily evaluated. The effect of separation temperature on condensate recovery from the process is also shown. INTRODUCTION The transportation of natural gas from producing well to the consumer has always encountered the problem of hydrate prevention. This problem has become increasingly important in the past ten years due to the rapid increase in produced gas volumes, production pressures, transportation pressures and distance from producing wells to consumer. Natural gas, as normally produced from gas or gas-condensate wells, is saturated with water vapor at well-head conditions of temuerature and pressure. The solution of the hydrate problem require; but one basic process — dehydration of the gas to a water content which will result in a water dew-point below the minimum temperature to be encountered from the producing well to the point of consumption. Much of the recent development of gas and gas-condensate reserves in the Gulf Coast Area has been in locations which are accessible only by water. High well-head pressures, pipeline construction and maintenance costs and the desirability of final central gas-condensate separation facilities have stimulated the development of dehydration equipment which can be installed at each well and which will permit hydrate-free transportation of both gas and condensate in the same line to central facilities. There are four types of natural gas dehydration processes now used: 1. Adsorptive processes. 2. Absorptive processes. 3. Chemical reaction processes. 4. Refrigeration processes. The first three of these processes are indirect in that they require use of adsorbents, absorbents or reactive chemicals. These materials require regeneration and part of the total gas stream is consumed in the regenerative process. Indirect processes have a wide range of flexibility as defined by allowable operating pressure and temperature, but most are not easily adapted to automatic operation. The refrigeration process described in this paper was designed for installation at the producing well-head. It requires no regenerative cycle and with normal well-head temperatures no external source of heat. The flexibility of this process is limited only by the pressure drop which may be allowed between well-head and transportation line. THEORY There are three basic physical concepts involved in the low temperature dehydration process. These are: 1. Formation of hydrocarbon hydrates. 2. Joule-Thompson effect resulting from the expansion of gaseous mixtures through a throttling orifice. 3. The equilibrium composition characteristics of water vapor and gaseous hydrocarbon mixture.. The chemical composition and physical structure of hydrate; have been described by several investigators.3,4,5,10 Specific conditions of temperature, pressure and composition as well as the requirements for turbulence and presence of free water necessary for hydrate formation have been described by Katz.6 Natural gas hydrates, as they are found in plugged gas pipe lines, have the appearance of packed snow. The mass of these hydrates has low continuous porosity and permeability. Joule-Thomson effect. or the reduction in temperature which occurs when natural gas is throttled throusll a restrictive orifice, is the basic phenomenon which permits efficient use of refrigeration for the purpose of dehydrating natural gas. Joule-Thomson coefficients for gafeous mixture; of methane with ethane and with butane have been reported by Buder.-I~olzer, Sage and Lacey.2 Brown1 predicted temperature drops for pressure drops from enthalpy-entropy calculations. Aside from this work there were no fundamental data found which would be applicable to natural gas mixtures of varying spe-

Jan 1, 1951

By Irwin Politziner F. M. Townsend, L. S. Reid

Recently published data indicate that the water vapor content of a gas, as determined by dew point measurement, is inaccurate when the gas has been dehydrated with diethylene glycol. Water vapor contents and dew point measurements of gases dehydrated with triethylene glycol have been obtained in this investigation in order to determine the magnitude of a similar error, if one exists. Experimental data show a very low concentration of triethylene glycol vapor in gases dehydrated at atmospheric ternperatures and pressures ranging from 500 to 2,500 psia and that the accuracy of dew point measurements is not impaired by the presence of triethylene glycol vapor. INTRODUCTION Nearly all natural gas transported by pipe line to northern and eastern markets must be dehydrated to a low residual moisture content in order to assure maximum transmission efficiency and continuous delivery under peak load conditions. Without dehydration, water vapor often condenses in pipe lines in quantities sufficient to restrict the flow3 and. under low atmospheric temperature conditions, gas hydrates may form and plug gathering. transmission and distribution facilities. Gas may be dehydrated to pipe line specifications by a number of methods. The most widely used methods are (1) adsorption of water vapor on a solid dessicant such as activated bauxite, alumina or silica gel,' (2) by absorption of water vapor by either diethylene or triethylene glycol-water solutions of high glycol concentration,11,13 and (3) by simultaneous expansion-refrigeration of very high pressure gas in which gas hydrates are purposely formed and then quickly decomposed.'"" Of these three fundamental methods, the adsorption and absorption processes provide the bulk of the dehydrated gas moving to market at the present time. The expansion-refrigeration process. a relatively new development, is gaining in favor because of its simplicity but is sharply limited in its application by available differentials between source and gathering system pressures. Where gas sale or purchase contracts contain a maximum water vapor content specification, the water vapor content is usually determined by measuring the dew point of the gas at system pressure. Knowing he dew point temperature and the system pressure, the water vapor content of the gas is determined from a graphical correlation of saturation, or dew point, temperature us the water vapor content of the gas which is customarily expressed as pounds of water vapor per million cubic feet of gas measured at 14.7 psia and 60°F. Dew points are usually measured with the U. S. Bureau of Mines Dew Point Tester. shown in Fig. 1, which is well suited for use at temperatures lower than 120°F and at pressurei; ranging from atmospheric to 3,000 psi. A number of correlations of dew point temperatures vs water vapor content are available,3,5,15 the most recent of which is that by McCarthy et al.4 Where natural gas is dehydrated by absorhing contact with concentrated diethylene glycol-water solutions. considerable difficulty is experienced in observing water dew points due to condensation of liquid hydrocarbon and glycol films on the mirrored surface of the dew point tester. Riesenfeld and Frazierl2 report that the dew point method for determining the water vapor content of a dietllylene glycol-treated natural gas is in error due to the glycol content of the condensate formed on the tester mirror, and that the water vapor content of the gas tested is actually lower than that indicated by the standard' dew point-water vapor content correlation. Extensive experience in testing gases dehydrated by concentrated triethylene glycol-water solutions lias not revesled difficulties of the nature cited above for diethylene glycol. Water dew points are clear and sharp and condensation of

Jan 1, 1951

By L. S. Reid, Irwin Politziner F. M. Townsend

Recently published data indicate that the water vapor content of a gas, as determined by dew point measurement, is inaccurate when the gas has been dehydrated with diethylene glycol. Water vapor contents and dew point measurements of gases dehydrated with triethylene glycol have been obtained in this investigation in order to determine the magnitude of a similar error, if one exists. Experimental data show a very low concentration of triethylene glycol vapor in gases dehydrated at atmospheric ternperatures and pressures ranging from 500 to 2,500 psia and that the accuracy of dew point measurements is not impaired by the presence of triethylene glycol vapor. INTRODUCTION Nearly all natural gas transported by pipe line to northern and eastern markets must be dehydrated to a low residual moisture content in order to assure maximum transmission efficiency and continuous delivery under peak load conditions. Without dehydration, water vapor often condenses in pipe lines in quantities sufficient to restrict the flow3 and. under low atmospheric temperature conditions, gas hydrates may form and plug gathering. transmission and distribution facilities. Gas may be dehydrated to pipe line specifications by a number of methods. The most widely used methods are (1) adsorption of water vapor on a solid dessicant such as activated bauxite, alumina or silica gel,' (2) by absorption of water vapor by either diethylene or triethylene glycol-water solutions of high glycol concentration,11,13 and (3) by simultaneous expansion-refrigeration of very high pressure gas in which gas hydrates are purposely formed and then quickly decomposed.'"" Of these three fundamental methods, the adsorption and absorption processes provide the bulk of the dehydrated gas moving to market at the present time. The expansion-refrigeration process. a relatively new development, is gaining in favor because of its simplicity but is sharply limited in its application by available differentials between source and gathering system pressures. Where gas sale or purchase contracts contain a maximum water vapor content specification, the water vapor content is usually determined by measuring the dew point of the gas at system pressure. Knowing he dew point temperature and the system pressure, the water vapor content of the gas is determined from a graphical correlation of saturation, or dew point, temperature us the water vapor content of the gas which is customarily expressed as pounds of water vapor per million cubic feet of gas measured at 14.7 psia and 60°F. Dew points are usually measured with the U. S. Bureau of Mines Dew Point Tester. shown in Fig. 1, which is well suited for use at temperatures lower than 120°F and at pressurei; ranging from atmospheric to 3,000 psi. A number of correlations of dew point temperatures vs water vapor content are available,3,5,15 the most recent of which is that by McCarthy et al.4 Where natural gas is dehydrated by absorhing contact with concentrated diethylene glycol-water solutions. considerable difficulty is experienced in observing water dew points due to condensation of liquid hydrocarbon and glycol films on the mirrored surface of the dew point tester. Riesenfeld and Frazierl2 report that the dew point method for determining the water vapor content of a dietllylene glycol-treated natural gas is in error due to the glycol content of the condensate formed on the tester mirror, and that the water vapor content of the gas tested is actually lower than that indicated by the standard' dew point-water vapor content correlation. Extensive experience in testing gases dehydrated by concentrated triethylene glycol-water solutions lias not revesled difficulties of the nature cited above for diethylene glycol. Water dew points are clear and sharp and condensation of

Jan 1, 1951

By Fred H. Poettmann

An equation has been derived for use in calculating the sandface pressure of flowing gas wells in which the variation of the compressibility factor of the gas with pressure is taken into consideration. This variation due to compressibility has been put into both graphical and tabular form. Comparison of calculated results with field measured results were made on 20 dry gas wells from a given field and 11 distillate wells from different fields. The agreement between calculated and observed results is good. In addition to their use in the calculation of sandface pressures of flowing wells, the factors can be used in the direct calculation of the static bottom hole pressure of gas wells, the capacity of gas transmission lines, and in the calculation of the theoretical isothermal horsepower necessary to compress a natural gas. Examples demonstrating the use of various equations are given. INTRODUCTION Many of the equations used to calculate the sandface pressures of flowing gas wells from well head data do not take into consideration rigorously the deviation of the natural gas from ideal gas behavior. For low pressure wells this error is not serious. For high pressure wells flowing at high rates this error call be serious. Sandface pressures are used to determine the producing capacity of gas wells as shown in the U. S. Bureau of Mines' Monograph 7.' An equation has been derived for use in calculating the sandface pressure of flowing gas wells in which the variation of compressibility of the gas with pressure is taken into consideration. This variation due to compressibility has been put into both graphical and tabular form. In addition to their use in the calculation of sandface pressures, these "factors" can also be used to give a direct solution in the calculation of the static bottom hole pressure of gas wells, the calculation of the capacity of gas transmission lines, and the calculation of the isothermal horsepower necessary to compress a gas. CALCULATION OF SANDFACE PRESSURE OF FLOWING GAS WELLS The starting point in the derivation of any specific flow equation is an energy balance on the fluid flowing between any two points in the system. This energy balance based on one pound of flowing fluid is expressed by the well known general flow equation: jp~- vdP+ Ah + -— + wt + r. = o . . (i) P, 2 g. where V = specific volume of flowing fluid in cu ft/lb P = pressure in Ib per sq ft ah = difference in height above datum plane in, ft ------ = kinetic energy change of one lb of flowing fluid, v equals velocity in ft/sec and g. = 32.174 Ws = Work done by fluid while in flow (similar to shaft work in driving a turbine) W, = Znergy losses due to the irreversibilities of the flowing fluid This equation contains no limiting assumptions and can be made the basis of any fluid flow relationship by limitations or substitutions. The energy units are usually expressed in term* of foot-pounds of energy per pound of mass. Considering the vertical flow of gas through tubing or annu-lus, the external work W, done by the gas is zero. Let us also assume that the value of the kinetic energy function is small and can be neglected. Equation (1) is reduced to: /P: VdP + Ah+Wt = 0 .......(2) Pi The energy loszes PI can be expressed in terms of the well known Fanning equatinn: 4/Lf: rf = —— ............(3) 2g,D where L = the integrated average velocity in ft/sec of vertical flow in a uniform flow string -~h = L v = the integrated average velocity in ft/sec / = dimensionless correlating function

Jan 1, 1951

By Fred H. Poettmann

An equation has been derived for use in calculating the sandface pressure of flowing gas wells in which the variation of the compressibility factor of the gas with pressure is taken into consideration. This variation due to compressibility has been put into both graphical and tabular form. Comparison of calculated results with field measured results were made on 20 dry gas wells from a given field and 11 distillate wells from different fields. The agreement between calculated and observed results is good. In addition to their use in the calculation of sandface pressures of flowing wells, the factors can be used in the direct calculation of the static bottom hole pressure of gas wells, the capacity of gas transmission lines, and in the calculation of the theoretical isothermal horsepower necessary to compress a natural gas. Examples demonstrating the use of various equations are given. INTRODUCTION Many of the equations used to calculate the sandface pressures of flowing gas wells from well head data do not take into consideration rigorously the deviation of the natural gas from ideal gas behavior. For low pressure wells this error is not serious. For high pressure wells flowing at high rates this error call be serious. Sandface pressures are used to determine the producing capacity of gas wells as shown in the U. S. Bureau of Mines' Monograph 7.' An equation has been derived for use in calculating the sandface pressure of flowing gas wells in which the variation of compressibility of the gas with pressure is taken into consideration. This variation due to compressibility has been put into both graphical and tabular form. In addition to their use in the calculation of sandface pressures, these "factors" can also be used to give a direct solution in the calculation of the static bottom hole pressure of gas wells, the calculation of the capacity of gas transmission lines, and the calculation of the isothermal horsepower necessary to compress a gas. CALCULATION OF SANDFACE PRESSURE OF FLOWING GAS WELLS The starting point in the derivation of any specific flow equation is an energy balance on the fluid flowing between any two points in the system. This energy balance based on one pound of flowing fluid is expressed by the well known general flow equation: jp~- vdP+ Ah + -— + wt + r. = o . . (i) P, 2 g. where V = specific volume of flowing fluid in cu ft/lb P = pressure in Ib per sq ft ah = difference in height above datum plane in, ft ------ = kinetic energy change of one lb of flowing fluid, v equals velocity in ft/sec and g. = 32.174 Ws = Work done by fluid while in flow (similar to shaft work in driving a turbine) W, = Znergy losses due to the irreversibilities of the flowing fluid This equation contains no limiting assumptions and can be made the basis of any fluid flow relationship by limitations or substitutions. The energy units are usually expressed in term* of foot-pounds of energy per pound of mass. Considering the vertical flow of gas through tubing or annu-lus, the external work W, done by the gas is zero. Let us also assume that the value of the kinetic energy function is small and can be neglected. Equation (1) is reduced to: /P: VdP + Ah+Wt = 0 .......(2) Pi The energy loszes PI can be expressed in terms of the well known Fanning equatinn: 4/Lf: rf = —— ............(3) 2g,D where L = the integrated average velocity in ft/sec of vertical flow in a uniform flow string -~h = L v = the integrated average velocity in ft/sec / = dimensionless correlating function

Jan 1, 1951

By R. H. Olds, B. H. Sage

The transient flow of gases in long pipe lines is a problem of industrial interest. The present discussion deals with the application of the conservation of momentum and material to the transient flow of gas in conduits which are long with respect to their diameter. Solutions of the resulting equations include consideration of variations in friction and specific volume of the fluid as functions of time and position along the conduit. The changes in state along the pipe line are established as a function of time. The methods proposed may be extended to other situations. The flow of compressible fluids under steady conditions' has been considered in detail. Primary emphasis was placed on the development of simple means of taking into account the non-uniform flow' realized in long conduits under such conditions. Binder2 discussed the essential differences between the flow of compressible and uoncompressible fluids. Bonilla" proposed direct methods of solution for equations describing isothermal flow in long pipes. Similar considerations limited to steady flow have been discussed by Ruth.' Palsgrove 5 sugrested a graphical means of solving specific problems relating to the flow of gases in conduits of uniform section. Some of the basic concepts of the flow of a compressible viscous fluid in straight tubes have been described by Kuo.6 Problems of this type require knowledge of the equation of state of the fluid. In many cases it liar been convenient to assume that the fluid follows the relationship ascribed to a perfect gas. The treatment of unsteady flow of compressible fluids is less complete. This state of affairs result* from the fact that the differential equations relating pressure and flow rate with time and position for unsteady flow are nonlinear in character.' Muskat and Wyckoff presented an excellent treatment of the situation in laminar Bow where inertia forces were not of controlling importance. Somewhat earlier Hurst9 discussed the uncteady flow of fluids in petroleum reservoirs. Helhering-ton. MarRoberts. and Huntington'" established experimentally the pressure distribution and accumulative flow rate of natural gas through an unconsolidated sand. Recently Joffe11,12 conhitlcretl the specific problem of the flow of natural gas in relatively long.,. pipe lines for unsteady conditions with emphasis upon the economic feusibility of the storage of gas in such a reservoir. These discussions were based upon approximations of the partial differential equations applying to the condititons of flow. The results were descriptive of the physical situation and indirated the effertiveness of large pipe lines as cyclic storage facilities for natural gas. The advent of analog computers" has increased materially the practicality of solving nonlinear partial differential expressions. Several iterative numerical and graphical methods14,15,16 have been developed to solve nonlinear equations. However, it appears that the pair of simultaneous nonlinear partial differential equations involved in problems of this nature are not directly susceptible to solution by presently available analog computer or formal iterative numerical techniques. Nevertheless. graphical analyses afford a means of obtaining data of engineering value without special equipment. MATHEMATICAL CONSIDERATIONS Since the length of the conduit is large in comparison to the cross section in the cases to be considered, it is possible to treat the characteristics of the flow as independent of position in the cross section of the conduit. This possibility follows since the energy- connected with the velocity profile is small compared to that required to overcome the friction associated with its movement throughout the length of the line. Average values of the pressure. velocity. kinetic energy. momentum, and specific volume may he assigned to the fluid at any particular cross section. From a mathematical viewpoint this may be expressed in the following way for velocity: µ = µ(?X)..........(1) The uncertainties introduced by such assumptions usually are negligible when the ratio of length to diameter is greater than the order of 1.000. On this basis a volume element ma!. be considered to occupy the entire cross section of the conduit. Such an element is presented in Fig. 1.

Jan 1, 1951

By R. H. Olds, B. H. Sage

The transient flow of gases in long pipe lines is a problem of industrial interest. The present discussion deals with the application of the conservation of momentum and material to the transient flow of gas in conduits which are long with respect to their diameter. Solutions of the resulting equations include consideration of variations in friction and specific volume of the fluid as functions of time and position along the conduit. The changes in state along the pipe line are established as a function of time. The methods proposed may be extended to other situations. The flow of compressible fluids under steady conditions' has been considered in detail. Primary emphasis was placed on the development of simple means of taking into account the non-uniform flow' realized in long conduits under such conditions. Binder2 discussed the essential differences between the flow of compressible and uoncompressible fluids. Bonilla" proposed direct methods of solution for equations describing isothermal flow in long pipes. Similar considerations limited to steady flow have been discussed by Ruth.' Palsgrove 5 sugrested a graphical means of solving specific problems relating to the flow of gases in conduits of uniform section. Some of the basic concepts of the flow of a compressible viscous fluid in straight tubes have been described by Kuo.6 Problems of this type require knowledge of the equation of state of the fluid. In many cases it liar been convenient to assume that the fluid follows the relationship ascribed to a perfect gas. The treatment of unsteady flow of compressible fluids is less complete. This state of affairs result* from the fact that the differential equations relating pressure and flow rate with time and position for unsteady flow are nonlinear in character.' Muskat and Wyckoff presented an excellent treatment of the situation in laminar Bow where inertia forces were not of controlling importance. Somewhat earlier Hurst9 discussed the uncteady flow of fluids in petroleum reservoirs. Helhering-ton. MarRoberts. and Huntington'" established experimentally the pressure distribution and accumulative flow rate of natural gas through an unconsolidated sand. Recently Joffe11,12 conhitlcretl the specific problem of the flow of natural gas in relatively long.,. pipe lines for unsteady conditions with emphasis upon the economic feusibility of the storage of gas in such a reservoir. These discussions were based upon approximations of the partial differential equations applying to the condititons of flow. The results were descriptive of the physical situation and indirated the effertiveness of large pipe lines as cyclic storage facilities for natural gas. The advent of analog computers" has increased materially the practicality of solving nonlinear partial differential expressions. Several iterative numerical and graphical methods14,15,16 have been developed to solve nonlinear equations. However, it appears that the pair of simultaneous nonlinear partial differential equations involved in problems of this nature are not directly susceptible to solution by presently available analog computer or formal iterative numerical techniques. Nevertheless. graphical analyses afford a means of obtaining data of engineering value without special equipment. MATHEMATICAL CONSIDERATIONS Since the length of the conduit is large in comparison to the cross section in the cases to be considered, it is possible to treat the characteristics of the flow as independent of position in the cross section of the conduit. This possibility follows since the energy- connected with the velocity profile is small compared to that required to overcome the friction associated with its movement throughout the length of the line. Average values of the pressure. velocity. kinetic energy. momentum, and specific volume may he assigned to the fluid at any particular cross section. From a mathematical viewpoint this may be expressed in the following way for velocity: µ = µ(?X)..........(1) The uncertainties introduced by such assumptions usually are negligible when the ratio of length to diameter is greater than the order of 1.000. On this basis a volume element ma!. be considered to occupy the entire cross section of the conduit. Such an element is presented in Fig. 1.

Jan 1, 1951

By Edmund C. Bovey

"AS I begin my remarks this morning, please let me say how honoured and gratified I was to receive your invitation to address you here during your deliberations in historic Quebec City. The high esteem in which your Institute is held is reflected in the respect and deference accorded to it by industry across Canada. I feel privileged to be here with you today.I would like to discuss with you some applications of natural gas in the mining industry and suggest to you, in closing, some possible avenues of future development.Natural gas first became avail-able for industrial purposes in Northern Ontario in late 1958. Acceptance of natural gas, as a source of energy by the industry of that area, has been both widespread and gratifying. The mining industry of Northern Ontario has in-creased its annual use of natural gas by approximately 35 per cent each year since 1958. We believe that this trend will continue, al-though we will probably have to accept a more modest 10 per cent annual gain as the market approaches saturation. I would like to explain how we were able to do this and where all this gas is used. Our first sales were largely a matter of price-and the savings we offered were substantial."

Jan 1, 1966

By Francis J. Quinn

The Natural Gas Act, of 1938, which put interstate pipelines under the jurisdiction of the Federal Power Commission, did not place a protective competitive shield around such companies - nor does any provision of the act guarantee them a profit. Natural-gas pipelines are competitive with each other and also with the coal and oil industries. Gas distributing companies must compete not only with the coal and oil industries, but also with the electric industry. Natural gas has captured markets from oil, which had taken them from coal. Oil men contend that gas prices have: been, held to an artifically low level by regulation. The electric industry is moving into the space-heating market, which pleases the coal people because the coal industry's largest customer since losing the railroads to dieselization has been the electric companies. The coal industry is attempting to monopolize the industrial and electric generating market through government intervention, and this is being done under the guise of concern for the national welfare through advocation of a "National Fuels Policy purporting to, further the cause of fuel conservation. Such a policy is contrary to American principles and would result in the individual's loss of freedom of choice and ultimately, in less reserves of preferred fuels because of diminished exploration efforts.

Jan 1, 1961

By Louis V. Bender

THIS paper gives a short review of the installation for and the use of gas, as a. fuel, at the Anaconda Reduction Works of the Anaconda Copper Mining Co. Before putting in gas tile fuels used were pulverized coal, lump coal, coke distillate and oil. These fuels are now almost entirely eliminated. For nearly fifty years bituminous coals from Wyoming and Montana fields had been used. These coals were of a good grade, analyzing 11,300 B.t.u. and having an ash content of 12 per cent. When hydro-electric power replaced steam-driven equipment, the coal requirements were reduced; and, on account of improvements in metallurgy and/ or in furnace design, the quantity was lessened. Later, oil and distillate were introduced and used in some of the operations. All of these things tended toward the lessening of the amount of coal used, and had it not been for the increase in the size of the plant, the tonnage used would have been small when the change was made to gas.

Jan 1, 1932

By E. R. MARBLE

THE introduction of a new fuel, such as natural gas, necessitates careful study where it has not been used previously. At the El Paso smelter natural gas required the installation of apparatus with which no one at the plant was familiar, either as to the type of equipment needed or as to the burning of the gas in it. Observation of existing installations of a similar character and assistance from gas engineers served as a basis to determine what was advisable to use. The gas line entering the plant goes to a metering station equipped with a duplicate system of pressure regulators, a temperature recorder and the gas company and smelter orifice meters in tandem. There are three distribution lines that can be inter-connected at a later date, if necessary, to assist in equalizing the plant load. All the larger lines are of heavy

Jan 1, 1930

By Lyon F. Terry

IN contemplating the prospects of natural gas being transported from the fields where it is produced to such distant points as Philadelphia, New Jersey, New York City, and New England, let us review the advance that natural gas has made and the projects currently scheduled for construction. This may give us a perspective of the point in the long-range development of the natural gas business in which we now find ourselves, and some basis for judging the further expansion of the industry. Authentic statistics of the total marketed production of natural gas in the United States have been compiled by the Bureau of Mines since the year 1906. The growth of the business is indicated by the following data on marketed production for each ten-year interval since 1906:

Jan 1, 1947

By Don B. Carson, Donald L. Katz

NATURAL gases under pressure form crystal-line hydrates with water. Experimental data are reported on four-phase equilibrium for the methane-propane-water, methane-pentane-water, and methane-hexane-water systems. Temperatures and pressures for equilibrium between gas, water-rich liquid, hydrocarbonrich liquid, and hydrate were measured, as well as the percentages of methane and propane in the hydrate. The data indicate that natural gas hydrate behaves as a solid solution and that pentanes and heavier hydrocarbons do not enter into the solid phase. Vapor-solid equilibrium constants are presented that permit the approximation of the conditions for hydrate formation, from the composition of a gas. INTRODUCTION Natural gas hydrates have been the object of considerable research in recent years, because of the trouble they have caused in the natural-gas and natural gasoline industries. Natural gas hydrates are white crystalline compounds of water and gas, which, under pressure, exist at temperatures considerably above the freezing point of water. Because of the relatively high temperatures at which the hydrates exist, they become a nuisance in high-pressure gas operations where water is present, since their formation causes partial or complete plugging of valves and pipes. From a practical standpoint, the trouble incident to hydrate formation has been solved by dehydration of the gas before it enters the plant or pipe line, or by other remedial measures. Extensive work on gas hydrates in the latter part of the nineteenth century, by Villard1 and others, gave data on methane hydrate and on ethane hydrate. Schroeder summarized these theoretical studies.2 Hammerschmidt3 introduced the information on gas hydrates to the gas industry and Deaton and Frost4-6 gathered a considerable number of data on the behavior of natural gas hydrates. Recent papers7,8 have extended both the data and the theory of these hydrates. At present, data are available on temperatures and pressures of hydrate formation for pure methane, ethane, propane, n-butane, methane-ethane mixtures, methane-propane mixtures, methane-butane mixtures, and some 15 natural gases, all in the presence of excess water. However, up to the present time no method has been available for predicting the temperature at given pressures or the pressure at given temperatures at which natural gases will form hydrates if saturated with water. This paper pre¬sents data on the methane-propane-water, methane-pentane-water and methane-hexane water systems in four phases, one of which is the hydrate. The application of the phase rule to the methane-propane-water data proves that hydrates behave as solid solutions. The data of this paper and those in the literature were used to develop vapor-solid equilibrium constants,8 which permit prediction of conditions of hydrate formation from the analysis of a natural gas.

Jan 1, 1941

By R. T. Elworthy

Canada ranks second in the list of world consumers of natural gas. In 1923 our production was nearly fifteen million thousand cubic feet valued at $5,800,000. Our output, however, appears very small compared with that of the United States, which in 1923 totalled over one thousand and eight million cubic feet, valued at $240,000,000. Natural gas is found in commercial quantities in three? provinces in Canada. New Brunswick: Natural gas in New Brunswick has been utilized commercially only since 1912,although the investigation of oil and gas possibilities of the province commenced as early as 1859. The annual production is a little more than one-twentieth of the total Canadian production and remains fairly constant from year to year. Ontario: In Ontario the earliest gas wells were drilled in Essex and Welland counties between the years 1885 and 1890. On account of the small demand in Canada the cities of Detroit and Buffalo were supplied with large quantities of gas from these wells, but this export was curtailed in 1898 and finally ceased in 1900. The production of natural gas in Ontario, mainly from fields in Lambton, Kent, Essex, Norfolk, Haldimand and Welland counties, increased rapidly from 1900 until the peak was reached in 1917, when over nineteen million thousand cubic feet valued at $3,641,587 was consumed.

Jan 1, 1925

By J. E. Powers, T. D. Taylor, N. E. Wood

A computer program has been developed to simulate a gas transmission 1ine operating under transient conditions. The program was developed by application of the basic mass and momentum balance equations. The nonlinear equations thus obtained were transformed by the method of characteristics and finite-difference techniques to make them suitable for machine computation. Three tests of the computer program were made. In each of these, the initial condition was assumed to be steady-state flow, the inlet density was held constant at the initial condition, and the outlet mass flow rate was varied with time. One test was theoretical in nature, but the others were made for direct comparison with actual field data. Results of the tests are presented in graphical form. INTRODUCTION Theoretical investigations of the transient flow of gas in long pipelines have been limited in number. In 1951, Olds and Sage4 developed a gaphical method of solving the nonlinear flow equations describing transient gas flow in a long pipeline. Research in this field at the U. of Oklahoma was initiated by Nelson1 in 1956. Nelson utilized a computer to solve numerical equations involving a lengthy trial-and-error procedure, and his results have been reported in the literature? It does not seem likely that Nelson's method can be extended to the analysis of transient behavior of pipeline networks; therefore, the investigation to be discussed in this paper was undertaken to improve and extend the previous work. The following discussion presents, briefly: (1) the basic differential equations governing transient flow, (2) transformation of these equations into a form suitable for machine computation. (3) role of boundary conditions in the calculations, (4) a very brief description of the computer program which was developed to simulate the pipeline and (5) results of tests of the computer program.

By L. K. Nemeth, H. T. Kennedy

The investigation presented in this paper was performd to develop a relationship between the dewpoint pressure of a hydrocarbon reservoir fluid and its composition, temperature and characteristics of the heptanes-plus fraction. This is part of an over-all program to develop correlations for the essential properties of reservoir fluids with the composition, temperature and pressure. In all, 579 dewpoint pressures, determined experimentally on 480 different condensate systems along with their compositions and temperatures, were obtained from the literature and from previously unpublished sources. Compositions were expressed in terms of mol fractions of methane through heptanes-plus, nitrogen, carbon dioxide and hydrogen sulfide, and the molecular weight and specific gravity of the heptanes-plus fraction. Distribution of the samples assured a good representation of most of the major oil-producing areas in the world. A multiple regression analysis program written for the IBhl 7094 digital computer was used to compare numerous equations and to calculate their coefficients. The final equation containing 11 coefficients resulted in an average absolute deviation of 7.4 percent for all the samples. Segregation of data on the basis of one or more variables did not materially improve the results. The correlation developed is useful in predicting the dewpoint pressure of condensate reservoir fluids from variables normally measured in the laboratory. INTRODUCTION In any discussion of the dewpoint of hydrocarbon mixtures, it should be noted that there are two kinds of dewpoints which must be distinguished. The first type, or normal dewpoint, usually occurs at low pressures as dry gas is compressed to the point where liquid first forms. The second type, sometimes called the retrograde dewpoint, occurs when a gas mixture containing heavy hydrocarbons in solution is depressured until a liquid is formed. The first type, as applied to condensate mixtures, would normally be below atmospheric pressure and would be of no interest in reservoir performance. The second type is of great significance in interpreting reservoir behavior and is the property referred to throughout this paper. Laboratory measurement of dewpoints is laborious, expensive and subject to many errors, and it is desirable to find a reasonably accurate method to predict dewpoint pressures from the composition and other readily available properties normally measured on the fluids. A possible method of calculating dewpoint pressures would be to employ a set of equilibrium ratios (K-values). 1 However, the K-values themselves depend on composition as well as temperature and pressure; presently their use adds nothing to the accuracy of predicting dewpoints. If future correlations provide a significantly better method of estimating K-values for heavy hydrocarbons, they may be of greater use. REVIEW OF LITERATURE In 1944, Olds, Sage and Lacey 2 studied the behavior of fluids from the Paloma field. Properties of seven mixtures were studied at temperatures ranging from 100 to 250 F and at pressures up to 5,000 psia. From the information obtained, the influence of composition and temperature upon the dewpoint was determined. It was found that removal of the intermediate molecular weight components from the mixture resulted in considerable increases in the dewpoint pressures. Results indicated that the effect of changes in temperature was relatively minor when compared with the effect of modifying the mixture by removing the intermediate components. Thus, removal of propane and butanes resulted in an increase in dewpoint pressure more than 10 times greater than a change in temperature from 100 to 250 F. The authors stated that althouah

By J. H. Henderson, H. J. Ledbetter, N. B. Gove, J. D. Griffith

INTRODUCTION The results of a series of laboratory flood tests using liquid Iso-butane to displace refined oils from test cores are pre- ented and interpreted on an empirical bask. The study Revealed the similarity of the miscible liquid displacement to that of the immiscible-fluid displacement mechanism. The efficiency of the iso-butane flood decreased markedly as the oil Viscosity increased. but the effect of injection rate on the effectiveness of the primary production stage was negligible over the range investigated. The presence of free-gas saturation prior. to iso-butane breakthrough increased the volume of iso- Butane required to recover a given percentage of the oil present. Injection of liquid i.e.-butane prior to water follicle sculpted in a marked improvement in oil recovery by the water flood. INTRODUCTION The production of petroleum is often enhanced by the injec-1i1)n of extraneous fluids into the reservoir. It has been suggeited that the injection or cycling of a wet gas or a liquefied petroleum gas would he instrumental in increasing the effic.ienr!; of oil recover! to a greater degree than the commonly injected fluids. dry pas and water. Although instances of injection of light liquid hydrocarbons are not unknown, a systrmatic recording of the result is unavailable and superfi- cially, the practice gives the impression of being economicaIIy unsound. For specific types of displacement, analytic: solutions have been advanced which aid in understanding the physical mechanisms involved. However, there is no generalized theoretical concept which permits adequate prediction of displacement efficiency from a knowledge of readily measured reservoir rock and fluid properties. The Buckley-Leverett approach to oil displacement by an immiscible phase is an admirable analysiy of that type of mechanism. Dykstra and Parsons have introduced a useful concept in their evaluation of the role of the mobility ratio and its merit in rationalizing displacement phenomena. Everett, Gooch and Calhoun3 in their report on the effect of viscosity ratio and miscibility have pointed out the lack of a comprehensive theoretical approach and the desirability of investigating the mechanism of miscible-miscible displacement. In lieu of a well-developed theory concerning miscible-111isci1)le displacement and in view of the scarcity of engineering information on actual LPG injection trials, the limited program of laboratory experimentation described below was undertaken. OBJECTIVES The original broad objectives of the program, to study the oil recovery process using LPG as the displacing phase, defined the direction and scope of the laboratory tests. The specific objective. of the experimentation were to evaluate

Jan 1, 1953