石油英语2

石油工程专业英语 编者：范军 目录 Unit 1 petrophysics …..…..………………….…… 2 NEW WORDS:…..…..………………….………………..……………5 PHRASES: …..………………….………………………….……......5 Chapter 4: Properties of Reservoir Rocks……………..6 new words: …..………………….………………………10 phrases: …..………………….………………………...11 Unit 2 Production of Oil and Gas………………..13 New words …..………………….………………………15 phrases: …..………………….………………………...15 Chaper 2: Classification of Oil and Gas Separators………16 newwords: …..………………….………………………17 phrases:…..………………….………………………...18 Chapter 3: Sucker Rod Pumping …………………18 Surface and Subsurface Equipment……………………………….....20 New words …..………………….………………………21 phrases: ……………...………………………………....22 Chapter 4 : The Pump Dynagraph…………………………..22 Newwords……………………..…………………………………23 Phrases………………………………………………………23 Chapter 5: Gas Lift ………………………………………24 Newwords……………………..………………………………….26 Phrases……………………………………………………….27Chapter 6 : Hydraulic Fracturing…………………………..28 Newwords……………………..………………………………….31 Phrases………………………………………………………..31 Chapter 7: Matrix Acidizing of Sandstones….........................32 Newwords……………………..………………………………….35 Phrases……………………………………………………….35Chapter 8 : Water flooding………………………………..….37 Newwords……………………..……………………………….….38 Phrases……………………………………………………..…38 Chapter 9: Foam Flooding………..…………………………….39 Newwords……………………..………………………………….40 Unit 1 petrophysics Chapter 3: Physical Properties of Reservoir Fluids The fluids of a petroleum reservoir are generally gas, oil, and water in varying proportions. Each phase can differ widely in composition and properties. Gas and oil, either as separate fluids or in mixtures, change their state or phase as reservoir pressure changes. For an oil reservoir, as pressure decreases with production, a value is reached at which a portion of the liquid vaporizes to produce a gas phase that then exists in equilibrium with liquid. The pressure at which the liquid first begins to vaporize is termed the bubble-point pressure. The resulting gas is referred to as gas that has come out of solution. It contains the more volatile (lower molecular weight) components of the oil. As pressure further decreases below the bubble point, more gas comes out of solution, and the volume of the liquid phase decrease, whereas the volume of the phase increases. A reservoir that contains oil at its bubble-point pressure is called a saturated oil reservoir. If the reservoir pressure is higher than the bubble-point pressure, then the reservoir is said to contain an undersaturated oil. If an oil zone has an associated gas cap in equilibrium with it, then the reservoir pressure is necessarily the bubble-point pressure at reservoir temperature. Some reservoirs have a gas cap and are in contact with an aquifer undersaturated with gas. These reservoirs contain oil at the bubble-point pressure at the gas-oil contact at discovery but are increasingly toward the aquifer. Fluid physical properties and correlations, as well as phase behavior, are discussed extensively in the fluid flow literature. To determine the fluid physical properties for a particular reservoir, samples of reservoir fluid are collected during exploration well tests for subsequent laboratory analysis. These samples are taken with bottom-hole tools or from the surface facilities that separate produced fluid into gas and liquid. The physical properties most commonly determined are the density, specific gravity, viscosity, and compressibility of the fluid, along with the pressure-volume-temperature relationships needed to convert surface fluid volumes to reservoir fluid volumes. The molecular composition of the oil and gas is also determined routinely. Following are some definitions relevant to the analysis of transient pressure data from well tests. The density ρ of a fluid is defined as its mass M per unit volume V : ρ = M / V M / L3 The fundamental SI metric unit for density is kg/m3, the unit g/cm3 is also permissible. In the traditional oilfield system of units, density is measured in pounds-mass per cubic foot (Ibm/ft3). A density of 1 g/cm3 = 1000 kg/m3 = 62.428 Ibm/ft3. A convenient way of expressing the physical property is through the relative density, commonly called the specific gravity, in which no units of measure need to be specified. For liquid, the relative densityγ is the ratio of the liquid’s densityρ to that of pure waterρw at a specified temperature and pressure: γ = ρ / ρw In the oilfield system of units, the relative density of oil is measured in terms of API (American Petroleum Institute) gravity. Degrees API, always reported at 60F, are related to the relative densityγ of oil by oAPI = 141.5 /γ – 131.5 Conversely, the relative density of oil at 60 oF is related to oAPI by γ = 141.5 / ( 131.5 + oAPI ) The relative densityγdecreases as oAPI increases. A relative density range of 1.0 - 0.61 corresponds to a range of 10 - 100 oAPI. In the SI metric system of unit, API gravity is not used as a measure of relative density. For gases, the relative density is defined as the ratio of the density of the gas at a given temperature and pressure to the density of air at the same temperature and pressure: γg = ρg /ρair = Mg / Mair Where M is the molecular weight of the gas. It has been found by experiment that 1 mole of any ideal gas under a pressure of 14.696 Psi (atmospheric pressure measured in pounds per square inch) and at a temperature of 60 oF will occupy a volume of 379.4 ft3. These conditions, that is, a temperature of 60 oF (15.56 oC) and a pressure of 14.696 Psi (1 atm), are referred to in the United States as standard conditions. Viscosity μ is the measure of fluid’s internal resistance to flow. It has a dimension of forcetime FT per unit area L; that is, FTL=MTL. The SI metric unit of viscosity is the pascal second (Pa﹒s) and the oilfield unit is the centipoise; 1 CP=0.001 Pa﹒s. Viscosity is affected by temperature and pressure and the fluid’s composition. Therefore, oil viscosity is best measured as a function of pressure and temperature in the laboratory as a part of a subsurface hydrocarbon analysis. As pressure decreases blow the bubble point, oil viscosity increases rapidly, since the more volatile components in the oil vaporize. Gas and water viscosities, on the other hand, when they are not known, as in the case of exploration well testing, usually can be estimated satisfactorily for reservoir conditions from published correlation. Fluid properties will change as the pressure and temperature in the reservoir and the composition of the fluid change during the producing life of a field. In general, the thermal capacity of a formation is so large that the reservoir temperature remains essentially unchanged during depletion unless a fluid injection project such as waterflooding or steam injection is initiated. However, as production progresses, the reservoir pressure always decreases below the initial pressure. The composition of the liquid phase in an oil reservoir remains constant at pressures above the bubble point (saturation pressure), but the composition continuously changes as a gas phase evolves at pressures blow the bubble point. Volume changes with pressure for a homogeneous liquid, such as water or oil above the bubble point, can be accounted for by liquid compressibility. Oil compressibility Co is the fractional changes in oil volume that results from a unit pressure change. Likewise, water compressibility C is the fractional change in water volume due to a unit pressure change. Units of compressibility are thus the reciprocals of those of pressure. For ideal gases, according to Boyle’s law, the specific volume of a gas at constant temperature varies inversely with the pressure, or, according to Charle’s law, the volume of a gas at constant pressure varies directly with the absolute temperature. The absolute temperature in oilfield units is expressed in degrees Rankine (R). The SI metric unit of absolute temperature is the Kilvin (K). These abolute temperature scales correspond to the practical scales of degree Celsius (C) and degree Fahrenheit (F) in the following manner: TK = TC + 273.15 TK = TR / 180 TC = ( TF – 32 ) / 1.8 TR = TF + 459.57 Natural gases at reservoir temperatures and pressures have compressibilities that are different from those defined by the ideal gas law. The parameter that measures the deviation of a gas from ideal behavior is called the gas deviation factor Z, and is defined by the non-ideal gas law PV=ZNRT, where P is pressure, V is the gas volume containing N moles of gas at absolute temperature T, and R is the universal gas constant. This dimensionless quantity varies usually between 0.70 and 1.20, a value of 1.00 representing ideal behavior. The gas deviation factor can be estimated from well-known correlation charts, using reservoir temperature, pressure, and the molecular composition of the gas. Flow rates are almost exclusively measured at surface conditions. These rates must then be converted to rates at reservoir conditions. When pressure is reduced, liquid volume is reduced because of partial vaporization or gas liberation Conversely, when pressure is increased, gas dissolves in the liquid phase, and as a result the oil “swells”. The parameters that quantify these phase volume changes are called the formation volume factors and the solution gas-oil ratio. The oil formation volume factor Bo is the ratio of the volume of oil at reservoir conditions to the corresponding volume at standard conditions. Since oil volume decreases as partial vaporization occurs, Bo>1. The oil production rate at reservoir conditions is then the product of the surface rate times the formation volume factor. This factor will increase slightly as pressure declines until reservoir pressure drop below the bubble point; Bo will then decrease with further decreases in pressure. All the rates appearing in this monograph are rates at reservoir conditions. The gas formation volume factor Bg is the volume measured at reservoir conditions that corresponds to a unit volume of gas at standard conditions. Thus, Bg<1. The solution gas-oil ratio Rs the volume of gas at surface conditions dissolved in that volume of reservoir oil which will shrink to a unit volume of oil surface conditions. This parameter thus represents the volume of gas at surface conditions that vaporizes from a volume of oil at reservoir conditions. The solution gas-oil ratio remains nearly constant until reservoir pressure declines to the bubble point. The Rs parameter then decreases with further decreases in pressure. Since the volume factors and the solution gas-oil ratio are determined from laboratory measurements on samples of reservoir fluid at reservoir temperature and various pressures, these parameters are effective substitutes for detailed phase equilibrium data in most production calculations. However, these parameters are unknown at the time that exploration well tests are run, and hence they are estimated from correlation charts. The producing gas-oil ratio R is the ratio of the volumetric gas production rate to the volumetric oil production rate, both at surface conditions. Free gas is that gas which exists as a pas phase in the reservoir. The production rate of free gas at reservoir conditions is therefore the product of the difference (R - Rs) times the surface production rate of oil times the gas formation volume factor Bg. Finally, it should be noted that the effective compressibility of an oil-gas mixture below its bubble point pressure is large, since much of the volume decrease with pressure increase is associated with the change in phase of some the gas to a liquid. Although not complete, the preceding discussion highlights the physical properties of reservoir fluids that enter either into the parametric groups governing test behavior or into the conversion of surface flow rate available from well rests to the reservoir total flow rate. The reservoir total flow rate q is implied in all subsequent formulations in this monograph. NEW WORDS: reservoir [\T0L] vt. 使蒸发 equilibrium []0:EV0\S0BT0:P] n. 相称;平衡;均衡 volatile [\H5S:C>0S]　 a. 易挥发的 aquifer [\3EV:G:]　 n. 含水层 viscosity [H0K\E5K0C0] n. 粘度 compressibility [E:P]AT0EV>0L]　 ad. 同样地,照样地 fahrenheit [\G3T:QO>0C] n. 华氏温度计;华氏温标 deviation []D0:H0\<0M:Q] n. 越轨;偏向 dimensionless 　　　　　　 a. 无量纲的 PHRASES: petroleum reservoir 　　　　　　　　n. 油藏 reservoir pressure　 　　　　　　　 n. 储层压力 bubble-point pressure ｎ．泡点压力 come out of 　 vt. 由%产生 saturated oil reservoir n．饱和油藏 undersaturated oil reservoir 　n．不饱和油藏 gas cap 　 n. 气顶 in contact with prep. 与%接触 phase behavior n. 相特性 specific gravity n. 比重 transient pressure n. 瞬变压力 relative density n. 相对密度 in terms of adv. 根据,prep. 根据 molecular weight n. 分子量 resistance to flow n. 流动阻力 thermal capacity n. 热容量 gas deviation factor n. 天然气偏差系数 solution gas-oil ratio. n．溶解油气比 formation volume factor n. 体积系数 producing gas-oil ratio n．生产油气比 Chapter 4: Properties of Reservoir Rocks Introduction This chapter deals with the fundamental properties of reservoir rocks. The properties discussed are (1) porosity – a measure of the void space in a rock; (2) Permeability – a measure of the fluid transmissivity of a rock; and (3) fluid saturation – a measure of the gross void space occupied by a fluid. These properties constitute a set of fundamental parameters by which the rock may be described quantitatively. Typical core-analysis data are presented to illustrate the description of porous media by these fundamental properties. Porosity Porosity is defined as the ratio of the void space in a rock to the bulk volume (BV) of that rock, multiple by 100 to express in percent. Porosity may be classified according to the mode of origin as primary and secondary. An original porosity is developed during the deposition of the material, and later compaction and cementation reduce it to the primary porosity. Secondary porosity is that developed by some geologic process subsequent to deposition of the rock. Primary porosity is typified by the intergranular porosity of sandstones and intercrystalline and oolitic porosity of some limestones. Secondary porosity is typified by fracture development as found in some shales and limestones and the vugs or solution cavities commonly found in limestones. rocks having primary porosity are more uniform in their characteristics than rocks in which a large part of the porosity is induced. For direct quantitative measurement of porosity, reliance must be placed on formation samples obtained by coring. In dealing with reservoir rocks (usually consolidated sediments), it is necessary to define total porosity and effective porosity because cementing materials may seal off a part of the PV. Total porosity is the ratio of the total void space in the rock to the BV of the rock, while effective porosity is the ratio of the interconnected void space in the rock to the BV, each expressed in percent. From reservoir-engineering standpoint, effective porosity is the desired quantitative value because it represents the space that is occupied by mobile fluids. For intergranular materials, poorly to moderately well cemented, the total porosity is approximately equal to the effective porosity. For more highly cemented materials and for limestones, significant differences in total-porosity and effective-porosity values may occur. Laboratory Measurement of Porosity. Numerous methods have been developed for the determination of the porosity of consolidated rocks having intergranular porosity. Most of the methods developed have been designed for small samples, roughly the size of a walnut. Since the pores of intergranular material are quite small, determining the porosity of such a sample involves measuring the volume of literally thousands of pores. The porosity of larger portions the rock is represented statistically from the results obtained on numerous small samples. In the laboratory measurement of porosity, it is necessary to determine only two of the three basic parameters (BV, PV, and grain volume). In general, all methods of BV determination are applicable to determining both total and effective porosity. Permeability Introductory Theory. It is the purpose of this section to discuss the ability of the formation to conduct fluids. In the introduction to API Code 27, it is stated that permeability is a property of the porous medium and a measure of the medium’s capacity to transmit fluids. The measurement of permeability, then, is a measure of the fluid conductivity of the particular material. By analogy with electrical conductors, the permeability represents the reciprocal of the resistance that the porous medium offers to fluid flow. In 1856, Darcy investigated the flow of water through sand filters for water purification. His experimental apparatus is shown schematically in Fig.1. Darcy interpreted his observations to yield results essentially as given in following equation. q represents the volume rate of flow of water downward through the cylindrical sandpack of cross-sectional area A and length L. h1 and h2 are the heights above the standard datum of the water in manometers located at the input and output faces and represent the hydraulic head at points 1 and 2. K, a constant of proportionality, was found to be characteristic of sandpack. Darcy’s Investigations were confined to flow of water through sandpacks that were100% saturated with water. Later investigations found that Darcy,s law could be extended to fluids other than water and that the constant of proportionality K could be written as k/u, where u is the viscosity of the fluid and k is a proportionality constant for rock. The generalized form of Darcy,s law as presented in API Code 27 is presented in following. Us may further be defined as q/A where q is the volume rate of flow and A is the average cross-sectional area perpendicular to the lines of flow. The portion of the above equation in parentheses may be interpreted as the total pressure gradient minus the gradient caused by a head of fluid. Thus, if the system is in hydrostatic equilibrium, there is no flow and the quantity inside the parentheses will be zero. The equation may be rewritten as The quantity d(gρz-p)/ds may be considered to be the negative gradient of potential function Φ, where Φ = p - gρz The potential function is defined such that flow will be from higher to lower values. The dimensions of permeability may be established from an analysis of the above equation as k=L2. In the cgs system of units, the unit of permeability would be cm2, a large unit for common usage; therefore, the petroleum industry adopted the darcy as the standard unit of permeability, which is defined as follows. A porous medium has a permeability of one darcy when a single phase fluid of one centipoise viscosity that completely fills the voids of the medium, will flow through it under conditions of viscous flow at a rate of one cubic centimete