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Petroleum Production System 2nd custom-speeches.com - Ebook download as PDF File .pdf), Text File .txt) or read book online. Petroleum Production Systems Second Edition Michael J. Economides A. Daniel Hill Christine Ehlig-Economides Ding Zhu. Upper Saddle River, NJ • Boston. PETROLEUM PRODUCTION SYSTEMS. SECOND EDITION. Michael J. Economides. A. Daniel Hill. Christine Ehlig-Economides. Ding Zhu. Upper Saddle River.


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Second Edition [PDF] [EPUB] The Definitive Guide to Petroleum Production Systems–Now Fully. Updated With the Industry's Most Valuable. Petroleum Production Systems Second Edition Michael J. Economides A. Daniel Hill Christine Ehlig-Economides Ding Zhu Upper Saddle River, NJ \u Natural Gas. ✓International demand destruction is larger than was anticipated. ✓ Because of LNG developments in Qatar,. Egypt and Sakhalin 2, there could be.

Part three introduces artificial lift methods, including sucker rod pumping systems, gas lift technology, electrical submersible pumps and other artificial lift systems.

Part four is comprised of production enhancement techniques including, identifying well problems, designing acidizing jobs, guidelines to hydraulic fracturing and job evaluation techniques, and production optimization techniques. Provides complete coverage of the latest techniques used for designing and analyzing petroleum production systems Increases efficiency and addresses common problems by utilizing the computer-based solutions discussed within the book Presents principles of designing and selecting the main components of petroleum production systems Contents: Petroleum Production Engineering Fundamentals: Chapter 1: Petroleum Production System Chapter 2: Properties of Oil and Natural Gas Chapter 3: Reservoir Deliverability Chapter 4: Wellbore Performance Chapter 5: Choke Performance Chapter 6: Well Deliverability Chapter 7: Forecast of Well Production Chapter 8: Equipment Design and Selection Chapter 9: Well Tubing Chapter Separation Systems Chapter Artificial Lift Methods Chapter Sucker Rod Pumping Chapter Gas Lift Chapter Production Enhancement Chapter Well Problem Identification Chapter Matrix Acidizing Chapter Hydraulic Fracturing Chapter Production Optimization Appendix A: Unit Conversion Factors Appendix B: Order Online - http: If you have any questions please visit http: Product Name: Last Name: Email Address: Phone Number: Fax Number: You will receive an email with a link to a secure webpage to enter your Pay by credit card: Pay by check: Prentice Hall.

Carbo Ceramics. Curtis Whitson. As we did for the first edition. Discussions with many of our colleagues in industry and academia have also been a key to the completion of the book. PennWell Publishing Co. Elsevier Science Publishers. Imran Ali for their assistance in the production of this second edition. We would like to gratefully acknowledge the following organizations and persons for permitting us to reprint some of the figures and tables in this text: Chen Yang.

Michael J. Economides A chemical and petroleum engineer and an expert on energy geopolitics. He has written 15 textbooks and almost journal papers and articles. Second Edition. Economides is a professor at the University of Houston and managing partner of Economides Consultants. Petroleum Production Systems. The author of papers. Daniel Hill Dr. National Academy of Engineering. Christine Ehlig-Economides Dr.

Christine Ehlig-Economides holds the Albert B.

Charllyson Luiz

Ehlig-Economides provides industry consulting and training and supervises student research in well production and reservoir analysis. She has authored more than 70 papers and journal articles and is a member of the U. Ding Zhu Dr. Zhu is a coauthor of more than technical papers and one book. Ding Zhu is associate professor and holder of the W. Introduction Petroleum production involves two distinct but intimately connected general systems: Modern formation evaluation provides a composite reservoir description through three-dimensional 3-D seismic.

The drilling of these wells is never left to chance but. Complex well architecture. Such description leads to the identification of geological flow units.

As such. Control of drilling-induced. In the 15 years that separated the first and second editions of this textbook worldwide production enhancement. Production engineering technologies and methods of application are related directly and interdependently with other major areas of petroleum engineering.

Production engineering is that part of petroleum engineering that attempts to maximize production or injection in a cost-effective manner. Drilling creates the all-important well. In contrast. In practice one or more wells may be involved. Connected flow units form a reservoir. Some of the most important connections are summarized below. Single-well performance. The distinction is frequently blurred both in the context of study single well versus multiple well and in the time duration of interest long term versus short term.

Reservoir engineering in its widest sense overlaps production engineering to a degree. In developing a petroleum production engineering thinking process. Volume and Phase of Reservoir Hydrocarbons 1. Components of the Petroleum Production System 1. This is particularly true in identifying lateral and vertical boundaries and the inherent heterogeneities. While the shape of a well and converging flow have created in the past the notion of radial flow configuration.

Appropriate reservoir description. Reservoir The reservoir consists of one or several interconnected geological flow units. Figure is a schematic showing two wells. Common reservoir heterogeneities. The encountering of lateral discontinuities including heterogeneous pressure depletion caused by existing wells has a major impact on the expected complex well production. Whether a reservoir is an anticline. While appropriate reservoir description and identification of boundaries.

There is little doubt that the best petroleum engineers are those who understand the geological processes of deposition. Porosity All of petroleum engineering deals with the exploitation of fluids residing within porous media. Understanding the geological history that preceded the present hydrocarbon accumulation is essential. These issues become critical when horizontal and complex wells are drilled. Figure For example. These layers are usually considered impermeable.

Porosity values vary from over 0. Porosity is one of the very first measurements obtained in any exploration scheme. Figure is a well log showing clearly the deflection of the spontaneous potential of a sandstone reservoir and the clearly different response of the adjoining shale layers. In the absence of substantial porosity there is no need to proceed with an attempt to exploit a reservoir.

Well logging techniques have been developed to identify likely reservoirs and quantify their vertical extent. At times the thickness of the hydrocarbon-bearing formation is distinguished from an underlaying water-bearing formation. This deflection corresponds to the thickness of a potentially hydrocarbon-bearing.

The porosity of the reservoir can be measured based on laboratory techniques using reservoir cores or with field measurements including logs and well tests. The presence of satisfactory net reservoir height is an additional imperative in any exploration activity.

Spontaneous potential and electrical resistivity logs identifying sandstones versus shales. Frequently the use of the terms oil and gas is blurred. Knowing that formation brines are good conductors of electricity i. These variables can allow the estimation of hydrocarbons near the well..

If the water is present but does not flow. A classic method. Petroleum hydrocarbons. Classification of Reservoirs All hydrocarbon mixtures can be described by a phase diagram such as the one shown in Figure Water is always present. Flowing oil and gas in the reservoir imply. Plotted are temperature x axis and pressure y axis.

A specific point is the critical point. The combination of porosity. Produced oil and gas refer to those parts of the total mixture that would be in liquid and gaseous states.

The previously described SP log along with the resistivity log. With proper calibration.

Any mixture depending on its composition and the conditions of pressure and temperature may appear as liquid oil or gas or a mixture of the two. Figure also contains a resistivity log.

An attractive hydrocarbon saturation is the third critical variable along with porosity and reservoir height to be determined before a well is tested or completed. More frequently.

For lower pressures at constant temperature. If the initial reservoir pressure is less than or equal to the bubble-point pressure. Oilfield hydrocarbon phase diagram showing bubble-point and dew-point curves. This happens until a limited value of the pressure. These are usually measured in the laboratory with tests performed on fluid samples obtained from the well in a highly specialized manner.

Petroleum Production Engineering

This factor is simply a ratio of the volume of liquid or gas under reservoir conditions to the corresponding volumes under standard conditions.

Advances in 3-D and wellbore seismic techniques. In Equation the area is in acres. The gas formation volume factor traditionally. Equation can lead to the estimation of the oil or gas volume under standard conditions after dividing by the oil formation volume factor. For gas. The porosity. Areal Extent Favorable conclusions on the porosity.

Discontinuities and their locations can be detected. Each hydrocarbon reservoir has a characteristic phase diagram and resulting physical and thermodynamic properties. As more wells are drilled. The gas formation volume factor is much smaller than 1. Petroleum thermodynamic properties are known collectively as PVT pressure—volume—temperature properties.

The concept of permeability was introduced by Darcy in a classic experimental work from which both petroleum engineering and groundwater hydrology have benefited greatly. Permeability The presence of a substantial porosity usually but not always implies that pores will be interconnected. Thus the oil formation volume factor is invariably larger than 1. The reader is referred to the classic textbooks by Muskat In certain lithologies e. Craft and Hawkins revised by Terry. Correlations of porosity versus permeability should be used with a considerable degree of caution.

The present textbook assumes basic reservoir engineering knowledge as a prerequisite. In this instance. For production engineering calculations these correlations are rarely useful. In other lithologies e. The flow rate or fluid velocity can be measured against pressure head for different porous media.

The Zone near the Well. If fluids of other viscosities flow. This means that the pressure drop in the first foot away from the well is naturally equal to that 10 feet away and equal to that feet away.

Water flows through a sand pack and the pressure difference head is recorded. Darcy observed that the flow rate or velocity of a fluid through a specific porous medium is linearly proportional to the head or pressure difference between the inlet and the outlet and a characteristic property of the medium. Hydraulic fracturing. If no zonal isolation or wellbore stability problems are present.

Many wells are cemented and cased. Slotted liners can be used if a cemented and cased well is not deemed necessary and are particularly common in horizontal wells where cementing is more difficult.

There is damage associated even with stimulation. Matrix stimulation is intended to recover or even improve the near-wellbore permeability. One of the purposes of cementing is to support the casing. The various well completions and the resulting near-wellbore zones are shown in Figure Options for well completions. It is the net effect that is expected to be beneficial. Contamination of the produced fluid from the other formations or the loss of fluid into other formations can be envisioned readily in an open-hole completion.

A cemented and cased well must be perforated in order to reestablish communication with the reservoir. The ability to direct the drilling of a well allows the creation of highly deviated. Gravel packing can be used as an additional safeguard and as a means to keep permeability-reducing fines away from the well.

There is a required flowing pressure gradient between the bottomhole and the well head. In the case of formation water it is usually disposed in the ground through a reinjection well. The Surface Equipment After the fluid reaches the top. Mechanical lift can be supplied by a pump. Another technique is to reduce the density of the fluid in the well and thus to reduce the hydrostatic pressure.

In these cases. The former depends on the reservoir depth and the latter depends on the well length. The pressure gradient consists of the potential energy difference hydrostatic pressure and the frictional pressure drop.

An exception that is becoming more common is in some offshore fields. The Well Entrance of fluids into the well. This is accomplished by the injection of lean gas in a designated spot along the well. The reservoir. The flow systems from the reservoir to the entrance to the separation facility are the production engineering systems that are the subjects of study in this book.

If the bottomhole pressure is sufficient to lift the fluids to the top. The reservoir fluid consists of oil. The petroleum production system. The role of a petroleum production engineer is to maximize the well deliverability in a cost-effective manner. The IPR represents what the reservoir can deliver. Well deliverability gap between the original well performance and optimized well performance.

Understanding and measuring the variables that control these relationships well diagnosis becomes imperative. Well Productivity and Production Engineering 1. The Objectives of Production Engineering Many of the components of the petroleum production system can be considered together by graphing the inflow performance relationship IPR and the vertical flow performance VFP.

In reservoirs with pressure drawdown-related problems fines production. For a specific reservoir with permeability k. A negative skin effect can be imposed if a successful hydraulic fracture is created. For pseudosteady state flow.

The terms steady state. Equation succinctly describes what is possible for a petroleum production engineer. The concept of the dimensionless productivity index combines flow geometry and skin effects. For steady-state flow to a vertical well. The latter. While these concepts will be dealt with extensively in subsequent chapters. With diagnostic information in hand.

While the IPR remains the same. The production engineer has three major tools for well performance evaluation: Organization of the Book This textbook offers a structured approach toward the goal defined above. Remedial steps can range from well stimulation procedures such as hydraulic fracturing that enhance flow in the reservoir to the resizing of surface flow lines to increase productivity. For an appropriate product engineering remedy.

This textbook is aimed at providing the information a production engineer needs to perform these tasks of well performance evaluation and enhancement. The VFP change in Figure shows that the flowing bottomhole pressure may be lowered by minimizing the pressure losses between the bottomhole and the separation facility by. Increasing the drawdown p — pwf by lowering pwf is the other option available to the production engineer to increase well deliverability.

Improving well deliverability by optimizing the flow system from the bottomhole location to the surface production facility is a major role of the production engineer. In summary. Hydraulic fracturing is discussed in Chapters 17 and This textbook is designed for a two-semester. Examples and homework follow a more modern format than those used in the first edition. Less emphasis is given to hand-done calculations.

To employ these equations with SI units. Conversion factors between oilfield and SI units are given in Table All equations presented include the constant or constants needed with oilfield units. Table Calculate the pressure drawdown pe — pwf in Pa for the following SI data. Using the conversion factors in Table Since re is divided by rw. Solution Using the first approach.

Substituting the. Les Fontaines Publiques de la Ville de Dijon. Fundamentals of Reservoir Engineering. Englewood Cliffs. New York.

Physical Principles of Oil Production. Applied Petroleum Engineering. Petroleum Reservoir Engineering. Advances in Well Test Analysis. References 1. Victor Dalmont. New York.. SPE Monograph. Introduction Well deliverability analysis predicts the wellbore flowing pressure for a given surface flowrate. Equation is general and suggests a number of interesting observations. To understand the process of flow from the reservoir and into the well sandface.

Chapters 2—5 deal with well inflow performance and describe the reservoir variables that control well productivity under different conditions. Steady-State Well Performance Steady-state performance means that all parameters. In a well within a reservoir.

A reservoir being waterflooded is the most common situation for which steady-state behavior approximates the actual production well conditions. Reservoir schematic for steady-state flow into a well.

For a vertical well draining a region with radius re. Assuming that q is constant. This skin effect results in an additional steady-state pressure drop. They apply to all types of flow. This is analogous to the film coefficient in heat transfer. Two other important concepts are outlined below. Equation becomes and with rearrangement for the rate.

Van Everdingen and Hurst quantified the condition of the near-wellbore region with the introduction of the concept of the skin effect. Thus Equation becomes If the reservoir exhibits a constant-pressure outer boundary at re. Equation is semi-logarithmic. For steady-state production. The effective wellbore radius.

Calculate the steady-state production rate if the flowing bottomhole pressure is equal to. Example In a damaged well. In this case. Show calculations. The well radius is 0. Solution Assuming that the skin effect is zero this would result in the most pronounced difference in the production rate. Effect of Drainage Area on Well Performance Demonstrate the effect of drainage area on oilwell production rate by calculating the ratios of production rates from A second possibility is to increase JD by reducing the skin effect.

Solution From Equation The results are shown in Table Production Rate Increases over a acre spacing. These ratios indicate that the drainage area assigned to a well has a small impact on the production rate. For tight reservoirs. Transient Flow of Undersaturated Oil The diffusivity equation describes the pressure profile in an infinite-acting.

Equation becomes This expression is often known as the pressure drawdown equation describing the declining flowing. Equation This equation. More commonly. Figure is a rate-decline curve for this oil well for the first year assuming infinite-acting behavior. Because a producing well is usually flowing for long times with the same wellhead pressure which is imposed by the well hardware. Solution From Equation and substitution of the appropriate variables in Appendix A.

Do this in increments of 2 months and use a flowing bottomhole pressure equal to psi. Because the pressure profile is not changing.

This is defined as a volumetrically weighted pressure.

Petroleum Production Systems 2nd Edition Michael J Economides pdf

For no-flow boundaries. The pressure at the outer boundary is no longer constant but instead declines at a constant rate with time. Equation can be converted to This equation is not particularly useful under pseudosteady state conditions. In Section the steady-state condition implied a constant-pressure outer boundary. That is. Equation becomes. Induced constant pressure may be the result of injector—producer configurations.

It depends on the drainage area and the properties of the fluid and rock. Material balance calculations presented in Chapter 10 combine depletion mechanisms with inflow relationships and lead to forecasts of well performance and cumulative production.

They represent distinctly different reservoir production mechanisms. For steady state: The average pressure. The expression for the pressure at any point r can be substituted from Equation In both cases. Substituting the given variables in Equation results in The flow-rate ratio after the psi average pressure decline would be 2. Production from a No-Flow Boundary Reservoir What would be the average reservoir pressure if the outer boundary pressure is psi.

For a regular shape such as a circle or a square. What would be the ratio of the flow rates before q1 and after q2 the average reservoir pressure drops by psi? If the drainage area can be approximated by a circle with an equivalent drainage radius re.

The time tpss is in hours. Off-centered wells in irregular patterns have even larger values of tDApss. Even if they are assigned regular geographic drainage areas. The drainage area is then shaped by the assigned production duty of a particular well.

Equation is for a well at the center of a circle. To account for irregular drainage shapes or asymmetrical positioning of a well within its drainage area. Equation can be generalized for any shape into Figure Earlougher.

Wells Draining Irregular Patterns Rarely do wells drain regular-shaped drainage areas. Shape factor for various closed. From Earlougher. Calculate the production rates from the two wells at the onset of pseudosteady state. At late time.

Well B Since it is located at the center of the upper right quadrant. The flowing bottomhole pressure in both is psi. This calculation is valid only at very early time. A map with well locations is shown in Figure Solution Well A The shape factor. Use properties as for the reservoir described in Appendix A. All other variables in Equation remain the same. Three-well fault block for Example At the end of the days. From a problem by H. If the bottomhole pressure is psi for each well.

Solution The drainage volumes formed by the production rate of each well are related by and. Each well produced for days since the previous shut-in. The average pressures in the drainage areas for wells B and C are calculated to be and psi. Equations The next step is to sketch these areas on the fault block map. From Figure Such uneven depletion is common and is an important variable to know in any reservoir exploitation strategy.

Each map square represents The drainage divide must be normal to the timeline between adjoining wells. These describe shapes and therefore approximate shape factors. From Equation and for well A. If the reservoir thickness were the same throughout. Solution Equation with substituted variables takes the form The relationship between q and pwf of course will depend on time. The following examples illustrate these concepts. Assume zero skin. It is then useful to present the relationship between the well production rate and the bottomhole pressure as the inflow performance relationship IPR.

If the bottomhole pressure is given. Figure is a graph of the transient IPR curves for the three different times. Inflow Performance Relationship All well deliverability equations relate the well production rate and the driving force in the reservoir.

Equation becomes Similarly. Draw IPR curves for skin effects equal to 0. Steady-State IPR: Influence of the Skin Effect Assume that the initial reservoir pressure of the well described in Appendix A is also the constant pressure of the outer boundary.

Solution Equation describes a straight-line relationship between q and pwf for any skin effect. Transient IPR curves for Example Figure gives the steady-state IPR curves for the four skin effects.

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Steady-state and impact of skin effect for Example For a circular drainage shape. This is a time-dependent calculation. Combination volumetric material balances treated in Chapter 10 will allow the forecast of rate and cumulative production versus time.

Substituting the variables from Appendix A into Equation results for in. Use all other variables from Appendix A. Solution Equation is the generalized pseudosteady-state equation for any drainage shape and well position.

Equation is sufficient. Drainage radius is ft.

Pseudosteady-State IPR: Influence of Average Reservoir Pressure This calculation is the most useful and the one most commonly done for the forecast of well performance. For this exercise. For all average reservoir pressures. Pseudosteady-state IPR curves for a range of average reservoir pressures Example The intercept will simply be the average pressure. For these simplified examples. In petroleum reservoirs. The sum of these permeability values is invariably less than the absolute permeability of the formation to either fluid.

If both oil and free water are flowing. In reality this is only an approximation. Relative Permeability All previous sections in this chapter provided volumetric flow rates of undersaturated oil reservoirs as functions of the permeability.

Effects of Water Production. When the water saturation. It is not a good practice to use relative permeability values obtained for one reservoir to predict the performance of another. This permeability was used as a reservoir property. Relative permeability effects. In mature petroleum areas. Their economic viability is frequently one of the most important questions confronting production engineers.

Note that the pressure gradients have been labeled with subscripts for oil and water to allow for different pressures within the oil and water phases. In an almost depleted reservoir it would not be unusual to obtain water—oil ratios of 10 or larger. The production engineer selects the most appropriate of these relationships based on the farfield boundary condition for the well of interest.

If there is no effect of a boundary felt at the well. Summary of Single-Phase Oil Inflow Performance Relationships This chapter has presented three inflow performance equations that can be used to analyze the reservoir behavior for single-phase oil production: If the pressure.

Society of Petroleum Engineers. Advances in Well Test Analysis.. Les Fontaines Publiques de la Ville de Dijon.. Redistribution or other use that violates the fair use privilege under U.. Van Everdingen. Conduction of Heat in Solids. Clarendon Press. The flowing bottomhole pressure is psi. Explain your result.

The average pressure in a reservoir is psi. Using the variables for the well in Appendix A. Obtain other variables from Appendix A. Calculate this time for the well described in Appendix A if the drainage area is 80 acres.

Problems Use the well and reservoir properties in Appendix A. Equation provided the time for beginning of pseudosteady state. Generate inflow performance relationship IPR curves for three permeability values of 1 md. If the well drainage area in another reservoir is half that of the first reservoir. Use zero skin and psi bottomhole flowing pressure for both wells. The drainage area is 40 acres. An oil well produces under steady-state conditions. Calculate the total pressure gradient required for values of skin of 0.

Calculate flow rate from transient relationship. The reservoir pressure is psi.

Assume that all other variables are the same. Assume that there is no skin effect in the well system. In each case. Use this flow rate to solve for from the pseudosteady-state relationship.

Continue Problem 4. The discount rate time value of money is 0. Plot the well IPR for each skin value. Given the well data in Appendix A. Select the appropriate flow equation based on Equation What would be the average reservoir pressure at that time? What are the fractional contributions from each year to the 3-year discounted present value? Plot the corresponding IPR curves. Display 5 equal increments for time and 10 for wellbore flowing pressure.

For the well described in Problem How would be the presence of a skin effect change this comparison? Use skins equal to 0. Repeat for average reservoir pressures of and psi. Depending on the initial and flowing pressures and the reservoir temperature. Figure is a schematic of a classic phase diagram. It is likely that even in the best of cases the issue is addressed in Chapter In terms of ultimate recovery. Introduction The performance relationships presented in Chapter 2 were for single-phase oil wells and.

The flowing bottomhole pressure. For comparison. Marked are reservoir. In this depiction. In the gas cases there is a much more pronounced reduction in the temperature along the path. In an initially saturated reservoir. Solid lines connote single-phase flow. In Figure Schematic phase diagram of hydrocarbon mixture. The flowing bottomhole temperature is taken as equal to the reservoir temperature.

The wellhead flowing conditions. In Figure B-1b the formation volume factor of the gas. Rs decreases with decreasing reservoir pressure because gas comes out of solution.

Below pb. The solution gas—oil ratio is the amount of gas that would be liberated from a unit volume of oil at standard conditions. This increase is slight because liquid oil compressibility is small. Bo increases with decreasing pressure. These pressure—volume—temperature PVT properties are usually obtained in the laboratory and are unique to a given reservoir fluid.

Above the bubble-point pressure. Below the bubble-point pressure. Above pb. Figure B-1c shows the solution gas—oil ratio.

General Properties of Saturated Oil The bubble-point pressure is the important variable in characterizing saturated oil. Bo decreases as pressure decreases. At pressures above the bubble point.

The formation volume factor. The variables Bo. As oil is produced from a fixed reservoir volume. When the produced gas—oil ratio observed for a well is greater than the solution gas—oil ratio. Rs is constant as Rsb. At a pressure below the bubble point. Properties of Saturated Oil 3. Figure B-1a in Appendix B shows a plot of Bo versus pressure for an example two-phase well. Then from Equation These correlations should be used only in the absence of experimentally determined PVT properties obtained for the specific reservoir.

Impact on Oil Reserves Calculate the total formation volume factor at psi for the reservoir fluid described in Appendix B. The remaining original reservoir volume is now filled with gas that came out of solution from the oil. From Appendix B. Figures and Solution From the figures in Appendix B.

What would be the reduction in volume of oil STB in acres of the reservoir described in the same Appendix when the average pressure is reduced from the initial pressure to psi?

Assume that the initial pressure is the bubble-point pressure and is equal to psi. The correlation shown in Figure can be computed with the following equation: Solution Reading from Figure in a stairstep manner with the first set of variables. After Standing. Using Equation Properties of natural mixtures of hydrocarbon gas and liquids. Figure can be used for the last question. Property Correlations for Two-Phase Systems. They can be obtained from laboratory PVT data or from correlations.

One common correlation is the one of Standing. Here ql is the actual liquid flow rate at some location in the well or reservoir. Another correlation that is accurate for a wide range of crude oils is that by Vasquez and Beggs The downhole gas rate depends on the solution gas—oil ratio.

The solution gas—oil ratio is then. The oil-formation volume factor and the solution gas—oil ratio. This subsection presents the most widely used property correlations for two-phase oilfield hydrocarbon systems.

The downhole volumetric flow rate of oil is related to the surface rate through the formation volume factor. Above the bubble point. It can be estimated from Figure Katz et al. At the bubble point. Then Equation or may be used to calculate Bob. After Katz et al.

Prediction of gas gravity from solubility and crude-oil gravity. Copyright Oil Viscosity Oil viscosity can be estimated with the correlations of Beggs and Robinson and Vasquez and Beggs Handbook of Natural Gas Engineering. Then where Gas viscosity can be estimated with the correlation that will be given in Chapter 4.

For pressures above the bubble point. The volume fraction-weighted averages will be used to estimate liquid viscosities and surface tension. The oil viscosity at any other pressure below the bubble point is where If the stock tank oil viscosity is known. The reader should note that in the petroleum literature it has been common practice to use volume fraction-weighted average liquid properties in oil—water—gas flow calculations. If there is no slip between the oil and water phases.

Accounting for the Presence of Water When water is produced. Since the separator is at the reference condition of psig.

Solution The first step is to calculate Rs and Bo. The volumetric flow rates are [Equations and ] To calculate the oil density. The gas-formation volume factor. From Equations to Using the correlations presented in Section 3. From Figure it is found to be equal to 0. This calculation is shown explicitly in Chapter 4. The oil viscosity can be estimated with Equation through The liquid viscosity is then found from Equation Two-Phase Flow in a Reservoir Although a rigorous treatment of two-phase flow in a reservoir is outside the scope of this textbook.

The effective permeability values are related to the relative permeability values by simple expressions: Relative permeability values are laboratory-derived relationships.

If there are two or three fluids flowing at the same time in a porous medium. Pressure transient test-derived permeability values are far more reliable not only because of the reason outline above but also because they account for reservoir heterogeneities. The effective permeability values are.

Even the presence of a nonflowing phase. Figure is a schematic diagram of laboratory-derived oil and gas relative permeability data. Frequently relative permeability values are represented by a fit for laboratory data using Corey equations given by the following: Oil and gas relative permeability.

The rate equations developed in Chapter 2 for single-phase flow of oil must then be adjusted to reflect effective permeability values in the presence of gas.

The generalized expression for the flow of oil. For the calculation below bubble point. This is a significant reduction from the single-phase value.In reality this is only an approximation. Chapters 2—4 present the inflow performance for oil.

Being production engineer, you must be a person who knows everything about the production operation that is going on in this field. This book provides not only best practices but also the rationale for new activities. In the presence of large amounts of nonhydrocarbon gases.

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