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4 2 Petroleum fluid properties Treccani
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OIL FIELD CHARACTERISTICS AND RELEVANT STUDIES, development of a hydrocarbon field because it serves Pure components. as the basis for the design of the production plan Fig 1 illustrates the behaviour of a pure component. Even though the behaviour of these fluids is very by means of a pressure volume diagram which can be. complex it can be explained on the basis of the described in the following way Starting from point A. behaviour of simple fluids As a result the behaviour the component in the liquid state and gradually. of pure components is covered first before going on to increasing the volume at constant temperature the. that of binary mixtures bearing in mind that the real following phenomena are observed a a rapid. fluids obey the same rules decrease in pressure b the appearance of the first. bubbles of gas at point B c the increase in volume of. the gas phase and the decrease in that of the liquid. phase at constant pressure line joining B to R d the. A disappearance of the last drop of liquid point R and. e the much slower decrease in pressure,T TC This series of phenomena occurs for all. temperatures below the critical temperature TC Above. this temperature the component remains in a single. phase and is referred to as being in the supercritical. B state The set of bubble points form the bubble curve. while the dew points give rise to the dew curve, volume It is also possible to represent the behaviour of a. pure component on a pressure temperature diagram,Fig 1 Pressure volume diagram Fig 2. of a pure component All of the conditions at which the liquid and gas. Two isothermal curves for temperature, phases can co exist are represented by the curve AC.
lower than the critical temperature, and one dashed line where the bubble and dew curves are merged In fact. for higher temperatures are shown according to the phase rule at each temperature there. Points B and R are the bubble point is only one pressure value for which the fluid can have. and the dew point respectively two phases if the number of components of a fluid is. given by n and the number of phases is given by f, then the variance of the system V that is the number. critical point of intensive properties temperature pressure. C composition of each phase that need to be fixed in. order to determine the state of the system is given by. liquid V n 2 f,This curve is known as the vapour pressure curve. A and ends at the critical point point C beyond which. E triple point,the fluid always has a single phase The line AS. temperature represents the liquid solid equilibrium line which. Fig 2 Pressure temperature diagram corresponds to the line of melting points of the pure. of a pure component component The curve AE is the line of sublimation. on this line the solid is in equilibrium with the vapour. The intersection of the line AC AS and AE, corresponds to the triple point representing the only.
I pair of values of pressure and temperature at which the. three phases can co exist,R As with a pure component the behaviour of a. mixture can be represented on a pressure volume,diagram Fig 3 Starting from point I situated at a. volume temperature below the mixture s critical temperature. and moving towards larger volume the following, Fig 3 Pressure volume diagram phenomena can be observed a a rapid decrease of the. of a mixture pressure in the liquid phase b the appearance of the. 488 ENCYCLOPAEDIA OF HYDROCARBONS,PETROLEUM FLUID PROPERTIES. Fig 4 Phase envelope bubble point curve dew point curve. of a mixture,cricondenbar Ru,liquid vapour,cricondentherm.
temperature, first bubbles of gas at point B which represents the the reservoir in the liquid or gaseous state or in state. bubble point c the increase of the volume of the gas of equilibrium between these two phases The. phase and the decrease of the volume of the liquid reservoir fluids are composed of a wide range of. phase but in this case instead of remaining constant components that can have a greatly variable number of. the pressure decreases during the phase change d carbon atoms The lightest are gaseous under ambient. the disappearance of the last drop of liquid at point R conditions CO2 N2 CH4 while the heaviest which. the dew point and e the slow decrease in pressure contain several hundred carbon atoms are almost. beyond point R where the entire mixture is in the gas solid The crude also contains sulphurated compounds. If the behaviour of a mixture is represented on a mainly hydrogen sulphide and mercaptans which. pressure temperature diagram Fig 4 a two phase cause various types of problems including problems. region appears and not simply a two phase line as in related to their toxicity. the case of a pure component The bubble and dew Helium heavy metals mercury nickel and. curves no longer coincide but instead intersect at the vanadium as well as traces of organo metallic. critical point The critical point can be situated either compounds may also be present. to the left or to the right of the maximum of the, saturation curve and thus does not correspond to the Reservoir classification. maximum pressure and temperature of the two Reservoir fluids can be conveniently classified by. phases in contrast to the case of a pure component referring to the characteristics of their phase envelopes. In fact there is a pressure greater than the critical see also Chapter 1 1 Petroleum fluids are generally. pressure above which the two phases can co exist classified into two large families depending on. This pressure is called the cricondenbar In the same whether the reservoir temperature is above or below. way the cricondentherm corresponds to the the critical temperature of the fluid Fig 5. maximum temperature above which the two phases The term oil is used to describe reservoir fluids. cannot co exist with a critical temperature higher than the temperature. If the cricondentherm is greater than the critical of the reservoir while the term gas is used to identify. temperature of the mixture decompressing the gas those with a critical temperature lower than that of the. starting from point A the dew curve is crossed at the reservoir. upper dew point Ru where the first drop of liquid, appears Continuing the decompression the volume of. the liquid deposit goes through a maximum point M bubble point curve dew point curve. and then decreases before finally dropping to zero at. the lower dew point Rl This is the phenomenon of C. retrograde condensation which is frequently condensate. encountered in reservoir fluids such as gas oil,condensates. 4 2 3 Fluid classification temperature,Fig 5 Location.
Reservoir fluids behave in a similar way to binary of different types. mixtures Depending on their composition and on the of fluid. reservoir pressure and temperature they may exist in on the phase envelope. VOLUME I EXPLORATION PRODUCTION AND TRANSPORT 489,OIL FIELD CHARACTERISTICS AND RELEVANT STUDIES. Oils have the characteristic of liberating a certain Gases can be classified into three subfamilies In. quantity of gas starting from the bubble point when each of these cases the reservoir temperature is above. they are subject to an isothermal expansion Depending the critical temperature of the mixture but may be. on whether the reservoir pressure is higher lower or above or below the cricondentherm Tmax in Fig 5. equal to the bubble point pressure oils are classified as The reservoir contains a gas condensate if the. undersaturated oversaturated or saturated reservoir temperature TR is lower than the. An oil is referred to as a low or high shrinkage oil cricondentherm and higher than the temperature at the. depending on the quantity of gas liberated under critical point and the reservoir pressure PR is higher. expansion Further distinctions are possible by taking or equal to the saturation pressure An isothermal. into account the composition of the gas A low expansion of such a gas Fig 6 beginning from the. shrinkage oil liberates a small quantity of gas which is saturation pressure upper dew point Ru leads to the. usually dry A high shrinkage oil or volatile oil formation of a liquid phase On reduction of the. liberates a large quantity of gas which generally pressure the volume of this liquid phase increases to a. contains constituents that condense at surface maximum M and subsequently decreases to zero. conditions The presence of a volatile oil is suspected when lower than the lower dew point Rl As already. when the volumetric Gas Oil Ratio GOR is greater mentioned this phenomenon is known as retrograde. than 200 300 and the API gravity of the oil is greater condensation It does not occur in the case of a pure. than 40 component in which an isothermal expansion of the. gas phase never gives rise to a liquid phase but instead. leads to direct vaporization This behaviour of, bubble point curve dew point curve vaporization is also observed in the case of a gas. PR condensate but only when the expansion is continued. reservoir conditions, Ru above point M The main difference between a volatile. oil and a gas condensate resides in the nature of the. M heavy fraction The molar mass and quantity of the C7. fraction of a volatile oil are larger than those of a gas. Rl condensate in general it is rarely observed that a gas. condensate contains a C7 fraction with a molar,percentage greater than 15. temperature,If the reservoir temperature is higher than the.
Fig 6 Phase envelope of a gas condensate cricondentherm and if the point representing the. surface conditions Psep and Tsep which are the, conditions of the separator reside within the phase. envelope the gas is said to be wet Fig 7 This means. reservoir conditions, PR that liquid will be produced at surface conditions. C without however the occurrence of retrograde,condensation in the reservoir This situation very. rarely occurs If on the other hand the point,Psep separator. representing the surface conditions lies outside the. phase envelope the gas is said to be dry Fig 8 and. will not lead to the production of liquid at the surface. temperature In this extreme case the GOR is almost infinite. Fig 7 Phase envelope of a wet gas,4 2 4 Lateral and vertical.
PR reservoir conditions distribution of hydrocarbons. in reservoir, C There are a number of theories regarding the formation. of petroleum from organic matter all of which, converge on the conclusion that the composition of the. Psep separator reservoir fluid depends on its environment its. Tsep TR geological maturity and on the migration process from. temperature the source rock to the reservoir rock These factors can. Fig 8 Phase envelope of a dry gas cause significant variations in the lateral and vertical. 490 ENCYCLOPAEDIA OF HYDROCARBONS,PETROLEUM FLUID PROPERTIES. composition in reservoirs in different areas around the as is known will never succeed in taking all factors. world Even though reservoirs are usually considered to into account The most important effects are related to. have reached a state of equilibrium a significant gravity Gibbs 1961 proposed a mathematical model. number of these exhibit phenomena of lateral and capable of evaluating the composition gradient caused. vertical variations in composition Hamoodi and Abed by gravity in the absence of temperature gradients In. 1994 Hamoodi et al 1996 In the well known case of these conditions the heavier components are found in. a reservoir in Abu Dhabi the fraction of H2S varies the lower part of the reservoir while the lightest are. laterally from 1 to 12 in spite of excellent reservoir found in the upper part Schulte 1980 and Montel. communication and therefore this phenomenon 1993 proposed a model of this phenomenon based on. cannot be explained by the subdivision of the reservoir the equations of state However the quantification of. into separate zones Firoozabadi et al 1996 Another these phenomena is very complex and the effects of. similar example is a reservoir in the North Sea in their reciprocal influence is not precisely known For. which the methane concentration varies from 55 to example some authors Holt et al 1983 sustain that. 73 along a depth interval of 81 metres Danesh the thermal effect may be of the same order of. 2003 Volatile oils and fluids containing asphaltenes magnitude as the gravitational effect and that both act. are particularly sensitive to these variations The lack of in the same direction while other researchers have. the evaluation of such effects during the development arrived at the opposite conclusion Ghorayeb and. study can lead to considerable errors in the estimation Firoozabadi 2001. of the reservoir properties the quantity of reserves in In any case it is certain that the lateral and vertical. place and the recovery factor The margin of error may variations of the composition can be significant. reach 50 on the volume of the condensate in place especially in the case of volatile oils and gas. and up to 20 on the volume of gas in the case of gas condensates and it is indispensable to take them into. condensates Similarly the calculation of the consideration during reservoir studies for the. cumulative production can be either under or over development of the field As the factors for these. estimated by more than 20 Jaramillo 2001 variations are numerous and difficult to integrate into. The causes of this heterogeneity are numerous and a model it is important to take samples from different. may be related to thermodynamic phenomena reservoir wells with the aim of calibrating the models. characteristics or the phenomena of generation, migration and accumulation of the hydrocarbons The. thermodynamic processes of gravitational segregation 4 2 5 Sampling. thermal diffusion caused by the thermal gradient and. natural convection lead to the creation of An accurate knowledge of a fluid s thermodynamic. heterogeneities while molecular diffusion caused by behaviour requires representative samples of the. concentration gradients leads to homogenization of the reservoir fluid to be taken The study performed on. fluid Concerning the reservoir the characteristics these samples provides data for the calculation of the. capable of leading to a heterogeneous distribution are reserves in place the calculation of flow in the porous. variations in the permeability porosity wettability and medium as well as for the design and the. more generally all of the reservoir heterogeneities determination of the size of the surface facilities and. Finally differences between source rocks and the development scheme that would allow an optimal. maturation processes as well as phenomena of recovery of fluid The necessity of having. biodegradation and precipitation of asphaltenes or representative samples available appears even more. resins may also contribute to the formation of a important when the investment required for the design. heterogeneous distribution of reservoir fluids process is taken into account especially in the case of. All of these phenomena are very difficult to model offshore fields These studies should also enable the. For this reason it is necessary to take samples from identification of behaviour such as the precipitation of. different wells distributed over the entire area of the asphaltenes and paraffins or the formation of. reservoir hydrates, Regarding thermodynamic phenomena the vertical The quantity of fluid required depends on the type.
thermal gradient found in most parts of the reservoir of laboratory study to be conducted For example if. induces diffusion but not necessarily convection on one hand a classical PVT Pressure Volume. Firoozabadi et al 1996 In contrast a lateral thermal Temperature analysis is to be carried out a relatively. gradient observed in some reservoirs can small amount of fluid will be required especially. simultaneously induce thermal convection and considering that modern PVT equipment is capable of. diffusion phenomena Constructing a model that takes analysing ever smaller samples If on the other hand a. these phenomena into account is complex and as far more in depth characterization analytical and or. VOLUME I EXPLORATION PRODUCTION AND TRANSPORT 491,OIL FIELD CHARACTERISTICS AND RELEVANT STUDIES. thermodynamic needs to be performed a condensates The possibility of maintaining the. correspondingly larger sample will be required This is samples in a single phase until the laboratory analysis. particularly true in cases when the heavy fraction of deters the precipitation of asphaltenes whose. the fluid needs to be accurately characterized If the redissolution is always problematic Bottomhole. fluid to be sampled is a gas condensate in which the sampling can be performed only when the pressure in. proportion of the heavy fraction is relatively low it the well is greater than the saturation pressure of the. will be necessary to take a significant amount of fluid reservoir fluid otherwise the sample taken will not be. in order to perform an accurate analysis of the representative of the original reservoir fluid However. condensate Also in the case of the characterization of when this is the only type of sampling possible when. the heaviest fraction of oil containing asphaltenes or the reservoir pressure corresponds to the saturation. heavy paraffins adequately large samples of fluid will pressure or when the flowing pressure in the well is. be required Therefore choosing of the type of lower than this saturation pressure one must try to. sampling is a function of the fluid the well equipment attain well conditions that enable the sample collected. the production equipment at the surface and the type and the reservoir fluids to bear as many common. of study to be performed characteristics as possible This can be achieved by. There are two types of sampling procedures reducing the production rate of the well. bottomhole sampling single phase and surface It is important to suitably select the well where the. sampling Surface fluids are generally sampled at the sampling will be performed The well should be located. separator When the conditions of the wellhead are in an area of the reservoir where the reduction in. such that the fluid is in a single phase samples can be pressure is minimal and it should have a high. taken at the wellhead When large quantities of fluid productivity so as to maintain a sufficient pressure in. are necessary it is also possible to work with stock the surrounding region as well as to avoid the transition. tank oil The stock tank oil properties are used to study to two phase conditions Furthermore in order to. the risk of deposits during transport to perform minimize contamination of the sample the well should. measurements in porous media as well as for studies not produce water and should have been in production. concerning the treatment of emulsions the for a sufficiently long time in oder to avoid. dehydration and the desalting contamination for example by the drilling fluid. Finally the reservoir water is also sampled The Finally the well should be connected to a separator. knowledge of its properties is necessary for the located as close to the wellhead as possible thus. calibration of well logging the definition of the avoiding disturbances and excessively long stabilization. production and process methods the verification of its times The choice of the well is made by studying the. compatibility with water to be used in a possible water past history of its production in order to ascertain that. injection and for corrosion studies Even though it is in particular the GOR of the fluid produced at the. often ignored a water study is important it should not surface remains constant over time thus guaranteeing a. be forgotten that wells produce water after a certain single phase production Before sampling the rate of. period At the end of the lifetime of a field the the well should be stabilized for a sufficient amount of. quantity of water produced may even be larger than time to allow the GOR at the surface to become stable. that of the oil This stabilization time can vary significantly from a. Since the aim of the sampling procedure is to few hours to several days The value of the GOR at the. obtain a sample that must be representative of the separator should remain constant between two. original reservoir fluid it is indispensable to perform reductions of the rate in order to be sure that the. the sampling before the reservoir pressure reaches the producing horizon is indeed in a single phase. saturation pressure In the case of a volatile oil or a gas In the case of sampling in a gas well the rate. condensate below this threshold it is almost should be high enough to avoid an accumulation of. impossible to obtain either at the surface or at the liquid at the bottom of the tubing. bottomhole a fluid representative of the original Bottomhole sampling is performed by means of. mixture in the reservoir suitable instruments samplers which are lowered. into the well and vary according to the type of well. Bottomhole sampling This type of sampling can be performed. This type of sampling is performed using special While drilling in this case the samplers are fixed. equipment lowered into the well In general the together with other equipment to the end of the. sampling is done during the production tests before drilling string The most modern equipment makes. production has begun Bottomhole sampling is it possible to obtain good quality samples with this. preferred in the following cases undersaturated oils type of procedure open hole sampling This. fluids close to the critical point and rich gas method of sampling is becoming more and more. 492 ENCYCLOPAEDIA OF HYDROCARBONS,PETROLEUM FLUID PROPERTIES. common especially in offshore fields because it and pressure conditions during the sample s ascent to. saves time considerably with a corresponding the surface After the transfer the sample generally. reduction of costs Furthermore this equipment expands to a pressure lower than that of saturation in. permits an accurate control of the sampling In such a way as to create a gas cap which allows the. particular using infrared measurements it is sample to be transported safely When the samples. possible to verify that the sample is not too arrive at the laboratory they are brought back to. contaminated by water or drilling mud Equipment sampling conditions. capable of measuring the viscosity and the density Bottomhole sampling is the best method to obtain. of the fluid as well as taking samples at different samples provided that the fluid is in a single phase. depths in order to measure the homogeneity of the during sampling In particular this is the only. composition is presently being developed technique that allows samples to be obtained without. In wells that are completed with production tubing anti hydrate additive contamination Samples of this. In this case the sampler is most commonly type are also the most recommended for studies of. lowered at the bottomhole by a cable asphaltene containing fluids since redissolving these. These samplers collect a certain volume of liquid components remains to this day very difficult and. generally between 500 and 1 000 cm3 depending on much debated On the other hand this method does. the type before being brought back to the surface The not allow extensive studies to be performed in. samples are then transferred to suitable containers particular on the liquid fraction of gas condensates. which allow them to be transported in complete safety due to the small volumes obtainable generally less. This fluid transfer is performed under isobaric than one litre In the case of saturated oils and poor. conditions Finally if the saturation pressure has been condensates surface sampling methods are. reached due to the pressure and temperature changes recommended. during the ascent of the sampler to the surface the. sample must be restored to the reservoir temperature Surface sampling. before transfer There is also a new type of sampler At the surface samples can either be taken directly. SPMC Single Phase Multisample Chamber which at the wellhead if still in a single phase or more. keeps the sample above its saturation pressure in spite commonly at the separator This method can be used for. of the temperature reduction due to the ascent of the oils or gas condensates in particular when the fluids. sampler The pressure is maintained Fig 9 by means have reached or are close to saturation pressure or. of a nitrogen chamber or a system of two pistons when the well produces a large quantity of water In. allowing in an initial stage the sample to be contrast the use of this technique is not recommended. compressed from the initial reservoir conditions point when problems related to the crystallization of paraffins. A to a pressure higher than the sampling pressure or precipitation of asphaltenes are suspected to occur. point B and subsequently to limit the drop in Sampling at the separator consists of taking a gas and a. pressure due to the ascent point D A sampler liquid sample The two samples must be taken at the. capable of simultaneously avoiding the drop in same time and the sampling time must be greater than. pressure and temperature has been put forward this the residence time in the separator If there is more than. sampler thus eliminates any change in the temperature one separator preferably the sampling should be. performed at the first separation stage in order to avoid. error accumulation The two fluids the gas and the, liquid are then recombined in the laboratory in such a. way as to synthesize a fluid representative of the. reservoir fluid When the saturation pressure of the. reservoir fluid is known with precision it is preferable. to perform the recombination on the basis of the bubble. initial reservoir conditions A,point pressure rather than on the GOR Danesh 2003. The main difficulty with this type of sampling which. assumes the use of a separator lies principally in the. measure of the respective rates of the gas and the liquid. Furthermore as the gas is at the dew point and the. liquid at the bubble point the slightest variation of the. temperature and pressure conditions during the, temperature sampling process can induce the transition to a two.
Fig 9 Conservation of pressure phase state In this case there is a risk that the fluids are. in samplers no longer representative However the advantage of this. VOLUME I EXPLORATION PRODUCTION AND TRANSPORT 493,OIL FIELD CHARACTERISTICS AND RELEVANT STUDIES. type of sampling is that large quantities of fluid can be vaporization The constant mass study best represents. taken Such large quantities are necessary for detailed the behaviour of the fluid in the proximity of the well. studies this is especially true in the case of gas Further from the well where the pressure falls below. condensates that contain small quantities of heavy the saturation point a gas phase appears which is. components Nevertheless in order to mix the gas and produced preferentially to the less mobile liquid phase. the liquid in the proportions to generate a truly The study of differential liberation aims to simulate. representative fluid it is essential that the reservoir fluid the behaviour of the oil left in the reservoir which. is in a single phase at the depth of perforation interval progressively liberates the gas that was initially. open to production that the gas can lift the liquid in the dissolved within it This gas does not remain in contact. tubing if the pressure in the tubing is lower than the with the oil and thus is no longer in equilibrium with. saturation pressure and that the gas and the liquid rate it As illustrated later the measurements performed are. at the separator can be measured with maximum slightly different depending on the type of fluid. precision examined, The following measurements must be performed In order to be useful these tests must be performed. during the sampling procedure the rate of the gas and on fluid samples representative of the reservoir fluids. the liquid at the separator the sampling pressure and Bottomhole samples or samples obtained by. temperature the density of the gas at the separator recombination of separator fluids can be used In. and the density of the oil at standard conditions either case before beginning the analysis it is. There are several sampling methods for the gas and essential to be certain that the sample is of good. the liquid at the separator The gas can be transferred quality In the case of samples taken at the separator it. to a container under vacuum or it may be transferred is preferable to ascertain that the saturation pressure of. by displacement of a liquid e g the container may be the oil does indeed correspond to the separator. filled with water or by displacement of a gas In the pressure before performing the recombination The gas. last two cases it is advisable to transfer several obtained at the separator must be heated to a higher. volumes of gas in order to avoid the risk of temperature than the separator temperature in order to. contamination avoid any condensation Furthermore the opening. The liquid is transferred by displacement of a pressure of the bottle containing the gas must be equal. liquid taking care that the liquid chosen is not to the closing pressure at the well site The analysis of. miscible nor reacts with the liquid being sampled by the separator gas is an important parameter when. equilibrium displacement of the separator gas in this verifying that the sample is representative Williams. case the bottle should be pre filled with separator 1994 The recombination of the gas and the oil must. gas or by displacement of air be performed in the proportions of their respective. rates measured at the separator so as to reproduce the. saturation pressure of the reservoir fluids When the. 4 2 6 PVT analyses saturation pressure is known with certitude this. laboratory procedures parameter should be given priority with respect to the. and parameters measured GOR measured at the separator. Reservoir fluids contain several hundred components Oils. therefore it is impossible to identify all of these Oil is a fluid for which the reservoir temperature is. components in order to calculate the behaviour of a lower than the critical temperature of the mixture The. fluid using a thermodynamic model As a result the decompression of the fluid thus leads to the. method used is to study in the laboratory the appearance of gas bubbles starting from the moment. thermodynamic behaviour of representative samples of when the pressure is lowered below the saturation. the reservoir fluids and to use the results obtained on level also known as the bubble point pressure Pb. these samples to calibrate the thermodynamic model The measurements performed during the testing of. This model can then be employed to forecast the oil samples include constant mass study differential. behaviour of the fluid throughout the productive life of study separation tests and viscosity measurements. the reservoir When a particular development scheme is planned. The experimental studies performed on the e g gas injection further tests are required. reservoir fluid allow the determination of their, composition their volumetric behaviour as well as Constant mass study. their physical properties such as density and viscosity Constant mass studies are performed by gradually. The volumetric tests include a constant mass study decompressing the fluid under isothermal conditions. and a differential study differential liberation or until the appearance of the gas phase Using this. 494 ENCYCLOPAEDIA OF HYDROCARBONS,PETROLEUM FLUID PROPERTIES. can also be used to determine the density of the fluid. at a given pressure and subsequently knowing the, relationship between the pressure and the volume the.
density can be calculated as a function of pressure. Differential study, bubble pressure Differential liberation or vaporization reproduces. volume the behaviour of the fraction of initial reservoir liquid. Fig 10 Graph of the pressure as a function,that is not produced at the surface during the. of the volume during a constant mass decompression of the reservoir In fact given that the. and temperature expansion gas is more mobile than the oil it is preferentially. produced when the fluid is at a lower pressure than the. bubble point To simulate the true behaviour of the. method it is possible to measure the saturation pressure fluid it would be necessary to remove the gas as it is. of the oil bubble point the relative volume i e the produced Since this is not possible one proceeds by. ratio between the volume of the fluid whether single successive expansions and subsequent removals of the. phase or two phase and the volume of the oil at the gas In general about ten stages between the reservoir. bubble point and in the case of undersaturated oils and atmospheric pressure are employed during the. when the pressure is higher than the bubble point the analysis As in the constant mass study the fluid is. isothermal compressibility coefficient This study aims introduced into the analysis cell at the reservoir. to reproduce the behaviour of the fluid in areas where temperature and when the temperature has stabilized. there is no flow but where the fluid pressure falls below the pressure is reduced in steps The gas phase appears. the saturation pressure close to the well when the saturation pressure has been reached which. A sample of the recombined fluid is introduced is then completely removed from the system at. into an analysis cell at constant pressure Having constant pressure The volume of the removed gas is. stabilized the temperature at reservoir temperature the measured by means of a gasometer These operations. pressure is reduced in successive steps After are then repeated until a pressure close to atmospheric. stabilization of the pressure the volume of the sample pressure is reached Having arrived at the last stage. is measured at each step In this way the variation of the volume of the residual oil is first measured at the. the volume with pressure at constant temperature is temperature of the experiment and at atmospheric. determined and the relative volume is calculated The pressure then at standard conditions SC 288 15 K. results of such an experiment are shown in Fig 10 and 1 013 bar. Using the data obtained in this way the Fig 11 illustrates the evolution of the phase. compressibility coefficient of the fluid as a function of envelopes of the different saturated oils in the cell. pressure is determined during the course of the experiment This figure. highlights how the oils obtained after removal of the. Co 1 12 gas are successively less volatile due to the reduction. V DP T of the bubble point at the expansion temperature The. When the gas phase appears a sudden change in saturation pressure of the initial fluid at reservoir. the slope of the curve is observed from which the temperature TR is represented by point A. bubble point can be accurately determined This study Subsequently the saturation pressures of the liquids in. the successive stages are represented by points B E as. the pressure is progressively reduced At each stage it. A is necessary to measure the volume of the gas removed. at the temperature and pressure conditions of the cell. B as well as at standard conditions the density of the gas. and the volume of oil at cell conditions,The properties calculated at the end of the. D experiment are as follows, Properties of the liberated gas the total volume of. the gas produced the volumetric factor Bg the, TR compressibility factor Z and the composition of the.
temperature,gas from which the density is calculated the. Fig 11 Phase envelope of liquids volumetric and compressibility factors are defined. in equilibrium during a differential study in the following way. VOLUME I EXPLORATION PRODUCTION AND TRANSPORT 495,OIL FIELD CHARACTERISTICS AND RELEVANT STUDIES. at different pressure values ranging from the reservoir. Bo 1111 expressed in m3 m3 pressure to atmospheric pressure using either a ball. Vg SC viscosimeter by measurement of the drop time of a. steel ball in a calibrated tube filled with the reservoir. fluid or a capillary viscosimeter e g for a gas,288 15 PVg P T. Z 111112323 condensate,Gas condensates, Properties of the residual liquids at each pressure As mentioned above the reservoir temperature of a. value the relative volumes VR the volumetric gas condensate falls in the range between the critical. factor Bo the density r and the dissolved gas RS temperature and the cricondentherm Upon expansion. These quantities are defined as follows these fluids which are initially gaseous form a liquid. Vo P T below the saturation pressure the quantity of liquid. VR 11133 deposited reaches a maximum value before being. Vo Pb T revaporized Laboratory tests aim to describe such. where Pb is the bubble point pressure of the oil at behaviour on the basis of volumetric and. temperature T and Vo is the volume of the liquid compositional measurements. Constant mass studies, Bo 1111 expressed in m3 m3 The goal of this experiment is to determine the.
Vo res SC dew point the compressibility coefficient above the. dew point and the volumes of liquid deposited below. where the volume of the residual oil Vo res the dew point To perform this experiment the. is the volume of the oil left at the last stage of recombined fluid or the separator fluids liquid and. decompression under standard conditions gas are introduced into the PVT cell which is then. brought to reservoir temperature The initial pressure. Vg diss P T is generally fixed to that of the reservoir. Vo res SC Subsequently the fluid is gradually decompressed. thus increasing its volume until the dew point, where Vg diss P T is the volume of dissolved gas at pressure is reached In most cases the determination. the pressure considered This volume of gas is of the dew point is made visually either by eye or by. equivalent to the sum of the volumes of gas means of a camera The decompression is then. liberated in the successive stages and therefore is continued in steps until revaporization begins At. calculated after the last stage each step the pressure and volume of the liquid. Furthermore an analysis of the gas is performed at deposited are measured The parameters that can be. each stage and an analysis of the residual liquid is determined by means of this procedure are a the. performed at the last stage upper dew point b the compressibility factor of the. fluid as a function of pressure c the relative volume. Separation tests VR V P T V PD T where PD is the dew point. This experiment consists of expanding the fluid pressure d the density of the fluid as a function of. from its saturation pressure to the separator pressure pressure e the percentage of condensate deposited. so as to optimize the oil production Depending on the as a function of the pressure calculated using the. fluid pressure at the wellhead case one or several sample volume at the dew point pressure as a. stages of separation can be foreseen reference and f the maximum quantity of the. During this test the volume and composition of the liquid deposited. gas at each stage as well as the volume of the oil are. measured These two values are then converted to the Constant volume studies. volume of oil under standard conditions Furthermore This type of experiment is of fundamental. the density of the oil and the composition of the liquid importance as it aims to reproduce the evolution of. are measured at standard conditions the reservoir fluid s composition during the course. of the exploitation thus allowing the estimation of. Viscosity of the reservoir fluid the quality and quantity of the condensates which. The viscosities of the fluid are necessary to define will remain in the reservoir To perform this. the flow of the fluid in the rock These viscosities are analysis the fluid is recombined in the cell or is. measured at the reservoir temperature conditions and directly introduced in the case of bottomhole. 496 ENCYCLOPAEDIA OF HYDROCARBONS,PETROLEUM FLUID PROPERTIES. 14 The composition of the gas produced,liquid deposit 100 V Vsat. constant volume The principal difficulty of this study lies in the. 12 constant mass, recovery of the small volumes of condensates formed. during the expansion of the gas The quantity of gas. 8 removed must be sufficient to allow the measurement. 6 of the volume of the condensate if this is not the case. 4 the material balance between the quantity of material. 2 introduced and removed will not give satisfactory. results Danesh 2003 cites the work of Drohm et al, 0 10 20 30 40 50 60 1988 whose results show that of 80 studies of the gas.
pressure MPa condensates reported 71 presented unsatisfactory. Fig 12 Graph of the quantity of liquid material balances The development of injection valves. deposited as a function of the pressure under pressure for the direct gas chromatographic. in the constant mass and volume experiments analysis of the fluid should resolve this problem. Composition of reservoir fluids, sampling and the cell is subsequently brought to In order to determine the composition of a. the pressure and temperature conditions of the reservoir fluid it is generally necessary to expand it to. reservoir The quantity of the fluid introduced must atmospheric pressure as the techniques for gas. be measured with maximum precision in order to chromatographic analysis available today can only be. perform a material balance To this end it is applied under such conditions The gas and liquid. important to know the density and composition of phases are then collected and analysed by means of. the fluid introduced The volume of the recombined gas chromatography see also Chapter 1 1 The. sample at the initial pressure and temperature analysis of the two phases obtained in this way are. conditions is chosen as the reference volume V0 then recombined in order to determine the. The pressure is then gradually reduced in 10 to 15 composition of the original mixture It is important to. stages At each stage a part of the gas phase is avoid the contamination of the sample with air at the. removed from the cell at constant pressure in order time of sampling as this can cause errors in the. to maintain the system at the reference volume V0 measurement of nitrogen concentration In addition to. The information collected at each step includes the the light components up to C4 the heavy components. pressure the volume of the liquid deposited the in the gas between C5 and C10 and especially in the. volume of gas extracted at both the pressure condensate should also be quantified because the dew. condition of the experiment and atmospheric pressure value is strongly affected by their. pressures and the composition of the gas In this concentration. way it is possible to calculate the cumulative The molar mass or molecular weight Mg of the. production of gas in terms of the cumulative gas can be calculated in the following way. number of moles of gas produced over the number, of moles of reservoir fluid at the initial pressure The i. parameters calculated at the end of the experiment where yi and Mi represent the molar fraction and molar. are the following mass of the component i, The volume of condensate deposited as a The density of the gas can be measured by. function of pressure The condensate curve will weighing a known volume of gas or it can be. be lower than that obtained from the constant calculated from the results of the gas chromatographic. mass study Fig 12 since the quantity of analysis by means of the expression. material in the cell diminishes at each stage This Patm Mg. curve indicates the fraction of the condensate rg 11133. that will remain in the reservoir On the other RT0. hand the difference between the two curves where rg is the density of the gas at atmospheric. represents the condensates that will be produced pressure Patm and at the standard temperature T0 and R. at the surface is the universal gas constant equal to 0 0083144 if. The compressibility factor Z of the gas produced Patm is expressed in MPa T0 in K and r in kg m3. as already defined As far as the liquid phase is concerned it can be. The density of the gas relative to air This can be analysed by distillation or by means of gas. measured by weighing a known volume of gas or chromatography on a capillary column In either case. calculated from its composition an unidentified residual heavy fraction remains which. VOLUME I EXPLORATION PRODUCTION AND TRANSPORT 497,OIL FIELD CHARACTERISTICS AND RELEVANT STUDIES. can be analysed by liquid phase chromatography RT a T. Danesh 2003 P 11 11111113,V b V c V b 2c, The composition of the reservoir fluid is obtained.
from the composition of the gas and the liquid on the which contain the parameters a b and c For pure. basis of the value of the GOR The principal problem components these parameters are calculated from the. with this method lies in the necessity to expand the critical properties or are modified in such a manner. fluid to atmospheric conditions before analysis In that the equation simulates in the best way the. fact the expansion could cause a loss of heavy behaviour of the fluid In the case of a mixture. components which are deposited on the walls of the specific rules mixing rules are used to calculate these. cell and a loss of part of the oil s volatile components parameters starting from those of the pure components. As a result the composition of the C5 C10 fractions that make up the mixture The classical mixing rules. could be less accurate than that of the other fractions used by the Peng Robinson and Soave Redlich Kwong. in the fluid To avoid this problem methods of equations of state are the following. a aij zi zj, injection under pressure are presently being developed. These methods will allow the fluid especially gas i j. condensates to be directly introduced into the gas. chromatograph without the preliminary expansion i, thus avoiding the loss of intermediate components 2323. aij ai aj 1 kij with kij kji,4 2 7 Equations of state. where zi and zj represent the molar fractions of the. An accurate knowledge of the thermodynamic components i and j in the mixture In these. behaviour of the fluid is necessary in order to calculate expressions ai bi and ci represent the parameters. the reserves in place to define the production design of the pure components The calculation of aij. and to determine the size of the surface facilities that requires the use of a binary interaction parameter. will guarantee an optimal recovery of liquid phase kij which is usually determined by minimizing the. The laboratory tests provide useful information on the difference between the calculated and experimental. thermodynamic behaviour of reservoir fluids but data on the binary mixtures At present it is also. unfortunately these experiments are long and possible to use pseudo experimental data. expensive and cannot be performed in all of the calculated by means of molecular modelling. conditions foreseen during the productive life of the especially when it is necessary to characterize the. reservoir Therefore the experimental studies are often heavy components of the mixtures for which. used to calibrate the thermodynamic models integrated minimal data are available or the toxic components. into the reservoir transport and process simulators Delhommelle et al 1999 Moreover there are. The models are either based on simple laws which numerous publications in the literature where the. allow the equilibrium constants and properties of the values of kij for the Peng Robinson and Soave. phases to be calculated or on the use of equations of Redlich Kwong equations can be found Vidal. state A detailed treatment of the application of 2003 In the case of a mixture containing large. equations of state to petroleum fluids has already been quantities of nitrogen or carbon dioxide it is. given see Chapter 1 1 To follow only certain necessary to use specific correlations for the. specific aspects that are of particular interest for binary interaction parameters The works of. reservoir fluids are recalled Moysan et al 1986 and Nishiumi et al 1988. report such specific correlations for the cases of. Calculation of the equation of state parameters carbon dioxide and nitrogen respectively. of mixtures, Equations of state used to describe the behaviour Mixtures with acidic gases water and alcohols. of reservoir fluids contain various parameters that When considering systems containing water. must be determined or estimated For example two of gaseous acids H2S or CO2 or alcohols which usually. the most commonly used equations of state in the oil are added in order to avoid the formation of hydrates. industry are the equation of Peng Robinson and that of in addition to hydrocarbon the classical mixing rules. Soave Redlich Kwong see also Chapter 1 1 do not provide an accurate description of the. behaviour of the mixture In such cases it is advisable. RT a to use rules derived using the excess free energy. P 11 11111,V b V 2bV b2,2 Huron and Vidal 1979,498 ENCYCLOPAEDIA OF HYDROCARBONS.
PETROLEUM FLUID PROPERTIES, As far as equilibria with water are concerned at temperature and pressure the acentric factor and the. times it is necessary to take into account the salinity of boiling temperature Ahmed 1989 described various. the water which is not considered in the formulation methods of grouping together and characterizing the. of the mixing rules outlined above In this case for pseudocomponents of the heavy fraction. high pressures it is preferable to use another method The physico chemical properties TC PC w. Soreide and Whitson 1992 which consists of attributed to each of these pseudocomponents are. modifying the classical mixing rules associated with generally calculated from the properties of the. the Peng Robinson equation This method uses constituent pure components The rule most commonly. different interaction parameters for the hydrocarbon used is that of Kay 1936 which is based on the linear. and liquid phases weighting of the given property as a function of the. In the domains of gas transport and treatment component s molar fraction in the pseudocomponent. when the pressure and temperature conditions are such With regard to the heavy fraction the literature contains. that there is risk of hydrate formation during transport numerous studies on its characterization and in. additives that inhibit such processes are usually particular on the influence of the method used on the. employed Classical equations of state cannot describe predictions of the reservoir fluid s properties Hamoodi. the phase equilibria in which these components take et al 1996 It has been demonstrated that even in the. part Therefore new equations derived using statistical case of a fluid containing only 0 01 in moles of the. mechanics are presently being developed C6 fraction the adjustment of the properties of the. Kontogeorgis et al 1999 heavy fraction can significantly modify the phase. envelope of the fluid Finally Thomassen et al 1987. Grouping of components indicated that an error of between 5 and 10 in the. Applying equations of state to mixtures assumes molar mass of the heavy fraction can cause an error of. knowledge of the mixture s composition components 700 psi on the predictions of the dew point pressure of a. and concentration as well as of the chemical and gas condensate. physical properties of each component the critical The heavy fraction can be represented by pure. temperature TC the critical pressure PC and the components mixed in such a way as to reproduce the. acentric factor w for the Peng Robinson and Soave molecular mass and the division by chemical family. Redlich Kwong equations see Chapter 1 1 resulting from the compositional analysis or by a. As already mentioned reservoir fluids gases or mixture of several pseudocomponents The properties. liquids are commonly analysed by means of gas phase of the pseudocomponents can be quantified to a first. chromatography and the analytical methods commonly approximation with the help of correlations which. used provide very detailed information on their allow them to be calculated from the values of two of. composition Unfortunately it is not possible to take the following properties the boiling temperature the. into account all components either individually or in density and the molar mass For example it is possible. groups during the modelling of the fluid behaviour to cite the correlation proposed by Twu 1984 which. using basin or reservoir simulators because the allows TC PC VC and M to be expressed as a function. calculation times are proportional to the number of of g0 the relative density and the boiling temperature. components and these times rapidly become Tb This correlation is expressed using the following. incompatible with the calculation capacity of present four parameters. day computers For this reason the fluids are generally. represented by a number of pseudocomponents 3 to TC0 Tb 0 533272 0 191017 10 3Tb 0 779681 10 7Tb2. 10 each one grouping together an ensemble of,0 959468 1028 1. components There are various methods of grouping the 0 284376 10 10Tb3 111113. components the simplest consists of gathering all Tb13. components eluted between two n paraffins in the gas VC0 1 0 419869 0 505839a 1 56436a3. chromatography analysis Furthermore all components. with the same number of carbon atoms can be grouped 9481 7 a14 8. together It is also possible to differentiate on the basis PC0 3 83354 1 19629a0 5 34 8888a. of chemical families components with a given number. of carbon atoms or within a given range of boiling 36 1952a2 104 193a4 2. temperatures This further subdivision results in a larger. S 0 0 843593 0 128624a 3 36159a3 13749 5a12,number of pseudocomponents. Finally Montel and Gouel 1984 propose grouping, together components in a 3 or 4 dimensional parameter with a 1 Tb TC0 which allows the determination of. space represented by for example the critical The critical volume VC in ft3 lb mol. VOLUME I EXPLORATION PRODUCTION AND TRANSPORT 499,OIL FIELD CHARACTERISTICS AND RELEVANT STUDIES.
VC VC0 11133,2 and with,fm DSm x 0 0175691 1111,0 46659 3 01721. fv DSv 11133 0 182421 11133 DSv DSm exp 5 S 0 g0 1. Tb0 5 Tb0 5,x 0 0123420 1111,The critical temperature Tc in R. TC TC0 11133, The characteristic values of the heavy fraction are. then optimized in such a way as to reduce to a,minimum the differences between the data measured. with at the reservoir temperature and the calculated data As. fT DST 11133,0 0398285 111332, DST an example Fig 13 illustrates the phase envelope of.
the oil calculated with the initialization values used as. parameters of the pseudocomponent of the heavy,DST exp 5 S 0 g0 1. fraction and the phase envelope obtained after, The critical pressure Pc in psia calibration of these parameters This example. TC VC0 1 2fp,PC PC0 120 12 121233,TC VC 1 2fp, 2 demonstrates the necessity of laboratory experiments. Representation of the heavy fraction,with The heavy fraction of the fluid which is not. fp DSp 2 53262 11133,0 00127885T,completely analysed is represented by one or more.
pseudocomponents usually two or three the physical. b properties of which need to be determined The use of. 11 4277 11133,0 00230535T DS,three pseudocomponents has been proposed in order. represent respectively the paraffins the napthenes. DSp exp 0 5 S 0 g0 1 and the aromatics present in the heavy fraction. Pedersen et al 1992 on the other hand propose a, The molar mass M method of representing the heavy fraction of gas. 1 2fm 2 condensates by means of a distribution function based. 1nM 1nM 0 132, on the number of carbon atoms In fact this function. allows one to determine a concentration per number of. with ln M 0 q q being defined by carbon atoms the final number of carbon atoms being. Tb exp 5 71419 2 71579q 0 286590q2, fixed with the help of the molar mass of the heavy. fraction Finally Danesh 2003 describes the,39 8544 1111.
possibility of using the mathematical distribution. functions proposed by Cotterman 1985,4 2 8 Empirical PVT correlations. after tuning, before tuning As already mentioned in order to correctly develop. a hydrocarbon field it is necessary to know the,properties of the fluid under a wide range of. pressure and temperature conditions The properties. can be calculated by the equations of state or,estimated with the help of empirical correlations. The latter are easier to use than equations of state. but they are generally only applied to the type of. temperature fluids on which they were developed and cannot be. Fig 13 Variation of a phase envelope before extrapolated The main properties that can be. and after the calibration of the parameters calculated using these correlations are the saturation. of the heavy fraction pressure the GOR the formation volume factors. 500 ENCYCLOPAEDIA OF HYDROCARBONS,PETROLEUM FLUID PROPERTIES.
the compressibility the density and the viscosity volume of gas dissolved SC. The correlations available in the literature have been GOR1111111111. volume of the storage oil SC,evaluated by numerous authors however it is still. difficult to advise the use of one more than another Also in this case the correlations established by. Therefore in the following only the most frequently Standing will be examined. cited or the most recent correlations will be given as Standing s correlation This correlation is. examples indicating where possible the nature of applicable to fluids with a GOR between 3 6 and 254. the fluids used in their derivation Ahmed 1989 sm3 m3 i e between 20 and 1 425 sft3 stb. Danesh 2003,McCain 1991 and more recently Valko and GOR gg yg. McCain 2003 presented a summary of the, correlations that can be used to calculate the properties with. of reservoir fluids,yg 1 225 0 00164T 133,Properties of oils. where the GOR is expressed in sm3 m3 and the pressure. Bubble point pressure P in kPa gg and go are the density of the gas relative to. Standing s correlation This correlation was air and the density of the oil relative to water. established using data obtained on certain fluids, originating in California having bubble points Formation volume factor.
pressures between 900 and 48 300 kPa i e between The formation volume factor Bo is used to establish. 130 and 7 000 psia It was first presented in the form the relationship between the volume of the oil under. of a graph without analytical formulation Standing reservoir conditions and that under standard. 1947 and later in the form of a computer usable conditions The correlations that allow the calculation. correlation Standing 1977 It is presented below with of Bob Bo at the saturation pressure require the GOR. parameters compatible with SI units the density of the gas and the storage oil and the. temperature to be known As an example Standing s,Pb 519 7 10 yg correlation is discussed. g Standing s correlation It is expressed by,Bob 0 972 0 000147 F1 175. yg 1 225 0 00164T 13 with, where the bubble point pressure Pb is expressed in F 5 615 GOR 2 25T 575. kPa the GOR in m3 m3 and the temperature T in K gg. and go are the density of the gas relative to air and the where Bo and the GOR are expressed in m3 m3 and gg. density of the oil relative to water and go are the density of the gas relative to air and the. From the many other correlations which have been density of the oil relative to water. developed that of Elsharkawy 2003 can be cited as, an example The input data of this correlation based Compressibility factor. on data obtained from fluids coming from the North The isothermal compressibility factor of the. Sea are the molecular weight and the density of the undersaturated oil Co at pressures higher than the. C7 fraction as well as a detailed composition of the bubble point pressure is defined in the following way. fluid up to C6, It is recalled that for a saturated oil the GOR where V P T is the slope of the pressure volume.
represents the quantity of gas dissolved in a unit curve This factor is generally determined with the. volume of the storage oil where the volumes of gas help of the experimentally defined pressure volume. and oil are those under standard conditions that is curves However it is also possible to evaluate it. 288 15 K and 1 013 bar The same correlations can be using various correlations among which that of. used to calculate the quantity of gas dissolved RS see Vasquez and Beggs 1980 which requires. above at all pressures below the bubble point since at knowledge of the density of the gas the API gravity. all of these pressures the oil is saturated in the case of of the oil the GOR the temperature and the pressure. a differential study can be cited,VOLUME I EXPLORATION PRODUCTION AND TRANSPORT 501.

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