Литература по нефтяной
и газовой промышленности

Kermit E. Brown. The technology of artificial lift methods

Авторы:Kermit E. Brown

Название:The technology of artificial lift methods

Формат: PDF

Размер: 24,6 Mb

Год издания: 1977

 
Contents
 
Chapter1 Inflow performance
 
1.1 Introduction
 
1.2 Types of reservoirs
 
1.21 Solution gas drive
 
1.22 Water drive
 
1.23 Gas cap expansion drive
 
1.24 Summary
 
1.3 Inflow performance relationships
 
1.31 Introduction
 
1.32 Productivity index
 
1.321 Estimated productivity index
 
1.322 Productivity index change with time
 
1.33 Some early discussion on PI
 
1.34 Inflow performance curves
 
1.341 Introduction
 
1.342 Vogel’s work
 
1.343 Standing’s extension of Vogel's work to account for damaged or improved wells
 
1.344 Predicting future inflow performance curves
 
1.3441 Standing’s extension of Vogel’s work to predict IPR curves
 
1.3442 Practical solution for House Mountain field, Canada
 
1.3443 Another procedure for predicting Pis into the future
 
1.35 Isochronal and flow after flow testing of oil wells
 
1.351 Introduction
 
1.352 Gas well testing
 
1.3521 Flow after flow tests
 
1.3522 Isochronal tests
 
1.3523 Modified isochronal tests
 
1.3524 Conventional well test analysis
 
1.353 Testing of oil wells
 
1.354 Basic equations and pressure functions presented by Fetkovich
 
1.355 Total effective skin effect
 
1.3551 Introduction
 
1.3552 Skin effect, S"
 
1.3553 Rate and time-dependent skin, S(q,t)
 
1.3554 Non-Darcy flow effect, Dq
 
1.3555 Value of S
 
1.3556 Final equation
 
1.356 Change in performance curves with time or cumulative recovery
 
1.357 Example problems and field test results
 
1.3571 Isochronal and flow after flow tests
 
1.3572 Example problems on flow after flow and isochronal testing of oil wells
 
1.3573 Problems dealing with skin effect
 
1.3574 Problems dealing with future inflow performance curves
 
1.358 Conclusions
 
1.36 Comparison of methods for estimating and predicting inflow performance curves
 
1.361 Introduction
 
1.362 Weller's inflow performance relationship
 
1.363 Comparative evaluation of IPR curves
 
1.364 Prediction of future IPR curves
 
1.3641 Application of Fetkovich’s method to Vogel’s dimensionless IPR
 
1.3642 Application of Standing’s method to Fetkovich’s flow equation
 
1.3643 Discussion and comparison of results
 
1.365 Conclusions
 
1.370 Effect of watercut on IPR
 
1.371 Gilbert's discussion
 
1.372 Nind’s discussion
 
1.38 Shape of IPR curves for stratified formations
 
1.39 Suggested method for running a productivity index test
 
1.310 Summary
 
Chapter 2 Multiphase flow in pipes
 
2.1 Introduction
 
2.11 General history of multiphase flow
 
2.12 Uses of multiphase flow pressure loss calculations in petroleum engineering
 
2.13 Objectives of this chapter
 
2.2 Mathematical and physical bases for pressure loss calculations in multiphase flow
 
2.21 Conversions and dimensional analysis
 
2.211 Introduction
 
2.212 Units
 
2.213 Conversions
 
2.214 Determining dimensions of variables
 
2.215 Solving for conversion constants to make equations dimensionally correct
 
2.216 Determining dimensionless groups
 
2.2161 Stepwise procedure for use of Buckingham’s я-theorem
 
2.2162 Example problems making use of the tt theorem
 
2.22 Liquid properties
 
2.221 Liquid density
 
2.222 Compressibility
 
2.223 Viscosity
 
2.224 Surface tension
 
2.23 A brief review of gases as related to multiphase flow
 
2.231 Introduction
 
2.232 Gas properties
 
2.2321 Density
 
2.2322 Viscosity
 
2.2323 Compressibility
 
2.233 Gas problems related to multiphase flow
 
2.2331 Introduction
 
2.2332 Example problem on gas density
 
2.2333 Example problem on change in gas volume
 
2.2334 Example calculation, gas velocity in a pipe
 
2.24 Discussion of variables affecting pressure loss in multiphase flow
 
2.241 Volume factor for oil
 
2.242 Gas in solution
 
2.2421 Crude
 
2.2422 Water
 
2.243 Surface tension
 
2.244 Wall contact angle
 
2.245 Viscosity of multiphase flow mixture
 
2.25 Development of the general energy equation
 
2.251 Introduction
 
2.252 Discussion of variables in the equation”
 
2.253 Derivation of the equation
 
2.254 Discussion of the general energy equation
 
2.255 Application of equations to multiphase flow
 
2.2551 Holdup
 
2.2552 Liquid mixture properties
 
2.2553 Two-phase mixture properties
 
2.2553 Two-phase mixture properties
 
2.2554 Friction factors
 
2.2555 Calculation of pressure traverses
 
2.26 Single phase liquid flow
 
2.27 Single phase gas flow
 
2.271 Horizontal gas flow
 
2.272 Vertical gas flow
 
2.3 Vertical flow
 
2.31 Introduction
 
2.32 Historical development of vertical multiphase flow
 
2.33 Development and utilization of the best correlations in predicting pressure loss
 
2.331 Introduction
 
2.332 Limited correlations
 
2.3321 Introduction
 
2.3322 Poettmann and Carpenter method
 
2.3323 Faneher and Brown method (extension of Poettmann and Carpenter method)
 
2.3324 Method of Hagedorn and Brown to account for viscous effects (1V4 in. tubing) (extension of Poettmann and Carpenter method)
 
2.333 The four best correlations for vertical multiphase flow
 
2.3331 Introduction
 
2.3332 Generalized correlation of Hagedorn and Brown 113 2-3333 The Duns and Ros method
 
2.3334 Orkiszewski correlation
 
2.3335 Beggs and Brill correlation
 
2.34 Casing annular flow
 
2.341 Introduction
 
2.342 Cornish method
 
2.35 Heading phenomenon
 
2.351 Introduction
 
2.352 Literature review
 
2.353 Conclusions
 
2.36 Summary and evaluation of Correlations and their range of application
 
2.361 Introduction
 
2.362 Discussion of results
 
2.363 Conclusions
 
2.37 Practical application of vertical multiphase flow correlations
 
2.371 Introduction
 
2.372 Effect of variables
 
2.3721 Introduction
 
2.3722 Effect of tubing size
 
2.3723 Effect of flow rate
 
2.3724 Effect of gas-liquid ratio
 
2.3725 Effect of density
 
2.3726 Effect of water-oil ratio
 
2.3727 Effect of viscosity
 
2.3728 Effect of slippage
 
2.3729 Effect of surface tension
 
2.37210 Effect of kinetic energy
 
2.373 Preparation of working curves
 
2.3731 Introduction
 
2.374 Example problems
 
2.4 Horizontal flow
 
2.41 Introduction
 
2.42 Flow patterns
 
2.43 Liquid holdup
 
2.44 Historical development of horizontal multiphase flow
 
2.441 Introduction
 
2.442 Historical review of correlations
 
2.45 Utilization of best correlations in predicting pressure losses and determining line sizes
 
2.451 Introduction
 
2.452 Limited correlations
 
2.4521 The Lockhart and Martinelli correlation
 
2.4522 Baker’s correlation
 
2.4523 The correlation of Andrews, et al.
 
2.453 Best correlations for horizontal multiphase flow
 
2.4531 Introduction
 
2.4532 The correlation of Dukler, et al.
 
2.45321 Introduction
 
2.45322 Case I-Dukler
 
2.45323 Case ll-Dukler
 
2.4533 The correlation of Eaton, ef al.
 
2.45331 Introduction
 
2.45332 Energy-loss correlation of Eaton, ef al.
 
2.45333 Liquid holdup correlation of Eaton, ef al.
 
2.45334 Derivations, procedures, and example Problems for method of Eaton, ef al.
 
2.4534 The correlation of Beggs and Brill
 
2.45341 Procedures and example problems by the method of Beggs and Brill
 
2.46 The use of spheres in horizontal flow
 
2.47 Summaries of the best correlations and their range of application
 
2.471 Introduction
 
2.472 Summary
 
2.473 Conclusions
 
2.474 Recommendations
 
2.48 Practical application of horizontal multiphase flow
 
2.481 Introduction
 
2.482 Effect of variables
 
2.4821 Introduction
 
2 4822 Effect of line size
 
2.4823 Effect of flow rate
 
2.4824 Effect of gas-liquid ratio
 
2.4825 Effect of viscosity
 
2.4826 Effect of water-oil ratio
 
2.4827 Effect of other factors
 
2.483 Example problems
 
2.5 Inclined or hilly terrain multiphase flow
 
2.51 Introduction
 
2.52 Best correlations for inclined flow
 
2.521 Flanigan correlation
 
2.5211 Introduction
 
2.5212 Friction drop component
 
2.5213 Elevation pressure-drop component
 
2.522 Ovid Baker’s correlation
 
2.5221 Procedures and example problems
 
2.523 Beggs and Brill correlation
 
2.53 Limited correlations
 
2.531 Introduction
 
2.532 Brigham, Holstein and Huntington’s correlation
 
2.533 Rene Serigny’s correlation
 
2.5331 Serigny’s calculation procedure
 
2.534 Bonnecaze, Erskine, and Greskovich correlation
 
2.535 Singh and Griffith correlation
 
2.54 Conclusions and recommendations
 
2.55 Practical application
 
2.551 Example problems
 
2.6 Directional well multiphase flow
 
2.61 Introduction
 
2.62 Directional multiphase flow correlations
 
2.621 Introduction
 
2.622 General solution to the problem
 
2.623 Beggs and Brill correlation
 
2.624 Solution of Ney and Fuentes
 
2.625 Solution combining a vertical and horizontal multiphase flow correlation
 
2.6251 Solution procedure
 
2.6252 Problem examples and procedures for the directional well
 
2.626 Correlation of Cardozo
 
2.627 Summary and recommendations
 
2.628 Practical application of directional well multiphase flow correlations
 
2.7 Summary and conclusions
 
2.71 Introduction
 
2.72 Areas for further investigation
 
2.721 Directional wells
 
2.722 Inclined flow (hilly terrain)
 
2.723 Heading phenomenon
 
2.724 Emulsified flow
 
2.725 Viscosity effects
 
2.726 Slippage at low flow rates
 
2.727 Conclusions
 
Chapter 3 The flowing well including choke bean performance
 
3.1 Introduction
 
3.2 The overall flowing system
 
3.3 Methods of analysis
 
3.4 Irregular production
 
3.41 Heading phenomena
 
3.42 Irregular behavior of wells completed in stratified formations
 
3.43 Purging of wells
 
3.44 Summary
 
3.5 Flow of fluids through surface chokes, restrictions, and fittings
 
3.51 Introduction
 
3.52 Correlations for choke flow
 
3.521 Introduction
 
3.522 Single phase choke flow
 
3.523 Multiphase flow choke correlations
 
3.5231 Tangren, et al.
 
3.5232 Gilbert's approach
 
3.5233 Ros’ formula (Poettmann and Beck adaptation)
 
3.5234 Sheldon/Schuder approach
 
3.5235 Omana's correlation
 
3.5236 Achong s correlation
 
3.5237 Conclusions and recommendations
 
3.53 Flow of fluids through valves and fittings
 
3.531 Introduction
 
3.532 Equivalent length concept
 
3.533 Flow coefficient
 
3.534 Secondary flow in bends
 
3.535 Other resistances to flow
 
3.54 Summary
 
3.6 Wells flowing with no surface chokes (unrestricted production)
 
3.61 Introduction
 
3.62 Effect of variables
 
3.63 Method to predict rate possible from a flowing well (for no restrictions)
 
3.631 Introduction
 
3.632 Selection of tubing sizes for constant wellhead pressure
 
3.633 Determination of flow rates and selection of tubing sizes for wells with variable wellhead pressures
 
3.64 Effect of other variables including example problems
 
3.641 The effect of changing static pressure
 
3.642 The effect of water-cut on a flowing well
 
3.6421 Introduction
 
3.6422 Physical significance of water-cut

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  1. iussama:
    26 Apr 2018г. в 16:03

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