reservoir and production fundamentals potx

00-TABLE OF CONTENTS.pdf

Cover
Foreword
TOC (3 pages)

01-INTRODUCTION

A) Conditions favorable for hydrocarbon reservoir formation
- Fig. 1-1. accumulation of oil and gas into a reservoir.
B) Oilfield units of measurement
- Table 1-1. Comparison of units used in the oilfield.
C) A brief description of SI oilfield units
- Table 1-2. SI base and suplementary units.
- Table 1-3. Si unit prefixes.
- Table 1-4. Examples of SI coherent derived units
- Table 1-5. Allowable SI units And conversations.

02-GEOLOGY & HIDROCARBONACCUMULATIONS

A) Introduction from "Handbook of Natural Gas Engineering".
B) Historical Geology
- Fig. 2-1. Geological time scale
C) Structure of the earth
- Fig. 2-2. Cross section the earth From Mears
- Fig. 2-3. Detail structure of crust from earthquake wave analysis From Mears.
- Fig. 2-4. Mechanism of tectonic plate movements From Mears "The Changing Earth"
- Fig. 2-5. Break-up of the Continents - From Scientific American
- Fig. 2-6. Erosion of mountains / transport / deposition of sediments
- Fig. 2-7. Sand particles - From Kuenen-Scientific American
D) Classification of rocks
- Fig. 2-8. Ingenious rock formation - From Mears
- Fig. 2-9. Sedimentary rock classification
- Fig. 2-10. Summary chart of general properties of some of the commonest rock-forming minerals - From Mears, the Changing Eart
- Fig. 2-11. Petrophysical properties of common sedimentary materials
E) The origin and habitat of oil
- Fig. 2-12. Sources of organic material From Clark - Elements of Petroleum Reservoirs.
- Fig. 2-13. Offlap process - beds formed by retreating sea of land emerging.
- Fig. 2-14. Onlap process-beds formed by advancing sea of submerging shoreline.
F) Hydrocarbon reservoirs
- Fig. 2-15. Dome structure. oil and gas migrate upward from source beds until trapped by the impermeable cap rock.
- Fig. 2-16 Oil an gas accumulation in an anticline
- Fig. 2-17. Hydrocarbon accumulation ossorted with a piercement salt dome
- Fig. 2-18 Trap formed by fault.
- Fig. 2-19. Oil and gas trapped under an uncomformity.
- Fig. 2-20. Upper bounds of the reservoir formed by change in permeability of a sand.
G) Sub-surface mapping
- Fig. 2-21. Sub-surface mapping.
H) Reservoir Temperature and Pressure
- Fig. 2-22. "Normal"pressure distribution from surface through a reservoir structure.
- Fig. 2-23. Estimation of formation temperature

03-RESERVOIR FLUID BEHAVIOR

A) Classification of oil and gas
- Fig. 3-1. Clasification and composition of reservoir hydrocarbons
  - Table 3-1. Composition of Natural Gases
  - Table 3-2. Analysis of Reservoir Oils Containing Disolved Gases
B) Phase behaviour of hydrocarbon fluids
- Fig. 3-2. Phase behaviour of a single-component hydrocarbon
- Fig. 3-3. Three-dimensional diagram of single-component system
- Fig. 3-4. Tyipical diagram of densities vs temperature in two-phase region (from Buricik)
- Fig. 3-5. Vapor pressure curves for two pure components and phase diagram for a 50:50 mixture of the same components.
- Fig. 3-6. Phase diagram of low shrinkage oil.
- Fig. 3-7. Operation of separator on well producing crude oil with dissolved natural gas
- Fig. 3-8. Phase diagram of retrograde condensate gas
- Fig. 3-9. Phase diagram of dry gas. (Elements of Petroleum Reservoirs.)
- Fig. 3-10. Phase diagram of wet gas. (Elements of Petroleum Reservoirs.)
C) Reservoir fluid properties
- 1) Source of fluids data
- 2) Compressibility of gases
  - Fig. 3-11. The compensibility factor for natural gases as a function of pseudoreduced pressure and temperature
    - Table 3-3. Computation of Pseudocritical temperature and Pressure of a Natural Gas.
  - Fig. 3-12. Pseudocritical properties of natural gases
- 3) Conversion factors between surface and downhole volumes
  - Fig. 3-13 Relationxhips between surface and downhole volumes dissolved gas system
  - a) Gas Formation Volume Factor, Bg
    - Fig. 3-14-(Chart Fg.1)
  - b) Formation volume Factor of oil, Bo
    - Fig. 3-15. Typical PVT data for differential vaporization of an undersaturated oil at constant temperature
    - Fig. 3-16-(Chart Fgo-1)
    - Fig. 3-18 Oil FVF
    - Fig. 3-19
  - c) Formation volume factor of water, Bw
    - Fig. 3-21. Formation volume factor of pure water and a mixture of natural gas and water.
- 4) Fluid density correlations
  - Fig. 3-22-(Chart Fg-5)
  - Fig. 3-24- (Chart Fw-1)
- 5) Viscosity correlations
  - Fig. 3-25-(Chart Fg-6)
  - Fig. 3-27. Water viscosity vs temp and concention of NaCl
  - Fig. 3-28. Pore compressibility - limestone
D) Rock pore-volume compensibility
- Fig. 3-29. Pore-volume compressibility - sandstone
E) Appendix - SCHLUMBERGER FLUID CONVERSION CHARTS
- Chart fg-1 GAS FORMATION VOLUME FACTOR
- Chart fg-2 PSEUDO-CRITICAL NATURAL GAS PARAMETERS
- Chart fg-3 NATURAL GAS DVIATION FACTOR
- Chart fg-4 GAS FORMATION VOLUME FACTOR (Nomograph)
- Chart fg-5 GAS DENSITY
- Chart fg-6 GAS VISCOSITY
- Chart fgo-1 BUBBLE-POINT PRESSURE
- Chart fgo-2 SOLUTION GOR CORRECTION FACTOR
- Chart fgo-3 FORMATION VOLUME FACTOR AT ph, OIL
- Chart fgo-4 FORMATION VOLUME FACTOR AT ph, OIL (Nomograph))
- Chart fgo-5 FORMATION VOLUME FACTOR, OIL
- Chart fgo-6 OIL DENSITY AT WELL CONDITIONS
- Chart fgo-7 OIL VISCOSITY
- Chart fgw-1 SOLUTION GAS-WATER RATIO
- Chart fw-1 DENSITIES OF NaCl SOLUTIONS
- Chart fw-2 WATER VISCOSITY

04-RESERVOIR ROCK PROPERTIES

A) Porosity
- Fig. 4-1. Irregular porosity
- Fig. 4-2. Range of matrix porosity and permeability of comercial inetest of conventional and factured -dual porosity systems.
B) Permeability
- Fig. 4-3 Definition of a Darcy
- Fig. 4-4. Effect of grain size on permeability.
- Fig. 4-5. Example illustrating effect of grain size on wetted surface.
- Fig. 4-6. High horizontal-low vertical permeability
C) Meassuremant of permeability
- Fig. 4-7. Laboratory apparatus for measurement of permeability
- Fig. 4-8 Permeability of core sample A to air at various pressures. (After Klinkerberg).
D) Measurement of porosity
- Fig. 4-9. RUSKA Universal porometer
E) Measurement of Capillary pressure by mercury injection

05-SURFACE TENSION WETTABILITY, CAPILLARITY, SATURATION & FLUID DISPLACEMENT

A) Surface tension
- Fig. 5-1. Apparent surface film caused by imbalance of molecular forces
- Fig. 5-2. Pressure in a bubble
- Fig. 5-3. Measurement of surface tension by ring method
B) Wettability
- Fig. 5-4. Contact angle as a measure of wettability
- Fig. 5-5. Contact angle as a measure of wetting
C) Capillarity
- Fig. 5-6. Capillary rise
- Fig. 5-7 Measurement of capillary pressure by depression of rise
- Fig. 5-8. Capillary pressure and radii of curvature of meniscus
D) Repartition of saturation in revoir rocks
- Fig. 5-9. Comparison of fluid rise in a capillary tube bundle of varying diameters illustrates the distribution of saturation
E) Irreducible water saturation
- Fig. 5-10. Shape of the capillary pressure vs. saturation curve.
- Fig. 5-11. Shape of capillary curve through the transition zone is strongly affected by the distribution of grain size.
F) Displacement pressure
- Fig. 5-12. Comparision of displacement from a capillary tube and granular packs.
G) Displacement of oil
- Fig. 5-13. Natural displacement of oil by water in a single pore channel.
- Fig. 5-14. Natural displacement of oil by gas in a single pore channel.
- Fig. 5-15. Gas displaces oil first from high permeablity pore channels. Residual oil occurs in lower permeability pore channe
- Fig. 5-16. Capillary forces cause water to move ahead faster in low permeability pore channel (A) when water is moving slow t
- Fig. 5-17. Capillary pressure gradient causes oil to move out and water to move into a dead-end pore channel when sand is wat
H) Residual oil
- Fig. 5-18. As thread of oil gets smaller, interfacial tension increases in the film at restricted Points A and B, where film
- Fig. 5-19 Water drive leaves residual oil in sand because surface films breal at restrictions in sand pore channels.
- Fig. 5-20. Pressure to displace bubble through a restriction.
I) Relations between permeablility and fluid saturations
J) Relative permeability -Saturation Correlations

06-RESERVOIR DRIVE MECHANISMS

A) Oil Reservoirs
B) Solution Gas Drive Reservoirs
- Fig. 6-1. Dissolved gas drive reservoir
- Fig. 6-2. Production data disolved gas drive reservoir.
C) Gas Cap Expansion Drive Reservoirs
- Fig. 6-3. Gas cap drive reservoir.
- Fig. 6-4. Production dat-gas cap drive reservoir.
D) Water Drive Reservoirs.
- Fig. 6-5. Water drive reservoir.
- Fig. 6-6. Production data-water drive reservoir.
- Fig. 6-7. Combination drive reservoir.
E) Discussion of recovery efficiency (including gravity drainage)
- Fig. 6-8. Reservoir pressure trends for reservoirs under various drives.
- Fig. 6-9. Reservoir gas-oil ratio trends for reservoirs under various drives.

07-WELL PERFORMANCE

A) Momenclature and Model for ideal cylindrical flow
- Fig. 7-1. Nomenclature for ideal cylindrical flow.
- Fig. 7-2. Pressure distribution is identical for different permeability zones.
B) Radius of drainage
- Fig. 7-3. Radius of drainage and boundaries in a rectangular reservoir.
- Fig. 7-4. Pressure distribution and drainage bundaries for wells producing at different rates.
C) Well pressure drawdown
D) Productivity index and specific productivity index
- Fig. 7-5. Pressure distributionwith and without formation damage.
E) Formation damage
- Fig. 7-6 Conditions causing formation damage.
- Fig. 7-7. Pressure distribution in a damaged fromation.
F) Formation inmprovement
- Fig. 7-8. Pressure through an improved formation
G) Skin factor
H) Skin damage in perforated completions
- Fig. 7-9. Pressure distribution showing "perforating skin"damage - uni -directional perforations.
I) Inflow production relation - IPR
- Fig. 7-10. Idealized and true IPR curves.
J) Evaluation of a fromation treatment with IPR
- Fig. 7-10. Idealized and true IPR curves.
K) Composite IPR of multi-zone completion
- Fig. 7-12 Composite for a stratified formation.
- Fig. 7-13. Electrical analugy of composite inflow performance.
L) Cross flow between zones
- Fig. 7-14. Cross between zones - well shut in.
M) Water cut vs. production rate
- Fig. 7-15 IPR water cut curves.
N) Performance of flowing oil wells.
- Fig. 7-16. Fluid configurations in various flow reigimes.
- Fig. 7-17. Chart to find energy loss factor, f.
- Fig. 7-18. Vertical lift performance.
- Fig. 7-19. Determination of optimum tubing size.
- Fig. 7-20. Tubing flow pressure distribution tables.
- Fig. 7-21. Two possible production rates for a given size of choke.
O) Simulators - the single well model
- Fig. 7-22. Electrical analogy of a flowing well.
- Fig. 7-23. Single well simulation radial grid.
- Fig. 7-24. Perforation geometry.
- Fig. 7-25 - Nomograph for estimation of productivity ratio.

08-RESERVOIR ESTIMATES

A) Volumetric methods
B) Calculation of the reserve
- Fig. 8-1. Osopacheous map - net thickness of pay - above oil water contact
- Fig. 8-2. Plot of depth vs. area contained within each contour.
C) Uncertainly in reservoir estimates
D) Field Integrated log and reservoir mapping services
- Fig. 8-3. Structural contour map superimposed over the posted map used.
- 1) Normalisation of data
  - Fig. 8-4. Pb, At and On histograms on three field wells.
- 2) Gridding and mapping
  - Fig. 8-5. Integrated log analysis and reservoir geometry flow diagram.
- 3) Monitoring fluid interfaces changes
E) Reservoir estimates - material balance mathods
- 1) Material balance-gas reservoirs
  - Fig. 8-6. Estimating initial gas in place.
  - Fig. 8-7. Effect of production rate on recovery with water influx.
- 2) Generalized material balance-oil reservoirs
  - Fig. 8-8. Combination drive reservoir illustrating volumetric balance method.
  - Fig. 8-9. water influx models.

09-WELL TESTING & PRESSURE TRANSIENT ANALYSIS

A) The DST (Drill sistem test)
- Fig 9-1. Typical DST tools for three types of testd. Upper assembly (left) is similar on all three test types.
- Fig. 9-2. Schematic of a DST chart.
- Fig. 9-3. Example of a three-cycle drillstem test.
B) LTD (long term production test) of oil wells.
- Fig. 9-4. Idealized diagrams of flow and pressure during an oil well test.
- Fig. 9-5. Results of a multiple rate test are presented as a plot of Pwf vs. gross liquid production rate.
C) Testing procedured for high capacity gas wells
- Fig. 9-6. Pressure and flow diagrams of a gas well back pressure test.
- Fig. 9-7. Plot showing results of a gas well back pressure test.
- Fig. 9-8. Preassure and flow diagrams of a modified isochronal test of a gas well.
- Fig. 9-10. Plot showing results of modified isochronal test data.
D) RFT - The wireline formulation tester
- Fig. 9-11. Schematic diagram and tool functioning.
E) Transient test techniques and analysis
- Fig. 9-12. Propagation of waves in a pond is analogous to propagation of s pressure wave through formation.
- Fig. 9-13. Idealized rate schedule and presure response for drawdon testing.
- Fig. 9-14. Semilog plot of pressure drawdown data for a well with wellbore storage and skin effect.
- Fig. 9-15. Idealized rate and pressure history for a pressure build-up test.
- Fig. 9-16. Horner plot of pressure build-up data showing effects of wellbore storage and skin.
F) Drawdown behaviour
- Fig. 9-17. Propagation of a pressure distrubance vs. log t.
- Fig. 9-18. Plots of well flowing pressure vs. time.
- Fig. 9-19. Plot of Pwf vs. t - different model reservoirs.
G) Pressure build-up analysis
- Fig. 9-20. Idealized flow rate and pressure vs. time, Cartesian coordenates.
- Fig. 9-21. The Honer plot.
- Fig. 9-22. MDH Interpretation method plot.
- Fig. 9-23. Dimensionless shut-in time.
H) Remarks concerninf the slope and shape of pressure drawn curves
- Fig. 9-22. Slope of drawndown curve in high and low kh formation
- Fig. 9-23. Reservoir boundary encountered after time t'.
- Fig. 9-24. Change in slope indicates change in kh after time t'.

10-FACTURED RESERVOIRS

A) Introduction
- Fig. 10-1. Comparison of matrix porosity and permeability of conventional and fractured reservoirs.
B) A phisical description of a fractured reservoir
- Fig. 10-2. fractures must be oriented in intersecting planes and extend throughout the reservoir for the reservoir to exhibit
- Fig. 10-3. Localized or mechanically induced factures do not achieve fractured reservoir performance.
C) A comparison of conventional and fractured reservoir performance
- Fig. 10-4. Comparison of pressure drawdowns for typical fractured and conventional reservoirs producing at equal rates.
- Fig. 10-5. Mechanism of gas segregation in a fractured reservoir
- Fig. 10-6. Gas-oil ratio and pressure trends for solution gas drive conventional and fractured reservoirs.
- Fig. 10-7. The transition zone in conventional and fractured reservoirs
- Fig. 10-8. Water-cut in the fractured and conventional reservoirs.
D) Idealized model of a fractured reservoir
- Fig. 10-9. An idealized model of a fractured reservoir.
- Fig. 10-10. Matrix block dimensions are determined by intersecting fracture planes.
E) Description of the fracture process
- Fig. 10-11. Frequency vs size of fracture openings.
- Fig. 10-12. Nomenclature for fracture orientation
F) Porosity and permeability
- 1) Determination of porosity
- 2) Permeabiliry determination
G) Production Mechanisms in the Factured Reservoir
- Fig. 10-13. Mechanisms of production in the fractured reservoir
- Fig. 10-14. Oil drainage from different height blocks by gravity mechanism
H) Discussion of Displacement Mechanisms
- Fig. 10-15. Imbibition mechanisms
I) Steady state flow towards the well
- Fig. 10-16. Steady state flow relations in the fractured reservoir.
J) Transient Flow
- 1) Warren and Root method
  - Fig. 10-17. Warren and Root drawdown plot.
- 2) Pollaird method
  - Fig. 10-18. Pollaird plot - log AP vs. t
K) Appendix to chapter 10

11-APPENDIX

A) Nomenclature
B) CONVERSION FACTORS BETWEEN PRACTICAL OILFIELD UNITS METRIC SI AND OTHER MEASURES
C) MISCELANEOUS OIL FIELD CONVERSIONS
D) Physical constants ans values