Chapter 1

Chapter1Introduction

IntroductionThe chemistry of hydrocarbon reservoir fluids is very complex. It is assumed that around 3000 organic compounds can exist in a single reservoir fluid. These compounds contain a variety of substance of diverse chemical nature that includes hydrocarbons and non-hydrocarbons. Hydrocarbons range from methane to substances that may contain more than 100 carbon atoms. Non hydrocarbons include substances such as N2, CO2, H2S, S, H2O, He and even traces if Hg, etc.1.1. Reservoir Fluid Composition The empirical formula CnH2n+hSaNbOc can be used to classify all the compounds present in crude oil. The largest portion of crude oil is composed of hydrocarbons with carbon number n, ranging from 1 to about 60 and h numbers ranging from +2 for low molecular weight paraffin hydrocarbons to -20 for high molecular weight organic compounds. Occasionally, sulphur, nitrogen and oxygen substitutions occur in high molecular weight organic compounds with a, b and c usually ranging from 1 to 3.Hydrocarbons are of two types: Aliphatic AromaticAliphatic hydrocarbons are further divided into alkanes (CnH2n+2), alkenes (CnH2n), alkynes (CnH2n-2) and their cyclic analogs.The series of straight chain alkanes (saturated hydrocarbons) show a smooth gradation of physical properties. As molecular size increases, each additional CH2 group contributes a fairly constant increment to boiling point and specific gravity. The boiling and melting points of alkanes are fairly low because of symmetrical nature of molecules. Chemically, alkanes are unreactive at ordinary temperature. Hence, naturally occurring petroleum deposits mainly consist of alkanes.The physical properties of alkenes and alkynes (unsaturated hydrocarbons) are very much like the physical properties of alkanes. Hence alkenes and alkynes are not usually found in naturally occurring hydrocarbon deposits. Cycloalkanes and cycloalkenes are about as reactive chemically as their open chain analogs. Different members of cyclic group exhibit different chemical reactivities. Aromatic hydrocarbons (unsaturated cyclic compounds) show gradation in their physical properties with increase in molecular weight and they have the same stability as the carbon- carbon single bond found in alkanes. Mercaptans, alkyl sulphides, aldehydes, ketones, resins and asphaltenes also belong to the category of organic compounds.Hydrocarbon liquids may be composed of several thousands of compounds. A complete chemical analysis for the identification and measurement of constituents is very difficult. Few of the classifications are given below: Paraffins, naphthenes and aromatics as group (PNA) : chains of hydrocarbon segments, branched (iso) or unbranched (normal) types of hydrocarbons are termed as paraffins, naphthenes are similar to paraffins with the exception of containing one or more cyclic structures and aromatics are cyclic benzene type of compounds (six carbon atoms rings) Paraffins base, asphalt base and mixed base oil. Classification based on API of oil etc.Reservoir fluids are commonly identified by their constituents individually to pentanes and heavier compounds are reported as groups composed mostly of components with equal number of carbons such as C6s C7s C8s. The most common method of describing the heavy fraction is to lump all the compounds heavier than C6 and report it as C7+.1.2. Phase BehaviorThe term phase is used to define any homogeneous and physically distinct part of a system which is separated from other parts of the system by definite bounding surfaces. Whether a substance exists in a solid, liquid or gas phase is determined by the temperature and pressure acting on the substance. The study of effect of variation in temperature and pressure on the physical characteristics of the naturally occurring hydrocarbons to establish phase relationship is termed as Phase Behavior. Phase behavior of a hydrocarbon mixture at reservoir and surface conditions is determined by its chemical composition and prevailing temperature and pressure.1.2.1. Phase Diagram of Pure Compound A phase diagram is a graph of pressure against temperature which shows the conditions under which the various phases of the substances may be present. Phase diagram is also referred to as pressure temperature diagram. The word pure refers to a single component system and is considered to be the simplest type of hydrocarbon system. They are not found in nature. We study the phase behavior of a single component in order to understand the relationship between temperature, pressure and volume which provide the understanding of the complex hydrocarbon mixtures.

Fig 1.1.Pressure- Temperature diagram for a single-component systemIn the Fig 1.1, the line OA represents the vapor pressure as a function of temperature and the systems which are represented by points above OA are composed of liquid only. Similarly, points below OA represent systems that are all vapor. The upper limit of vapor pressure line is A. This is known as the critical point, at which the intensive properties of the liquid phase and the vapor phase become identical and they are no longer distinguishable. The lower end of the vapor pressure line is limited by the triple point O. this point represents the pressure and temperature at which solid, liquid, and vapor coexist under equilibrium conditions. The sublimation pressure curve of the solid is given by the line OB which divides the area where solid exists from the area where vapor exists. The line OC represents the change of melting point with pressure and divides the solid area from the liquid area. The line IJ represents an isobaric temperature increase for a system.

1.2.2. Phase Diagram of Two-Component SystemConsider a two component system with fixed overall composition. If the bubble point pressure and dew point pressure for various isotherms on a P-V diagram are plotted as a function of temperature, a P-T diagram similar to that shown in Fig 1.2 is obtained. The P-T diagram indicates the phase changes that occur when the pressure and temperature of a system are varied.

Fig 1.2.A typical Pressure-Temperature diagram for a two-component systemIn the Fig.1.2, the bubble point curve AC and the dew-point curve BC meet at the critical point C. points within the loop ACB represent systems consisting of two phases. Points below dew-point curve represent vapor and points above bubble-point curve represent liquid. As in single-component systems, far removed from two-phase region represent fluid. The dotted curves XC, YC, ZC represent 25%, 50%, and 75% by volume of liquid respectively.If a system originally at point I is compressed isothermally at a temperature below Tc along the path IM, then the system is originally in the vapor state; At the dew-point J liquid begins to form and in passing from J to L more and more liquid condenses. At the bubble-point L the system is essentially all liquid and only an infinitesimal amount of vapor remains. At the point M the system is in the liquid state.

1.2.3. Phase Diagram of a Multicomponent SystemFor a multi-component system with a given overall composition, the characteristics of P-V and P-T diagrams are very similar to those of a two-component system. The multicomponent P-T diagrams are essentially used to classify reservoirs, specify the naturally occurring hydrocarbon systems and describe the phase behavior of the reservoir fluid. Fig 1.3 shows a typical P-T diagram of a multi-component system.

Fig 1.3.Typical Pressure-Temperature diagram of multi-component system1.2.4. Terms Related to Phase DiagramCricondenthermThe cricondentherm is the maximum temperature above which liquid cannot be formed regardless of pressure. The corresponding pressure is termed as cricondentherm pressure.Cricondenbar The Cricondenbar is the maximum pressure above which no gas can be formed regardless of temperature. The corresponding temperature is called the Cricondenbar temperature. Critical point The critical point for a multicomponent mixture is referred to as the state of pressure and temperature at which all the intensive properties of the gas and liquid phases are equal. At the critical point, the corresponding pressure and temperature are called the critical pressure and critical temperature of the mixture.Phase envelope (two phase region) The region enclosed by the bubble point curve and the dew point curve, where gas and liquid coexist in equilibrium, is identified as the phase envelope of the hydrocarbon system.Quality lines The dashed lines within the phase diagram are called quality lines. They describe the pressure and temperature conditions for equal volumes of liquids. Quality lines converge at the critical point.Bubble point curve The bubble point curve is defined as the line separating the liquid phase region from the two phase region.Dew point curve The dew point curve is defined as the line separating the vapor phase region from the two phase region. 1.3. Classification of Reservoir and Reservoir FluidsPetroleum reservoirs are broadly classified as oil gas reservoirs. These broad classifications are further subdivided depending on: The composition of the reservoir hydrocarbon mixture. Initial reservoir pressure and temperature. Pressure and temperature of the surface production Location of the reservoir temperature with respect to the critical temperature and the cricondentherm.In general, reservoirs are classified on the basis of the location of the point representing the initial reservoir pressure, Pi and temperature, T with respect to the p/T diagram of the reservoir fluid. Accordingly, reservoirs can be classified into two types: Oil reservoirs If the reservoir temperature, T is less than the critical temperature, Tc, of the reservoir fluid, the reservoir is classified as an oil reservoir. Gas reservoirs If the reservoir temperature is greater than the critical temperature of the hydrocarbon fluid, the reservoir is called as gas reservoir.1.3.1. Identification of Reservoir FluidsThe classification is essentially based on the properties exhibited by the crude oil, such as, Physical properties, such as API gravity of the stock-tank liquid Composition Initial producing gas/oil ratio (GOR ) Appearance, such as color of the stock-tank liquid Pressure-temperature phase diagramAmong the properties given above, three are generally available: initial GOR, API gravity and color of the separated liquid.The initial GOR is the most important indicator of the fluid type. Color is generally not a reliable mean of differentiating between gas condensate and volatile oils, but in general, dark colors indicate the presence of heavy hydrocarbons. In general, reservoir temperature and composition of the hydrocarbon system greatly influence the behavior of the system.Basically the reservoir fluids are classified into five types. These are: Black oil Volatile oil Retrograde gas Wet gas and Dry gas1.3.2. Black OilBlack oils, or ordinary oils, are the most common type of oil reserves. Its phase envelope is the widest of all types of reservoir fluids, with its critical temperature well above the reservoir temperature. Atypical black oil phase diagram is shown in Fig 1.4. The quality lines are broadly spaced at reservoir conditions with separator conditions lying on relatively high quality lines. The above characteristics lead to a low shrinkage of oil when produced.

Fig 1.4: Phase Diagram of black oilThe GOR may decrease initially when the reservoir pressure falls below the bubble point, as the evolved gas remains immobile at very low saturations. The GOR then increases sharply as the gas to oil mobility ratio within the reservoir varies inversely with the viscosity ratio, which is typically of two orders of magnitude. 1.3.3. Volatile OilVolatile oils have many common features with gas condensates, but as they contain more heavy compounds they behave liquid-like at reservoir conditions. The phase envelope of a volatile oil is relatively wider than that of a gas condensate, with a higher critical temperature due to its larger concentration of heavy compounds. A typical volatile- oil phase diagram is shown in Fig 1.5. The reservoir temperature is near the critical temperature; hence, volatile oils are referred to as near-critical oils. The quality lines are tighter and closer near the bubble point curve. A small reduction of pressure below the bubble point vaporizes a significant fraction of the oil, hence the name volatile oil.Separator conditions typically lie on low quality lines. The GOR increases when the reservoir pressure falls below the bubble point during the reservoir life. Saturation pressures of volatile oils are high. Fig 1.5.Phase Diagram of Volatile Oil

1.3.4. Gas CondensateAtypical gas condensate phase diagram is shown in Fig 1.6. The presence of heavy hydrocarbons expands the phase envelope relative to a wet gas; hence, the reservoir temperature lies between the critical point and the cricondentherm. The amount of potentially condensable hydrocarbons in the reservoir increases with the richness of the gas, as heavy compounds shift the critical temperature towards the reservoir temperature.Retrograde condensation:Retrograde condensation is defined as the formation of liquid by an isothermal decrease in pressure or an isobaric increase in temperature. Similarly, retrograde vaporization is the formation of vapor by an isothermal compression or an isobaric decrease in temperature. In Fig 1.6, this phenomenon is represented by the shaded region.Retrograde phenomena would not occur in a system whose dew-point curve and bubble-point curve meet in an acute angle at the critical point so that the cricondentherm and the cricondenbar are equal to Tc and Pc respectively. The producing GOR initially remains constant until the reservoir pressure falls below the dew point and increases thereafter. It is commonly assumed that the condensate formed in reservoir remains immobile due to its low saturation, and is mostly non-recoverable.

Fig 1.6: Phase Diagram of Gas Condensate

1.3.5. Wet GasA wet gas is mainly composed of methane and other light components with its phase envelope located entirely over a temperature range below that of the reservoir. A typical phase diagram of a wet gas is shown in Fig 1.7, where reservoir temperature is above the cricondentherm of the hydrocarbon mixture. Because the reservoir temperature exceeds the cricondentherm of the hydrocarbon system, the reservoir fluid will always remain in the vapor phase region as the reservoir is depleted isothermally, along the vertical line A-B. As the produced gas flows to the surface, however, the pressure and temperature of the gas will decline. If the gas enters the two-phase region, a liquid phase will condense out of the gas and be produced from the surface separators. This is caused by a sufficient decrease in the kinetic energy of heavy molecules with temperature drop and their subsequent change to liquid through the attractive forces between molecules.Fig.1.7.Phase Diagram of Wet-Gas1.3.6. Dry GasDry gases are predominantly composed of methane and non-hydrocarbons such as nitrogen and carbon dioxide. Figure1.8 shows the phase diagram of a dry gas. The phase envelope is relatively tight and mostly located below the ambient temperature. The gas remains single phase from the reservoir to the separator conditions. Water, however, may condense at the surface conditions due to the gas cooling. PVT tests in the laboratory are limited to the gas compressibility measurement.Fig.1.8.Phase Diagram of dry gasBased upon some characteristics of reservoir fluid, such as the color, gravity, GOR etc., we can distinguish the reservoir fluids among the above mentioned classifications. Table 1.1 shows the nomenclature of a reservoir:Table 1.1.Nomenclature of ReservoirComponentBlack OilVolatile OilGas CondensateWet GasDry Gas

C7+ mole %>3012.5-3060-

Liquid colorGreenish- BlackMedium- OrangeLight-StrawWater-White-

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Chapter2 reservoir fluid properties

Reservoir Fluid PropertiesPhysical properties of primary interest in petroleum engineering studies include: Gas Characteristics: Gas Gravity Gas Solubility Gas Compressibility Factor Gas Formation Volume Factor Coefficient of Isothermal Compressibility of Gas Gas Viscosity Oil Characteristics: Oil Gravity Oil Formation Volume Factor Shrinkage Factor Relative Volume Oil Compressibility Isothermal compressibility coefficient Oil Viscosity2.1. Gas GravityThe specific gravity is defined as the ratio of the gas density to that of the air. Both densities are measured or expressed at the same pressure and temperature. Commonly, the standard pressure Psc and standard temperature Tsc are used in defining the gas specific gravity: 2.1Assuming that the behavior of both the gas mixture and the air is described by the ideal gas equation, the specific gravity can then be expressed as: 2.2

2.2. Solution-Gas Oil RatioIt is defined as the number of cubic feet of gas which will dissolve in one stock tank barrel of oil when both are taken down to the reservoir at the prevailing reservoir pressure and temperature. As the pressure is reduced the gas in solution with oil gets liberated. If the crude is under saturated at initial reservoir temperature and pressure the gas is evolved after reduction of pressure below the bubble point. 2.32.3. Gas Compressibility FactorGas compressibility factor is also called deviation factor, or z-factor. Its value reflects how much the real gas deviates from the ideal gas at given pressure and temperature. Definition of the compressibility factor is expressed as: 2.4For a given amount of gas, if temperature is kept constant and volume is measured at 14.7 psia and an elevated pressure P1,z-factor can then be determined with the following formula: 2.5Where V0and V1 are gas volumes measured at 14.7 psia and P1, respectively.2.4. Gas Formation Volume FactorIt is defined as the volume in barrels that one standard cubic foot of gas will occupy as free gas in the reservoir at the prevailing pressure and temperature. Gas expansion factor E is the inverse of the gas formation volume factor. 2.6 2.72.5. Coefficient of isothermal compressibility of gasThe coefficient of isothermal compressibility of gas (or simply gas compressibility) is defined as the change in gas volume per change in pressure at constant temperature. Gas compressibility Cg is expressed as: 2.8For an ideal gas, 2.9 For real gases, 2.102.6. Gas ViscosityGas viscosity is a measure of the resistance to flow exerted by the gas. Dynamic viscosity (g) in centipoises (cp) is usually used in the natural engineering. Kinematic viscosity (vg) is related to the dynamic viscosity through density (g) as, 2.11Viscosities of natural gases are affected by pressure, temperature, and composition. The viscosity of a specific natural gas can be measured in the laboratory, but common practice is to use the available empirical data. Contrary to the case for liquids, the viscosity of a gas at low pressures increases as the temperature is raised. At high pressures, gas viscosity decreases as the temperature is raised. At intermediate pressure, gas viscosity may decrease as temperature is raised and then increase with further increase in temperature.2.7. Oil GravityLiquid specific gravity, o, is defined as the ratio of the density of the liquid to the density of water, both taken at the same temperature and pressure. 2.12The petroleum industry uses another gravity term called API gravity which is defined as 2.132.8. Oil Formation Volume FactorOil formation volume factor is defined as the volume of reservoir oil required to produce one barrel of oil in the stock tank. 2.14The volume of oil that enters the stock tank at the surface is less than the volume of oil which flows into the well bore from the reservoir conditions to surface conditions is due to three factors: The most important factor is the evolution of gas from the oil as pressure is decreased from reservoir pressure to surface pressure. This causes a rather large decrease in volume of the oil when there is a significant amount of dissolved gas. The reduction in pressure also causes the remaining oil to expand slightly, but this is somewhat offset by the contraction of the oil due to the reduction of temperature.Shrinkage factor is the reciprocal of the Formation volume Factor. 2.152.9. Relative VolumeWhen the pressure of a sample of reservoir oil is decreased below its bubble point pressure, gas is evolved. The change in volume of oil due to this liberation of gas gives the relative volume of gas as, 2.162.10. Isothermal compressibility coefficient of oilIsothermal compressibility coefficients are required in solving many reservoir engineering problems, including transient fluid flow problems, and they are also required in the determination of the physical properties of the under saturated crude oil. By definition, the isothermal compressibility of a substance is defined mathematically by the following expression: For a crude oil system, the isothermal compressibility coefficient of the oil phase B is defined for pressures above the bubble point by one of the following equivalent expressions: 2.17Where, V is volume of the fluid and KT is isothermal bulk modulus, respectively. 2.11. Crude Oil ViscosityCrude oil viscosity is an important physical property that controls and influences the flow of oil through porous media and pipes. The viscosity, in general, is defined as the internal resistance of the fluid to flow. The viscosity of crude oil is affected by pressure, temperature, and most importantly, by the amount of gas in solution. Below the bubble-point, viscosity decreases with increasing pressure because of the thinning effect of gas going into solution. Above the bubble-point, viscosity increases with increasing pressure because of compression of the liquid. If a crude oil is under saturated at the original reservoir pressure, viscosity will decrease slightly as the reservoir pressure decreases. A minimum viscosity will occur at the saturation pressure. At pressures below the bubble-point, evolution of gas from solution will increase the density and viscosity of the crude oil as the reservoir pressure is decreased further. Viscosities of hydrocarbon liquids decrease with increasing temperature for gas-free reservoir crudes.The viscosity of reservoir fluid is measured by capillary viscometer which is based on Hagen-Poiseuille equation. Hagen-Poiseuille law states that the volumetric flow rate Q of a liquid through a cross section of a tube is directly proportional to the pressure difference between the ends of the tube (P-Po) and fourth power of the diameter d of the tube and inversely proportional to the length of tube and viscosity of fluid. The equation is given as: 2.18Due to non-idealities, the operational equation is modified slightly with an empirical factor known as the coil factor, Kv. This factor is calibrated for each coil with fluids of known viscosity.

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Chapter3Reservoir fluid sampling

Reservoir Fluid SamplingOne of the important activities in reservoir management is to ensure that representative reservoir fluid samples are obtained by sampling and proper laboratory measurements are conducted on the samples. It is also equally important that reservoir fluid samples should be stored in containers and maintained under conditions that retain the composition of the original sample over time. Some points to be remembered in sampling the fluids: Reservoir fluids should be sampled as early as possible during the production life of a reservoir, so that the obtained sample is representative. As long as the reservoir pressure has never been below its saturation pressure, and a single phase sample flows into the sampling bottle, the chance of collecting a representative sample is high. So the flow should be in single phase. The well should be conditioned prior to sampling:First, the well should be cleaned such that the collected sample is devoid of contaminants such as drilling mud, rock debris, completion fluids etc.Well cleaning can be ensured by checking the produced fluids in the separator after flowing the well initially for the purpose of well testing and selection of optimum bean size. The well is then flowed at a lower production rate until a minimum and stabilized GOR is obtained. Samples should be taken at the top of the completion interval so that the temperature and pressure are close to reservoir conditions. Mostly the sampler is not lowered below the tubing. Multiple samples are taken to ensure accuracy of the data. Surface samples should be taken only from the first stage high pressure separator and when only a single well is flowing into the separator. 3.1. Sample CollectionThe sample can be collected either as a single phase at the bottom hole, when the pressure is still above the saturation value, or at the surface. Reservoir fluid sampling methods are generally divided into two categories: Subsurface Sampling. Surface Sampling. 3.1.1. Sub-surface SamplingIt is also known as Bottom hole sampling. After the well is ensured of a single flow, a special sampler is run on a wire line. This sampler is activated at the surface so as to retrieve a bottom hole fluid sample under pressure. Fig.3.1 is a schematic drawing of the bottom-hole sampler. The valves are locked open at the surface, the sampler is located at the desired sampling position, and the valves are activated by dropping a metal bar or by a preset clock mechanism. Bottom hole sampling can be done in both the flowing and shut-in conditions of the well.

Fig.3.1: Schematic drawing of bottom-hole fluid sampler.The sampler is then brought to the surface and checked for possible leaks. The pressure in the sampler at the surface is measured to indicate whether or not the sampler was properly activated at the hole. The pressure in the sampler should be slightly less than the bottom-hole pressure at which the sample was collected. 3.1.2. Surface samplingA second technique used in obtaining fluid samples from which to determine PVT relations is known as recombination sampling. For a recombination sample, the fluids are collected at the surface. A sample of separator oil and separator gas is collected, and these samples are recombined in the laboratory in the proper proportions as determined by production characteristics at the surface during sampling operations.Gas and liquid samples are collected from the same separator at the same flow conditions. A larger quantity of separator gas must be collected because of its high compressibility compared with the liquid. The sampling containers can be attached the separator as indicated in Fig. 3.2. Regardless of the method of collecting the fluid samples, the following data should be recorded:1. A volume of oil in the separator compared with a volume of oil in the stock tank. This information permits the field calculation of a shrinkage factor for separator oil. The final shrinkage factor for separator oil is determined in the laboratory by flashing to stock-tank conditions.

Fig.3.2: Schematic layout of productions facilities with indicated sample points for recombined samples.2. The temperature and pressure of the separator3. The temperature and pressure of the stock tank.4. The specific gravity of the stock-tank oil.5. The amount of separator gas produced pre stock-tank barrel (GOR, gas oil ration).6. The gravity of the separator gas obtained in field or laboratory to correct meter measurements.7. The flowing bottom-hole pressure and temperature.8. The shut-in bottom-hole pressure and temperature.With these data it is possible to obtain an analysis of the fluid entering the separator by properly recombining the separator liquid and separator gasThe recombination method of sampling is just as good as the bottom-hole sampling technique for reservoirs where the flowing pressure exceeds the bubble point pressure of the reservoir fluid. When the bottom-hole flowing pressure is less than the bubble point pressure, free gas is produced from reservoir. The bubble point pressure for a recombination sample may be excess of the original bubble-point pressure of the reservoir fluid owing to the excess gas. In most cases, these errors can be found and corrections made by taking into account the other data measured while collecting the sample.3.3. Sample Transfer and Validation (Sub surface sample) After a sample is collected in the sampler, it is sent to the laboratory from the Asset. In the laboratory, the sample is first transferred into a shipping bottle and pressurized. After sample transfer, the validation check is performed to know whether the sample is valid for further analysis. If multiple samples from a single well are available, the Valve Opening Pressure (VOP) and the GOR of the samples are measured. Ideally, all samples should show same properties. But, if there exists any difference in values; generally a sample with low GOR and higher values of VOP are considered to be valid.

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Chapter4Overview of equipment

Overview of EquipmentThis chapter consists of an overview of the equipment required for conducting a complete PVT analysis on a reservoir fluid sample.4.1. PVT Equipment (Chandler PVT 3000)PVT Equipment consists of two cells: a pump cell and an auxiliary cell, enclosed in an insulation chamber. While testing for gas condensates the auxiliary cell is replaced by a gas condensate cell. The volume of pump cell is 400cc and that of gas condensate cell is 1000cc.Maximum pressure: Pump cell and auxiliary cell =15000 psiaGas Condensate cell = 20,000 psiaMaximum Temperature: 200C (400F)The equipment is as shown in Fig 4.1. It is provided with a digital camera for real time monitoring of process going in the cell. All the operations can be carried out automatically using software. For a gas condensate cell, camera is not used; instead a borescope is used which helps in the accurate measurement of condensate. Fig.4.1: PVT equipment4.2. Positive Displacement PumpsPositive displacement pumps are used to change the volume in the cell as well as to transfer the fluids. These are digital controlled single or dual drive pumps. It has feed rates in 0.01cc/min increments. It has a continuous constant pressure flow. They are Quizix 6000 series pumps which are large volume high flow rate pumps. They provide a flow rate of 400 ml/mins. They are configured for single cylinder or multi cylinder continuous flow. Fig 4.2 shows a typical photograph of a positive displacement pump used in the PVT laboratory.

Fig.4.2: Positive Displacement Pump4.3. Digital Gasometer Gasometer can effectively be used as a flow meter. It has 1 and 2 liter volume collection tubes. It gives an accurate estimation of gas and can be used with the separator on the console assembly or directly connected to the PVT system. Fig. 4.3 shows a digital gasometer that is used in the PVT laboratory for accommodating and measuring the gas volumes. Fig.4.3: Gasometer4.4. Density meterThe density meter consists of a hollow elastic tube (oscillator) which is electronically excited in an undamped harmonic fashion. The direction of oscillation is perpendicular to the U-shaped sample tube. The measuring principle of the instrument is based on change of the natural frequency of a hollow oscillator when filled with different liquids and gases. The frequency of the oscillator is only influenced by that fraction of the volume of liquid or gas which is injected in the vibrating part of the sample tube. It is essential to ensure that the oscillator is completely filled. Using the relationship between the density and the natural frequency of filled oscillator the density meter displays the density of the injected sample on a digital screen. The equipment is calibrated using air or water. Specific gravity and API gravity of liquid can be then calculated using their corresponding formulas. Fig 4.4 shows a digital density meter that is used in a PVT laboratory to obtain the density of oil directly.

Fig.4.4: Density meter4.5. Pour Point Apparatus (through AUTOPOUR 300)Pour point is defined as the lowest temperature at which the fluid ceases to flow when cooled and examined under prescribed conditions. Pour point is generally expressed as multiples of 3C as per ASTM standards. The apparatus consists of an internal heating/cooling system, a small motor which provides torque for the rod to be placed inside the sample container, and a digital monitoring system. The equipment is calibrated using benzene.4.6. GAS GRAVITY APPARATUSThe gas gravity can be known using apparatus consisting of a glass bulb, an evacuation pump, a weighing machine, a moisture absorbing material, and connecting pipes. Fig. 4.5 shows the moisture absorbing agents packed in glass tubes. The gas is passed through these tubes before filling into the glass bulb shown in Fig 4.6, so as to ensure that the gas entering into the bulb is moisture free. Fig 4.7 shows an evacuation pump used to create vacuum in the bulb.

Fig.4.5. Moisture Absorbent Fig.4.6. Glass bulb with weighing machine

Fig.4.7. Evacuation Pump

4.7. Analytical EquipmentAnalytical Equipment

Natural Gas Simulated GC-Mass TLC-FID Cryoscope Analyzer Distillation Unit Spectrophotometer Analyzer (Average (GC) (HTGC) (SARA) Mol.wt)4.7.1. Gas chromatograph (GC)Gas Chromatograph is a chemical analysis instrument for separating chemicals in a complex sample using differential adsorption as physical principle. It consists of a column with narrow tubes through which different chemical constituents of a sample pass in a gas stream (carrier gas, mobile phase) at different rates depending on their various chemical and physical properties and their interaction with a specific column filling called the stationary phase. The function of stationary phase in the column is to separate different components, causing each one to exit the column at a different retention time. Two detectors Thermal Conductivity Detector and Flame Ionization Detector are used. Both are sensitive to a wide range of components, and both work over a wide range of concentrations. While TCDs are essentially universal and can be used to detect any component other than the carrier gas (as long as their thermal conductivities are different from that of the carrier gas, at detector temperature), FIDs are sensitive primarily to hydrocarbons, and are more sensitive to them than TCD.Helium is used as carrier gas. Hydrogen and zero air are used for the flame in Flame Ionization Detector (FID). Nitrogen is used for operating the pneumatic valves between the columns in GC. Before injecting the sample the detector is heated with the help of an internal heater. Fig 4.8 shows a typical natural gas chromatographer used in the laboratory.

Fig.4.8: Gas Chromatographer4.7.2. High temperature Gas Chromatograph (HTGC) Liquid trapped in the Flash study is filled in small sample bottles and placed in the vial of HTGC. The auto sampler injects the sample into the column as per the loaded conditioning sequence. Then as per the constituents of the injected sample a chromatogram is obtained. The HTGC also gives the distillation characteristics of the oil using a simulated distillation unit. Recovery of oil after distillation can be useful in estimating the reservoir fluid composition. Manual distillation also can be done using the distillation apparatus shown in the figure. GC- Mass Spectrophotometer is also used for analyzing composition of the liquid but it can give accurate results for a broader range of constituents (C20+) when compared to HTGC. Fig 4.9 shows a typical high temperature gas chromatographer that is used in the laboratory.

Fig.4.9: High Temperature Gas Chromatographer4.7.3. TLC-FID Analyzer (IATROSCAN MK-6S)This equipment is used to know the percentage of Saturates, Aromatics, Resins and Asphaltenes in crude oil. Thin Layer Chromatography (TLC) is the separation of mixtures on thin bonded layers of adsorbent (stationary phase) with a solvent (mobile phase). Equipment consists of a set of ten quartz-silica coated rods, held in a frame, an auto spotter, and a detector. Fig 4.10 shows an auto spotter used to spot the sample on the thin rods. Fig 4.11 shows the Flame Ionization Detector along with the analyzer.

Fig.4.10: Auto Spotter

Fig.4.11: TLC-FID analyzer4.7.4. CryoscopeCryoscope is used to find out the average molecular weight of the sample. It gives molecular weight in terms of molality m, which can be obtained from depression in freezing point Tf and the cryoscopic constant Kf. (Tf = m. Kf ). Fig 4.12 shows typical cryoscopy equipment with a digital display of the molecular weight of the components tested.

Fig.4.12: Cryoscope4.7. Capillary ViscometerA capillary viscometer is an instrument used to find the viscosity of fluids by the measurement of the differential pressure at a constant volume flow of the sample through the capillary. Inside the capillary viscometers, the velocity drop required for viscosity measurement is built up in the form of a laminar tube flow within a measurement capillary. Under idealised conditions, the liquid flows in coaxial layers towards the pressure drop through the capillary. The apparatus as shown in Fig 4.13 consists of a capillary coil, two pump cells, a pressure gauge, all placed in an isothermal chamber. The fluid is flowed from one pump cell to another (under a pressure drop) through the capillary coil. The pressure drop at the ends of the capillary is noted. The flow rate of the fluid is a known parameter; hence in the Hagen-Poiseiulle equation, the only unknown can be calculated.Using this experiment, we can only find out the viscosity of oil but not that of gas. The viscosity of gas cannot be found through laboratory tests; it can be obtained through the use of correlations.

Fig 4.13: Capillary viscometer principlexxx

Chapter5PVT laboratory analysis

PVT Laboratory AnalysisPVT is the study of the behavior of reservoir fluid as a function of pressure, volume, temperature and composition. PVT analysis needs to be performed on the representative sample for managing efficiently the production of natural gas and petroleum reservoirs. Fluids exist in reservoirs as mixtures of gas, oil, and water. Some reservoirs may contain only gas and water, only oil and water, or mixtures of gas, oil, and water. Irrespective of the proportions of these fluids present in a reservoir, obtaining fluid samples and making accurate laboratory studies of PVT and phase-equilibrium behavior of reservoir fluids are necessary for characterizing these fluids and evaluating their volumetric performance at various pressure levels; also for establishing reservoir type, devising strategies for reservoir management, and estimating expected hydrocarbon recovery. In most of the recovery methods the reservoir temperature remains constant; hence reservoir pressure is the main criteria that determine the behavior of fluids. Thus, the volumetric data is determined at reservoir and surface temperatures, hence the name PVT (Pressure Volume Temperature study).5.1. Significance of PVT Relating the observed volumes of Oil and Gas production rates at the surface to the corresponding underground withdrawal. Understanding and predicting the Reservoir behavior throughout its life. Reservoir Simulation Studies. Well Test analysis. Reservoir Development Strategies. Optimizing separator conditions Determining optimum reservoir depletion strategyThe primary information obtained from PVT data is the phase behavior at reservoir condition. Bubble point pressure is another important property which determines the pressure at which the first bubble of gas is liberated. Reservoir fluid is considered to be composed of two components, broadly: oil and gas. The gas phase is characterized in the laboratory by the determination of formation volume factor, specific gravity and gas solubility, flash GOR, liberated GOR and solution GOR. The oil phase is characterized by the formation volume factor, API gravity and density. The parameters are determined through various studies (discussed later), a report is prepared and sent to the respected asset.5.2. Classification of PVT AnalysisPVT analysis is generally classified into two categories: Oil-Gas PVT Analysis Gas Condensate PVT AnalysisOil-Gas PVT Analysis: Studies comprises of: Flash Study PV Study/ Constant Composition Expansion Differential liberation Study/ Constant Volume Expansion Viscosity Measurement Compositional Analysis SARA Analysis Pour Point DeterminationGas Condensate PVT AnalysisOn gas condensate systems the following two types of studies are conducted: Constant Mass Expansion Studies Constant Volume Depletion Studies Compositional study of condensateThe studies for a Gas-Condensate system are limited when compared to Oil-Gas system. Also, a bottom-hole sampling technique cannot be used on a gas-condensate well because of the accumulation of liquid in the bottom of the hole. Thus, in most cases, gas and liquid are collected from a high-pressure separator. The quantities collected are brought to the laboratory and carefully analyzed and recombined to represent the reservoir fluid. This chapter includes description of the various PVT studies of an Oil-Gas system. Given below is a typical activity chart containing the studies conducted on an Oil-Gas sample. The Activity chart for an Oil-Gas system is as follows:

Sample transfer and validity check

Preparation of single phase sample

Cleaning and calibration of PVT cell

Charging sample to PVT cell

Determination of saturation pressure

Two Phase Study

Molar Composition Flash Study Distillation Gas Composition Differential Liberation Characteristics

Thermal Expansion Study

Viscosity Measurements

Calculations, Data Analysis and Report

5.3. PVT STUDIESThis section consists of description of all the laboratory PVT studies conducted on an Oil-Gas sample.5.3.1. Flash Study A liquid trap is arranged in between the pump cell and the Gasometer. Initially the sample is charged from the shipping bottle to the pump cell; pressure and temperature are maintained at the reservoir conditions. The stirrer is turned on and the mixture is allowed to equilibrate. Initial weight of trap is measured. After the equilibrium is attained, initial pump volume is measured. Some portion of the total volume is flashed into the Gasometer i.e. from reservoir condition to ambient condition. Flashing is done in four to five stages. Each time, the gas volume, the volume of liquid trapped and the remaining pump volume are measured. For example, if we have 50 cc volume of sample, we flash 10 cc each in 5 stages. We almost get the same values of GOR in each stage. At last, average of all the five values is recorded. Finally, the gas and liquid portions obtained are sent for compositional analysis.5.3.2. PV StudyThis is also known as Constant Mass Expansion (CME)/Constant Composition Expansion (CCE).The procedure is as follows: The fluid sample is charged into the cell and initially maintained at reservoir temperature and at a pressure beyond reservoir pressure. The pressure is then decreased in stages and the corresponding total cell volume is recorded. The fluid is agitated at each pressure by rotating the cell. This avoids the phenomenon of supersaturation or metastable equilibrium where a mixture remains as a single phase, even though it should split into two phases. As the pressure decreases, at some point of pressure there will be great increase in volume for small changes in pressure. This point can be identified by monitoring the cell contents with the help of camera. The pressure at which we can observe first bubble of gas is the bubble point pressure. Fig 5.1 is a process diagram for the constant mass expansion test; Pb represents the bubble point pressure. P1, P2, P3, P4, P5represents pressures at different stages. Vt1, Vt2, Vt3, Vt4, Vt5 represents the total cell volumes at the respective pressure stages.

Fig.5.1: Constant Mass Expansion Test5.3.3. Differential Liberation StudyThis is also known as constant volume depletion. The procedure is as follows: After the PV study, the cell is maintained at reservoir temperature and bubble point pressure. The pressure is then reduced in stages. As the pressure decreases below bubble point gas is evolved from oil. Hence, both phases exist in the cell at that particular pressure. Then the cell is left until the phases are stable, and then the gas volume present in the cell is removed (through proper monitoring) with the help of pumps and discharge tubes of Gasometer. Care should be taken that no liquid enters into the Gasometer while removing the gas phase. The liquid in the cell then expands in the cell to make it constant volume throughout. The gas volume is noted from the Gasometer. This is done every stage and the corresponding gas volumes are recorded. Fig 5.2 represents process diagram for constant volume depletion test; Pb represents the bubble point pressure.P2, P3represents pressures at different stages. V1is the oil volume in the cell at bubble point. V2, V3, V4, V5 represents the constant oil volumes at the respective pressure stages. There will be small change in oil volumes due to shrinkage of oil as gas is removed.

Fig.5.2: Constant volume depletion test5.3.4. Thermal Expansion Study After differential study, i.e. after the last part of the gas is discharged, the cell is closed, its internal pressure is increased in steps, and the resulting oil volumes are recorded. Then the cell temperature is reduced to 15C, and the oil volume is determined. This volume is the residual oil volume. The plot of these volumes can be extrapolated to atmospheric pressure, so that a measure of the residual oil volume at the given temperature can be determined. This study is mostly conducted on dead oil upon being recommended by the customer. From this, we can obtain thermal expansion of liquid (). This is useful for knowing the temperature at which the oil to be flowed through flow lines.5.3.5. Viscosity Measurement (through Capillary Viscometer) The pump cell and auxiliary cell are connected with a capillary coil of known length and diameter. A sample of 100cc is charged to the pump cell and that of 20cc to the auxiliary cell. Both the cells are maintained at reservoir temperature and pressure. The sample is equilibrated with the help of a magnetic stirrer. The sample is swept from the pump cell to the auxiliary cell. The flow rate is adjusted so as to maintain a constant pressure differential of about 50-55 psia. With the flow rate and pressure differential obtained we can calculate the viscosity of the fluid using the above equation. 5.3.6. Compositional AnalysisCompositional measurements are made using gas chromatography and sometimes true boiling point (TBP) distillation. Gas chromatography measures the weight (mass) fraction of individual components in a mixture. TBP analysis gives additional information about the amount and properties of heavier components (heptanes and heavier, C7+).Gas chromatography is based on selective separation of components as temperature is increased in a capillary tube. The gas liberated in the flash study, and also that from the differential liberation study are injected into the GC from the Gasometer. The gas then flows through the columns of GC. The solutes travel through the column at a rate primarily determined by their physical properties, and the temperature and composition of the column. As each solute elutes from the column, it enters the heated detector. An electronic signal is generated upon interaction of the solute with the detector. The size of the signal is recorded by a data system and is plotted against elapsed time to produce a chromatogram. Fig 5.3 shows a typical diagram of a gas chromatograph.

Fig.5.3: A typical diagram of a gas chromatograph5.3.7. True Boiling Point (TBP) AnalysisTrue boiling point distillation may supplement traditional GC analysis of oil and condensate samples. TBP distillation separates oil into cuts or fractions according to the range of boiling points used for separation. To avoid decomposition ("cracking") of the oil during distillation, vacuum is applied in four stages to reduce the distillation temperatures for heavier components. The distillation usually proceeds from C7 (or C9) to about C25, plus a residue (~C26+). The mass, volume, molecular weight, and density (specific gravity) of each distilled fraction is measured directly. Because the separation of components in a given distillation cut is only approximate, some overlap is observed. The overlap can be corrected to yield an "ideal" distillation curve.One advantage with TBP analysis is that measured molecular weights are available for converting from mass to mole fraction. Molecular weights are measured using a cryoscopy method (freezing point depression), a method that is sensitive to error and probably reliable at best to about 2 to 5%.5.3.8. SARA Analysis The sample is dissolved in dichloromethane to make a solution and sample amount as small as about 0.01gm is spotted at the end of each rod. The components are separated by a three stage solvent development sequence (hexane, toluene, and dichloromethane) according to their relative affinities for the adsorbent. The rods are then directly scanned through the FID to detect and quantify the four separated component classes. The electronic signal from the FID is converted to a chromatogram, from which data are normalized to produce relative concentrations of the component classes. In Fig 5.4, the peaks represents the amount of saturates, aromatics, resins and asphaltenes (in the same order). The area of peaks is evaluated to give the percentage amount of the components.

Fig.5.4: Typical Peaks obtained in SARA analysis5.3.9. Pour Point Determination The sample is placed in the sample chamber and is subjected to preliminary heating to a temperature higher than 45C. After pre-heating, a rod is fitted to the motor on one end and the other end is immersed into the sample. Then the sample is gradually cooled and the system is monitored at every 3C interval. The temperature at which the torque reduces and an icon reading Read Pour starts blinking is the pour point temperature of the sample.5.3.10. Gas Gravity Determination The glass bulb is evacuated using the evacuation pump and the gas from the gasometer is filled into the bulb ensuring that there is no moisture present in the bulb and the gas. Moisture absorbents such as silica gel, CaCl2 are placed between the gasometer and the glass bulb while filling the gas so that the weight of gas measured would be accurate (free of moisture). Then the glass bulb is weighed using the weighing machine. The weight of gas is obtained by subtracting the weight of the empty bulb. The ratio of molecular weight of gas to the molecular weight of air gives the gas gravity.

xxx

Chapter6case study

Case StudyThis chapter consists of a case study involving various studies conducted on a field sample. The analysis of the results obtained from each study, calculations to obtain various parameters are presented. A summary of the PVT data obtained from the analysis is presented at the end of the chapter.A reservoir fluid sample obtained through bottom hole sampling is taken for analysis; the well characteristics and sample details are as given in table 6.1.Table.6.1: Well Characteristics and Sample Details

Formation Characteristics:

Initial Reservoir Pressure, kg/cm2135.7

Current Reservoir Pressure, kg/cm2135.7

Reservoir Temperature, oC 85

Sampling Characteristics:

Type of sample Bottom Hole Sample

Well condition during samplingShut-in

A required volume of the sample from the shipping bottle was charged to the PVT cell (a high-pressure mercury free visual cell, as per the latest art of technology) and thermally expanded to the reported reservoir temperature of 85C, for detailed PVT study.To establish basic volumetric and phase behavior data of reservoir fluid, a set of laboratory experiments were performed which includes: Single stage flash liberation (from reservoir pressure to atmospheric pressure) along with compositional analysis of liberated gas and oil. Constant mass expansion or PV test Differential vaporization along with compositional analysis of liberated gas at different pressure stages. Thermal Expansion study of dead oil Pour point determination, Distillation profile, Sara Analysis and compositional analysis of residual oil. Viscosity study at reservoir temperature at different pressure stages.Flash StudyA flash study is conducted on the sample as stated earlier. The gas liberated from the oil is then analyzed by the gas chromatograph. Table 6.2 gives the composition of gas obtained from the analysis Table.6.2: Molar Composition of Flash gasComponentComponent Volume %

N20.15

O20.00

CO21.51

Methane63.24

Ethane12.07

Propane11.01

i-Butane3.82

n-Butane4.51

i-Pentane1.72

n-Pentane1.45

n-Hexane+0.51

Total100

Molar composition of the liquid trapped in flash study is obtained by analyzing it in the High Temperature Gas Chromatograph. Molar compositions of both phases i.e. gas and liquid are then recombined to give the composition of the well stream as shown in Table 6.3.Recombination Parameters:GOR at ambient condition 65Density of stock tank oil (STO) 0.8315Avg. Molecular Weight of STO 210.0Average Well Stream PropertiesCalculated density at 0 psig and 60F 0.7629Average Molecular weight of well stream 134.9Table.6.3: Molar Composition of Reservoir Fluid by flash studyComponentSTOSTGWell Stream Composition

Mole FractionMole FractionMole%

N200.00150.0623

CO200.01510.6176

C100.632425.9251

C200.12074.9483

C30.00060.11014.5481

IC40.00150.03821.6573

nC40.00340.04512.0492

iC50.00700.01721.1161

nC50.00860.01451.1048

C60.05210.00493.2735

C70.08460.00025.0023

C80.08880.00005.2428

C90.07770.00004.5843

C100.06680.00003.9441

C110.044102.6004

C120.052203.0828

C130.054003.1881

C140.052903.1236

C150.036802.1714

C160.041902.4726

C170.043702.5785

C180.033901.9983

C190.030701.8102

C200.027201.6028

C20+0.1914011.2954

1.001.00100.00

The Flash GOR obtained from the flash study will be greater than the solution GOR that will be obtained later from the differential liberation study. This is due to the fact that, during flashing, some of the intermediate components escape along with the gas (due to high kinetic energy of gas) resulting a greater amount of gas flashed to the gasometer. While for solution GOR, in the differential liberation study, the gas liberated due to decrease in pressure is not removed immediately. Rather, time is left for the phases to get stabilized. Hence the amount of gas collected in the gasometer will be relatively less, resulting in a relatively low GOR. Table 6.4 represents the properties of plus fractions. Table.6.4: Properties of Plus FractionPlus FractionMol %Wt %Mol WtLiquid DensityLiquid API

C7 +54.7089.292200.835437.9

C11 +35.9273.552760.854534.09

C20 +11.3036.084310.875630.10

In Table 6.4, the properties of + fractions indicate the type of reservoir fluid (see table 1.1). Since the C7+ fraction for the sample taken is >45, the reservoir fluid can be characterized as Volatile Oil.PV StudyA constant mass expansion study at reservoir temperature is carried out on the sample and the obtained results after data validation are shown in Table 6.5.Table.6.5: Constant Mass Expansion Study at Reservoir Temperature Pressure (psig)Pressure (kg/cm2)System Volume (cc)

2000140.62155.1

1900133.59155.2

1800126.56155.3

1700119.54155.5

1601112.56155.6

1500105.46155.8

1397*98.23155.94

139097.75156.1

136696.05156.5

136095.64157.0

134694.63157.5

132593.13158.0

*Bubble point pressure (from graph): 1397psig = 98.23 kg/cm2A graph is plot between pressure and system volume as shown below. Bubble Point Pressure is identified as the point at which the slope of the PV-curve changes.6.1. Bubble Point PressureThe values of system volume below and above the bubble point are plotted. They represent two lines with different slopes. The point at which these two lines meet is the bubble point. Fig.6.1: Plot of Pressure vs. System VolumeIn the Fig.6.1, as the pressure from 140.62 kg/cm2 (>reservoir pressure) is reduced in stages, the total volume of the cell increased gradually with a lesser step increase. But when the bubble point is reached, there occurs a greater step increase in the volume due to the liberation of gas from the oil. By knowing the bubble point we can know the duration of single phase flow from the reservoir, and also the recovery factor. If the difference between average reservoir pressure and bubble point pressure is more, then the recovery factor will be more.6.2. Relative Volume Relative Volume is calculated as the ratio of volume of oil at indicated pressure to volume of oil at saturation pressure.The relative volume data frequently require smoothing to correct for laboratory inaccuracies in measuring small volume changes in the total hydrocarbon volume just below the saturation pressure and also at lower pressures. A dimensionless compressibility function known as Y-function is used to smooth the reported relative volume data. The function in its mathematical form is only defined below the saturation pressure and is given by the following expression: 6.1Where, P is indicated pressure in psiaThe Y-function is a straight-line function of pressure or has only a small curvature. To smooth the relative volume data, the Y-function is plotted as a function of pressure on a Cartesian scale. Table 6.6 represents the calculated values of the relative volume and Y-function. The following steps summarize the simple procedure of smoothing and correcting the relative volume data: Calculate the Y-function for all pressures below the saturation pressure by using the equation above. Plot the Y-function versus pressure on a Cartesian scale. Determine the coefficients of the best straight fit of the data, or: Y = a + bP Where, a and b are the intercept and slope of the lines, respectively.Table.6.6: Constant Mass Expansion Study at Reservoir Temperature (Relative Volume and Y-Function at different pressure stages)Pressure(psig)Pressure(kg/cm2)Relative Volume (smooth)Y Function (smooth)

100070.261.172.32

75052.721.392.18

50035.141.852.04

25017.563.281.89

17011.864.621.85

1278.895.921.82

Recalculate the relative volume at all pressure below the saturation pressure from the following expression:

6.2Fitting an equation to a given set of data implies determining the constants a and b such that the resulting straight line equation will closely express the relationship throughout the range of the data. The method of least squares and method of averages can be used to obtain the equation of the best curve which can be fitted to the measured data points. Fig 6.2 represents the plots of relative volume and Y-function against pressure.Fig.6.2: Plots of pressure vs. relative volume and pressure vs. Y-function6.3. Mean Oil CompressibilityOil compressibility can be obtained from the formula, 2.16Assuming Co to be constant as pressure changes, we have 6.3Substituting relative volume (V/Vsat) obtained above for volume, we obtain: 6.4For pressures below bubble point, oil compressibility can be calculated by the formula:6.5Table 6.7 represents the calculated values of oil compressibility. The values are calculated using the relative volume calculated in the section before, and the pressure and system volumes obtained in the PV study.Table.6.7: Mean Oil CompressibilityPressure (psig)Pressure (kg/cm2)System Volume (cc)Co(cc/cc/kg/cm2)Co(psi-1)

2000140.62155.10.0001288.98153E-06

1900133.59155.20.0001359.47921E-06

1800126.56155.30.0001451.02259E-06

1700119.54155.50.0001339.33855E-06

1601112.56155.60.0001521.07112E-06

1500105.46155.80.0001248.72415E-06

1397*98.23155.94__

139097.75156.1_--

136696.05156.5__

136095.64157.0__

134694.63157.5__

132593.13158.0__

Mean Oil Compressibility13.33x10-59.37x10-6

*Bubble point pressure (from graph): 1397psig = 98.23 kg/cm2Hence, Mean Oil compressibility at reservoir temperature (above bubble point) is determined to be 13.33x10-5 cc/cc/kg/cm2 (9.37x10-6/psi). This compressibility can be used in material balance calculations.

Differential Liberation StudyA constant volume expansion test is performed on the sample. Stage gas gravity and residual oil density are the measured values. Cumulative gas gravity, Gas FVF, Oil FVF, Liberated and solution GOR are the calculated values. The results are as given in Table 6.8.Table.6.8: Differential Liberation Study at Reservoir Temperature(Gas gravity, Gas FVF (v/v), Reservoir Oil Formation Volume Factor (Bo), Reservoir Oil Density, Solution GOR and Liberated GOR at different pressure stages)Pressure Stage (psig)Pressure Stage (kg/cm2)Stage Gas GravityCumulative Gas GravityGas FVF(v/v)Res. Oil Density (gm/cc)Res.Oil FVF (v/v)Liberated GOR (v/v)Solution GOR (v/v)

2400168.74___0.72561.2362058

2200154.68___0.72421.2386058

2000140.62___0.72281.2410058

1900133.59___0.72231.2418058

1700119.52___0.72091.2442058

1500105.46___0.71951.2466058

1397*98.23(Gravitational) 0.7189* 1.2468*058

115080.850.71680.71680.01470.72041.2362850

90063.280.68820.70240.01890.72341.22261543

65045.700.70150.70200.02630.72991.19942533

40028.120.74460.71360.04190.73561.17853523

15010.550.87400.75120.10020.74321.15134513

0Atm. Pr.1.47880.91061.24080.76491.0849580

6.4. GAS GRAVITYThe specific gravity of gas, known simply as gas gravity, is defined with reference to air. It is defined as the ratio of the density of the gas to the density of air at the same temperature and pressure:6.6Most of the petroleum industry has adopted the temperature of 60F and the pressure of14.65 psia, as standard conditions. Density is defined as mass per unit volume. Hence, gas density is defined as:6.7If we assume ideal gas behavior at standard conditions, then the above equation becomes:6.8Similarly, the density of air is given by:6.9Therefore, gravity of gas can be obtained by dividing the molecular weight of gas with the molecular weight of air. 6.106.5. OIL FORMATION VOLUME FACTORThe differential oil formation volume factor Bo (commonly called the relative oil volume factors) at all the various pressure levels are calculated by dividing the recorded oil volumes VL by the volume of residual oil Vsc.In Fig.6.3, below the bubble point pressure, the oil formation volume factor increases with pressure. This is because more gas goes into solution as the pressure is increased causing the oil to swell. Above the bubble point pressure, the oil formation volume factor decreases as the pressure is increased, because there is no more gas available to go into solution and the oil is compressed. This compression of oil is termed as shrinkage.The amount of shrinkage is directly related to the amount of gas dissolved in solution and this helps indesigning the surface treating facilities.

Fig.6.3: Plot of pressure vs. Oil Formation volume factor

6.6. SOLUTION GAS-OIL RATIOThe differential solution gas-oil ratio Rs is calculated by dividing the volume of gas in solution by the residual oil volume. Fig 6.4 represents the plots of solution and liberated GOR against pressure.

Fig.6.4: Plots of Pressure vs. Solution and Liberated GORSolution gas oil ratio gives the type of separator to be used at the surface for high GOR fluids, we use horizontal separators, and for low GOR fluids vertical separators are used.We can also know the cumulative gas produced, by multiplying solution GOR with total hydrocarbons produced at stock tank conditions and the time duration.6.7. GAS FORMATION VOLUME FACTORGas FVF is defined as the volume in barrels that one standard cubic foot of gas will occupy as free gas in the reservoir at the prevailing pressure and temperature. 2.6 Gas expansion factor E is the inverse of the gas formation volume factor and is given as: 2.7Fig 6.5 represents the plot of Gas formation volume factor against pressure.

Fig.6.5: Plot of pressure vs. Gas Formation volume factorThese Formation Volume Factors are used in calculations of reserves in place, to know the best aquifer model, ratio of volume of gas cap to the volume of oil (m), and in material balance equation to know cumulative production and recovery factor.The gas liberated at each stage during differential liberation study is analyzed in HTGC and the composition is obtained at various pressure stages is recorded as shown in Table 6.9.Table.6.9. Composition of Differentially liberated Gas at different pressure stagesVolume %VVVVVVVMol.wt of component

PressureComposition11509006504001500

N20.220.200.140.090.050.0228

CO21.321.401.531.721.971.7044

Methane82.5183.9582.3978.1566.2036.5216

Ethane6.947.158.3110.3515.0920.2230

Propane4.203.814.375.689.7920.4744

i-Butane1.301.021.101.412.536.5458

n-Butane1.571.151.151.462.637.6658

i-Pentane0.720.450.390.450.763.3472

n-Pentane0.740.470.370.420.672.8272

C6+0.480.400.260.260.300.7086+

Sum100100100100100100

6.8. GAS COMPRESSIBILITYThe volume of gas evolved at each stage of differential liberation process is measured at the temperature and pressure of the PVT cell (reservoir conditions, R). The volume of the gas is also measured at standard conditions (atmospheric pressure and 60F, sc). Gas compressibility factor is calculated from these volumes as: 6.12It can also be calculated from the gas expansion factor as: 2.7Table 6.10 represents the compositions of produced well streams at different pressures during differential study. This data can be useful to know the composition and also to predict the behavior of reservoir fluid during reservoir depletion.Table.6.10: Compositions of Produced Well Streams at Different Pressures during Differential Study- Mole PercentPressure Step (psi)/Components11509006504001500Residual Oil

N20.040.030.020.010.010.000.00

CO20.660.630.590.510.410.250.00

C127.2624.4521.2116.1311.095.380.00

C25.084.994.874.594.122.980.00

C33.863.853.853.813.653.020.00

iC41.161.151.161.161.141.000.04

nC41.311.301.311.321.311.170.05

iC50.610.600.610.630.650.630.17

nC50.530.520.520.540.550.530.14

C61.251.301.351.441.551.681.87

C72.863.013.173.433.704.084.76

C84.544.775.035.455.896.507.61

C96.556.887.267.868.509.3811.00

C104.294.504.755.145.566.147.20

C113.203.373.553.844.164.595.38

C123.683.874.084.424.785.286.19

C133.603.793.994.324.685.166.05

C143.443.623.814.134.474.935.78

C152.372.492.622.843.073.393.97

C162.402.522.662.883.123.444.04

C172.842.983.153.413.694.074.77

C182.202.322.442.652.863.163.70

C192.042.142.262.442.642.913.42

C201.922.022.132.312.492.753.23

C20+12.2812.9013.6114.7315.9317.5820.62

6.9. Oil ViscosityViscosity is measured at various pressure stages using capillary viscometer and the results are as given in Table 6.11. Fig 6.6 represents the plot of oil viscosity against pressure.Table.6.11: Reservoir Oil Viscosity at different pressure stage (At Reservoir Temperature)Pressure (psig) Pressure (kg/cm2) Viscosity (cp)

2750193.350.9791

2500175.770.9656

2250158.190.9479

2000140.620.9287

1750123.040.9095

1397*98.23 0.8828*

120084.371.0220

90063.281.1101

60042.191.2495

30021.091.3716

00.001.7731

*Bubble point pressure (from graph): 1397psig = 98.23 kg/cm2

Fig.6.6: Plot of Pressure vs. Oil ViscosityDepending on the viscosity of the fluid sample, the type of crude can be known; and based on this the best field development/recovery method can be adopted. (Steam flooding, in-situ combustion etc.). Using viscosity, mobility ratio of either oil gas or water can be calculated and based on this mobility the relative permeability can be calculated.Oil Characteristics Pour Point : 36oC Water Content : Nil DISTILLATION PROFILE(Using High Temperature Simulated Distillation) I. B. P. : 68oC Recovery Details: Table 6.12 gives the distillation characteristics of the sample.

Table.6.12: Distillation Characteristics% RecoveryTemperature Range (oC)

5125.8

10160

20216.4

30259.2

40301.1

50333.1

60370.5

70407.4

80439.5

90480.6

95.8525.1

SARA ANALYSIS OF RESIDUAL OIL (>250oC) (Using TLC/FID Analyzer) Saturates: 86.2% Aromatics: 6.8% Resins: 4.9% Asphaltenes: 2.1%Summary of PVT DataReported Reservoir Conditions Initial/Current Reservoir Pressure, kg/cm2135.7 (1930 psig)

Reservoir Temperature, oC85 (185oF)

Pressure-Volume Relations Saturation Pressure, kg/cm298.23 (1397 psig)

Oil Compressibility (between 135.7 kg/cm2& 98.23 kg/cm2), at reservoir temperature, cc/cc/kg/cm213.33x10-5 (9.37x10-6/psi)

Single Stage Flash Study (at 2100 psig) Flash GOR, v/v65

Flash FVF at 2100 psig, v/v1.260

Flash FVF at Reservoir Pressure, v/v1.261

Flash FVF at Pb, v/v1.266

Reservoir Oil Density, gm/cc0.7223

Stock Tank Oil Density at 15.5oC, gm/cc0.8315

Gas Gravity of flash liberated gas0.9889 (gravitational)

Shrinkage (%) at Reservoir Pressure20.70

Mean Gas Solubility, cc/cc/kg/cm20.6602

Differential Vaporization Data Solution Gas/Oil Ratio, v/v58

Differential FVF at Pb, v/v1.247

API of Dead Oil38.84

Dead Oil Density at 15.5oC, gm/cc0.8299

Gas Gravity of differentially liberated gas0.9106

Thermal Expansion Coefficient of dead oil at 500 psig between 40oC and 85oC8.7 x 10-4

Viscosity at Reservoir condition (135.7 kg/cm2& 85oC), cp0.9205

Viscosity at Saturation Pressure (98.2 kg/cm2& 85oC), cp0.8828

Dead oil Viscosity at 14.7 psia & 85oC, cp1.7731

Viscosity Data

7. BIBLIOGRAPHY Ali Danesh : PVT and Phase Behavior of Petroleum Reservoir Fluids -1998 Emil J. Burcik : Properties of Petroleum Reservoir Fluids -1979 Tarek Ahmed : Reservoir Engineering Handbook, Third Edition-2006 James W. Amyx, Daniel M. Bass Jr., Robert L. Whiting: Petroleum Reservoir Engineering - 1960 William D. McCain Jr.: Properties of Petroleum Fluids, Second Edition-1990 L.P.Dake : Fundamentals of Reservoir Engineering -1978 http://www.google.com http://www.ipt.ntnu.no/~curtis/courses/PVT-Flow/2013-TPG4145/e-notes/PVT-Papers/Hydro%20PVT%20Manual%20Chap%203.pdf Reservoir-Fluid Sampling Revisited- A Practical Perspective (SPE paper) https://www.onepetro.org/journal-paper/SPE-101037-PA

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