well completions stimulations (george king)

7/24/2019 Well Completions Stimulations (George King)

1/661

An Introduction

t o

the Basic5

I

of

Well C0mpletion5~

*

3

15,OOOpsi wellhead

working press ure

f o r

all

surface

5timulations

and Workovers

2nd

Edition

(Version 2.05)

Rubble Zone

Se t li ne r ha n ge r a t

10,800

ft.

wi th re ta rder

PBR s e t a t

12,300

ft.

Hot, High Fi-essure Ga s

I

George King


2/661

An Introd uc t ion to the Basics

of

Well

Complet ions, S

im

u la ions an

d

Workovers

2nd edit ion

(version 2.05)

George E. King

Cop yrig ht 1988-1998 by George

E.

King,

TuIsa, Oklahoma


3/661

Copyright

1988-1996

by

George

E.

King

Document may not be copied in any manner

Inquiries to:

4

George E. King

5555 S. 97 W.

Ave.

Sand Springs,

OK

74063

918) 446-7081

(918) 660-3226


4/661

Table of

Contents

Introd uction : Basic Well Com pletion Concepts

..................................................... 1-1

Porosity ....................................................................................................... 1-1

Saturation ................................................................................................... 1-2

Permeability

................................................................................................ 1-2

Relative Permeability

..................................................................................

1-2

Natural Fractures

........................................................................................

1-3

Reservoir Pressure

.....................................................................................

1-3

Pressures ................................................................................................... 1-4

Pressure Differential ................................................................................... 1-5

Well Temperature ....................................................................................... 1-5

Fluid Properties .......................................................................................... i-6

High Temperature and High Pressure Wells .............................................. 1-6

Introduction: Geology

................................................................................................. 11-1

Formation Sequences and Layering .......................................................... 11-4

Well Planning

............................................................................................................... 111-1

Drilling the Pay, Selecting the Interval and th e Init ial Design .......................... 1-1

Coiled Tubing Drilling

.......................................................................................

1-6

Underbalanced Drilling ....................................................................................

1-6

Slimholes

......................................................................................................... 1-7

Initial Completion Design ............................................................................... 1-7

Selecting the Pay Zone

.................................................................................... 1-7

References

-

Drilling

.................................................................................... 1-12

Other References

......................................................................................... 1-12

Casing Design

..............................................................................................................

2-1

Open Hole Completions

...........................................................................

2-1

Cased Hole Completions .......................................................................... 2-1

Description of Casing Strings ................................................................... 2-2

Casing Clearance

.....................................................................................

2-3

Connections

.............................................................................................. 2-5

Casing Weights and Grades ..................................................................... 2-6

Casing Design Safety Factors .................................................................. 2-7

Load Description ....................................................................................... 2-7

Casing String Design

..................................................................................... 2-14

API Equations

.........................................................................................

2-14

Buoyancy

................................................................................................

2-16

Example

2.1

............................................................................................

2-17

Collapse Design - Non-API Method

........................................................

2-18

Example2.2 - Single String Casing Design

............................................

2-22

Example 2.3 - Casing Design - Intermediate String

................................

2-26

Design a

9-5/8

ntermediate String

........................................................

2-26

Final Design

............................................................................................

2-30

High Pressure Gas ................................................................................. 2-30

Additional Graphical Illustrations ............................................................

2-30

Running The Casing ............................................................................... 2-30

Casing String Design- Deviated Wells .......................................................... 2-34

Liner Design ...................................................................................................

2-36

Example2.4 - Liner Design .................................................................... 2-36

Liner Tie-Backs .............................................................................................. 2-38

Cementing ..................................................................................................... 2-39

...

- 1 -


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Problems ........................................................................................................ 2-42

References .................................................................................................. 2-42

Other References ........................................................................................ 2-45

Casing Horizontal Wells .................................................................................

2-54

Reach Interval

.........................................................................................

2-54

Rotation and Torque ................................................................................ 2-55

The Build Interval ....................................................................................

2-55

Bending Stress ........................................................................................ 2-56

Vertical Interval ........................................................................................ 2-57

Application

............................................................................................... 2-58

Cementing ...................................................................................................................... 3-1

Cement Density ......................................................................................... 3-4

Factors Affecting Cement .......................................................................... 3-5

Cementing Design ............................................................................................ 3-6

Primary Cementing

...........................................................................................

3-6

Cementing Calculations .......................................................................... 3.14

Balanced Plug Setting .............................................................................

3.15

Squeeze Cementing

................................................................................ 3-16

Cement Squeeze Tools

...........................................................................

3-17

Liner Cementing

......................................................................................

3-18

Frictional Pressure Dropin Pipe

...............................................................

3-19

References .................................................................................................. 3-20

Cementing: Review Questions .................................................................... 3-23

Packer Selection and Tub ing Forces ...................................................................... 41

Production Packers ...................................................................................

4 1

Special Equipment

....................................................................................

4 1

Dressing Packers

......................................................................................

4-3

Allowing Tubing Movement ....................................................................... 4-3

Effects of Temperature .............................................................................. 4-4

Deep Completions .....................................................................................

4-5

Seal Considerations .................................................................................. 4-8

Seal Problems ........................................................................................... 49

Tubing and Packer Forces ........................................................................

4-9

Length or Force Changes? ......................................................................

4-13

Setting the Packer ................................................................................... 4-14

Combined Forces

.................................................................................... 4-16

Special Packers

.............................................................................................. 4-17

Tubing Stretch and Compression

............................................................

4-17

Problems

........................................................................................................

4-17

References .................................................................................................. 4-18

Well Heads, Chokes and

SSSVs ............................................................................... 5-1

Well heads

........................................................................................................ 5-1

Subsea Wellheads ............................................................................................ 5-3

Coiled Tubing Well Heads ................................................................................ 5-5

Hydrate Control in C oiled Tubing Completions

................................................ 5-5

Chokes .............................................................................................................

5-7

Subsurface Safety Valves ................................................................................ 5-8

Fluid

Loss ..................................................................................................

3-4

Application

.................................................................................................

37


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References ................................................................................................... 5-12

Corrosion and Erosion ...............................................................................................

6-1

Corrosion ......................................................................................................... 6-1

The Corrosion Circuit ................................................................................ 6-2

Chemical Reaction

...................................................................................

6-2

Acid Gases

...............................................................................................

6-4

Controlling Corrosion

................................................................................ 6-5

Materials for Sour Service

...................................................................... 6-10

CO2 Corrosion ........................................................................................ 6-11

Other Factors ...........................................................................................

6-1 2

Corrosion by Stimulation Acids ............................................................... 6-13

Destruction of Elastomers ...................................................................... 6-14

Microbial Corrosion

.................................................................................

6-14

Nonmetallic Tubulars

.............................................................................. 6-14

Predictive Techniques and Inspection Devices ...................................... 6-14

Erosion ........................................................................................................... 6-15

Corrosion References

..................................................................................

6-1

7

Inflow Perform ance, Tubin g Selection, and A rtificial Lift .................................. 7-1

Inflow Performance

................................................................................... 7-1

Tubing Design .......................................................................................... 7-2

Heading .................................................................................................... 7-8

Tubing Design

..........................................................................................-9

Artificial L ift

...............................................................................................

7-9

Rod Pump ...............................................................................................

7-1

0

Rod Pump ............................................................................................... 7-1 2

Gas Lift

...................................................................................................

7-1 6

Electrical Submersible Pump

.................................................................. 7-1 6

Other Systems ........................................................................................ 7-1 6

Li f t

Selection

...........................................................................................

7-1

6

Reservoir Fluid Classification ................................................................. 7-1 7

References

...................................................................................................

7-1 9

Special Co mpletions (Deviated, Thermal Mu ltiples, and Multi-Laterals)

.......

8-1

Deviated Completions ...................................................................................... 8-1

Descriptions

..............................................................................................

8-1

Horizontal Well Candidate Selection

...............................................................

8-2

Horizontal Completions Background ............................................................... 8-3

Path of the Horizontal Section

.........................................................................

8-7

Artificial Lift Options ......................................................................................... 8-8

Solids Control Techniques

...............................................................................

8-9

Fracturing ............................................................................................... 8-10

Increasing Reservoir Contact ........................................................................

8-12

Logging

...................................................................................................

8-13

Wellbore Stability .................................................................................... 8-15

Perforating

.............................................................................................. 8-1 7

CorrosionErosion ...................................................................................

8-1 8

Gravel Packs .......................................................................................... 8-19

Coning Control ........................................................................................ 8-19

Heading Problems ......................................................................................... 8-21

Multi-lateral Completions

...............................................................................

8-21


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Lateral Technology Levels

......................................................................

8.22

Candidate List

.................................................................................................

8.24

The candidate list for design is still forming but has the following considerations:

8-24

Thermal Completions

.....................................................................................

8.25

Steam Projects ........................................................................................ 8-25

Combustion Projects

...............................................................................

8-26

Alternate Heating Methods

......................................................................

8.26

Stimulation

............................................................................................... 8.26

Corrosion and Scale

................................................................................

8-27

Insulation ................................................................................................. 8-28

Tubular Design ........................................................................................ 8-28

Cementing Considerations ...................................................................... 8.30

Completions ............................................................................................ 8.3 1

Coalbed Methane W ells

.................................................................................

8-32

Multiple Completions

......................................................................................

8-35

Tubingless Completions

..........................................................................

8.36

Selection of a Completion

.......................................................................

8-38

Monobores .............................................................................................. 8-38

Coiled Tubing Completions ............................................................................ 8-40

References ..................................................................................................

8-42

Logging ........................................................................................................... 8-50

Productivity Estimates

.................................................................................... 8.53

Perforating ..................................................................................................................... 9.1

Temperature Effect

....................................................................................

9-6

Perforation Size .........................................................................................

9-6

Calculated Pressure Drop

....................................................................... 9-16

Partial Completion ...................................................................................

9-16

Underbalance Perforating

.......................................................................

9-17

Tubing Conveyed Perforating .................................................................. 9-19

Wireline Perforating ................................................................................. 9-21

Highly Deviated W ells

............................................................................. 9-22

Depth Control

.......................................................................................... 9.22

Cement Damage

.....................................................................................

9.23

Casing Damage ....................................................................................... 9-23

Stress in an Deviated Well

............................................................................. 8-50

Well Completion Problems ............................................................................. 8-52

Extreme Overbalance Perforating ........................................................... 9-19

Repetiora ing Considerations

..................................................................

9-24

Stimulation Considerations

......................................................................

9-25

Stimulations n Deviated Wells - Effect

of

Perfs ...................................... 9-26

A

brasiveErosive Perforating ...................................................................

9-26

Pipe Cutoff Methods ....................................................................................... 9-27

Questions ................................................................................................ 9-27

References - Perforating ..............................................................................

9-28

Formation Damage - Causes and Preventions ...................................................

10-1

Clays ............................................................................................................... 10-6

Common Types of Clay ........................................................................... 10-8

Water lmbibition

of

Clays

........................................................................

10-9

.

v .


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Clay Swelling ..........................................................................................

10-9

Clay Dispersion

......................................................................................

10-9

Other Clay Problems

............................................................................ 10-1

0

Paraffins and Asphaltenes

........................................................................... 10-1 1

Emulsions

....................................................................................................

10-13

Dispersions

..................................................................................................

10-15

Foams

.......................................................................................................... 10-16

Froth

............................................................................................................

10-16

Wettability Problems ....................................................................................

10-16

Hydrates ...................................................................................................... 10-1

7

Scales

.......................................................................................................... 10-18

Calcite

................................................................................................... 10-18

Calcium Sulfate ....................................................................................

10-19

Barium Sulfate ...................................................................................... 10-21

Strontium Sulfate .................................................................................. 10-2 1

Other Scales

.........................................................................................

10-22

Particulate Damage .....................................................................................

10-22

Drilling Mud

...........................................................................................

10-22

Cements ............................................................................................... 10-22

Kill Fluids .............................................................................................. 10-22

Dirty Water ............................................................................................ 10-22

Bacteria Problems ................................................................................ 1

0-22

Effects

of

Formation Damage on Production ...............................................

10-23

Rate and Skin .......................................................................................

10-23

Example 70.7 ........................................................................................

10-23

Example 70.2 ........................................................................................ 10-27

Example

70.3

........................................................................................

10-28

Using Production History Curves to Assess Damage ..................................

10-28

Example 70.4 ........................................................................................ 10-28

Workover Candidate Selection ....................................................................

10-29

Example 70.5

........................................................................................

10-29

Formation Damage - Questions ...................................................................

10-30

References

.................................................................................................

1

0-30

Formation and Damage Diagnos is ........................................................................

11-1

Drill Stem Test (DST) ................................................................................... 11-1

Nodal Analysis ...............................................................................................

11-4

Inflow Performance ...................................................................................... 11-5

Equations of Flow

...................................................................................

11-9

Decline Curves

............................................................................................ 11-1

5

System Pressures ........................................................................................

11-1

6

Fluid Analysis ............................................................................................. 11-18

Transient Tests

..........................................................................................

11-21

Reservoir Logging Methods ....................................................................... 11-28

Gamma Ray Logging ............................................................................ 1 1-28

Acoustic or Sonic Logging ....................................................................

11-28

Neutron Logging ...................................................................................

11-29

Density Logging ....................................................................................

1

1

29

Natural Gamma Ray Spectroscopy Log ............................................... 11-30

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Induced Gamma Ray Spectroscopy Log ............................................... 1 1-30

Depth of lnvasion

..................................................................................

1 1-35

Other Logs ............................................................................................. 1 1-36

Cased Hole Logging

..............................................................................

1

1-37

Electric Logg ing Tool Response ................................................................ 11-38

Direct Borehole Investigation ................................................................ 1 1-40

Formation Tester ...................................................................................

1 1-41

Fluid Movement Surveys ..............................................................................

1

1-42

Fluid Surveys

-

Formation ............................................................................ 11-43

Fluid Surveys

-

Wellbore .............................................................................. 1

1-43

Mapping ..................................................................................................... 11-47

Rock Mechanics Information From Logs

...................................................

11-51

Basic Logg ing Tool Response ................................................................... 11 55

Gamma Ray Logging

.................................................................................

'11-56

Neutron Logging ........................................................................................ 11-56

Density Logging ......................................................................................... 11-57

Natural Gam ma Ray Spectroscopy Log .................................................... 11-57

Induced Gamma Ray Spectroscopy Log

...................................................

11-57

References

................................................................................................

11-58

Chemical and Thermal Stimulation ........................................................................ 12-1

Example

12.1

..........................................................................................

12-2

Example 12.2 .......................................................................................... 12-2

Selecting a Candidate Well ............................................................................ 12-3

Evaluation

of

Stimulations

.............................................................................. 12-3

Selective Stimulation

...................................................................................... 12-4

Diverting vs.Fluid Loss Control .............................................................. .l2-4

Candidates

..............................................................................................

12-4

Diverter Operation

...................................................................................

12-5

Limited Entry (Pressure Differential Diverting) .......................................

.1

2-5

Mechanical Diverting ............................................................................... 12-6

Chemical Diverlers

................................................................................

12-1

lnterface Treatments

.............................................................................

12-1

Diverler/Fluid Loss Control Stages ........................................................ 12-1

HCVHF Treatment Diversion ................................................................. 12-1

Recommendations ................................................................................ 12-1 7

Packoff Techniques

...............................................................................

12-1

Technology of Bridging .......................................................................... 12-1

Depth

of

Diversion ................................................................................. 12-1

Chem ical Stimulation Techniques

................................................................ 12-1

Acidizing ................................................................................................ 12-1

Open-Hole Logging

...............................................................................

1 1-30

Noise Logging ....................................................................................... 1 1

-46

Borehole Surveys .................................................................................. 1 1-47

Completion and Lift Analysis ..................................................................... 11-50

Production and Operations Information

.....................................................

1

1-50

Mechanical Properties ........................................................................... 1 1-53

Acoustic or Son ic Logging

.........................................................................

11-56

Cleanup ................................................................................................. 12-1

HF Acid Spending Rates

..............................................................................

12-20

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10/661

Solvents ....................................................................................................... 12-21

Gases .......................................................................................................... 12-22

Surfactants

................................................................................................... 12-22

Reactants

.....................................................................................................

12-22

Treatment Types .......................................................................................... 12-22

Damage Removal ........................................................................................ 12-23

Reaction Rate Factors ................................................................................. 12-24

Temperature ......................................................................................... 12-24

Pressure

...............................................................................................

12-24

Area Volume Ratio

...............................................................................

12-24

Acid Concentration

...............................................................................

12-24

Acid Selection ....................................................................................... 12-24

Formation Composition ........................................................................ 12-25

Additives ...................................................................................................... 12-25

Surfactants ...........................................................................................

12-25

Weffability

.............................................................................................

12-26

Mutua l Solvents ....................................................................................

12-27

Wash Design ............................................................................................... 12-28

Wellbore Cleanup and Acid Wash ........................................................ 12-28

Solvent Wash of Injection Wells ........................................................... 12-28

Perforation Breakdown

......................................................................... 12-28

Extreme Overbalance Perforating ............................................................... 12-29

Matrix Acidizing Design

...............................................................................

12-29

Obtaining the Required Information ...................................................... 12-29

Designing the Treatment ...................................................................... 12-3 1

Thermal Stimulation

.....................................................................................

12-35

Chem ical Heat Generation

...................................................................

12-37

References ................................................................................................. 12-38

Granular Salt ........................................................................................

12-43

100-Mesh Sand .................................................................................... 12-43

Calcium Carbonate ............................................................................... 12-43

Naphthalene .........................................................................................

12-43

Benzoic Acid Flakes ............................................................................. 12-44

Wax Beads

........................................................................................... 12-44

Organic Resin Beads ............................................................................

12-44

Organic Resin Dispersions ................................................................... 12-44

Micron Size Patticulates ....................................................................... 12-44

Poiymers

...............................................................................................

12-45

Others

...................................................................................................

12-45

Fracturing ....................................................................................................................

13-1

Recovery by Fracturing

..................................................................................

13-1

Fracturing Economics .................................................................................... 13-2

Fracturing Length and Conductivity Decisions .............................................. 13-3

Fracture Design

...........................................................................................

13-15

Fracture Length and Width - Modeling

................................................. 13-1

5

Fracture Orientation and Formation Stresses ....................................... 13-16

Fluid Loss ............................................................................................. 13-1

7

Fracturing Design ................................................................................. 13-20


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Closure Stress

.......................................................................................

13-25

Fracture Treatments .............................................................................. 13-29

Fracture Treatment Design ................................................................... 13-29

When To Fracture

.................................................................................

13-33

Treatment Pressure Behavior ............................................................... 13-33

References

................................................................................................

13-34

Unstable Form ations and Sand Control

............................................................... 14-1

Sand Cementation .......................................................................................... 14-1

Formation Characterization ..................................................................... 14-2

Sand Movem ent Prediction

.....................................................................

14-4

Sand Control Considerations

................................................................

14-1 2

Sand Control ......................................................................................... 14-13

Alternate Gravel Sizing Methods ........................................................... 14-20

Mobility

of

Fines

................................................................................... 14-22

Sand Sorting Considerations ................................................................. 14-23

Benefits

of

Larger Gravel

......................................................................

14-24

Carrier Fluids

.........................................................................................

14-26

Equipment ............................................................................................. 14-28

Packing Methods ................................................................................... 14-29

Fluid Loss Control

................................................................................. 14-30

Alternate Path Gravel Packing

..............................................................

14-30

Pressure Drops Across G ravel Packs ................................................... 14-31

Example

................................................................................................ 14-32

Pack and Frac Technology

....................................................................

14-32

Reservoir Lamination and Well Deviation ............................................. 14-33

Other Unstable Formations

...................................................................

1

4-33

References

-

Gravel Pack .......................................................................... 14-34

Workovers

and

Fluids

...............................................................................................

15-1

Well Control

.............................................................................................

15-1

Example

15 .......................................................................................... 15-2

Example

15.2 ..........................................................................................

15-3

Example 15.3

..........................................................................................

15-3

Shut-In

.....................................................................................................

15-5

(Re)Gaining Control ................................................................................ 15-6

Example

15.4 ..........................................................................................

1 5 6

Pressure Effects .................................................................................... 15-1 1

Example

15.5

........................................................................................

15-14

Completion/Workover Fluids

................................................................. 15-1 6

Example

15.6

........................................................................................

15-1

8

Example 75.7

........................................................................................

15-19

Example 15.8

........................................................................................

15-20

Example 15.9 ........................................................................................ 15-20

Example

I5 I0 ......................................................................................

15-22

Before the Job W C

................................................................................ 15-26

Fluid Filtration

...............................................................................................

1527

Field Testing and Measurement of Clean ........................................... 15-32

Application

............................................................................................

.1 5-32

Kill String Completions

..........................................................................

15-33

Returning W ells to Operation

................................................................

15-33

Workover References

................................................................................

15-34

Current Gravel Pack Design Methods and Problem Identification ........14-21

Snubbing ...............................................................................................

15-1

4

. iii .


12/661

References o n Filtration ............................................................................. 15-35

High Tem perature, High Pressu re Completions ................................................. 16-1

Completions Operations

................................................................................. 16-2

Brines

............................................................................................................. 16-5

Stimulation

......................................................................................................

16-5

Formation Damage .........................................................................................

16-6

Well Design

.................................................................................................... 16-7

Completions Equipment ................................................................................. 16-7

Subsurface Safety Valves

..............................................................................

16-8

Annular Pressure Buildup

.............................................................................

16-1

References

................................................................................................

16-1 1

Water Produc tion Control

........................................................................................

17-1

Summary of Important Points

..................................................................

17-1

Sources

of

Water

.....................................................................................

17-1

Problem Definition - Reservoir

................................................................

17-2

Problem Definition

-

Near Wellbore

.........................................................

17-3

Coning

.....................................................................................................

17-3

Water Block ............................................................................................. 17-5

Problem Definition - Injection Well

..........................................................

17-6

Reservoir Description and Modeling Necessities

....................................

17-7

Treating Considerations .......................................................................... 17-7

Modification of Permeability

............................................................................ 17-7

Deep M odification - Permeab ility Reduction

...........................................

17-7

. .

Deep M odification - Increasing Permeability

...........................................

17-7

Shallow Modification - Permeability Reduction ........................................ 17-8

Shallow M odification - Increasing Permeability

.......................................

17-9

References

..................................................................................................

17-9

Wireline and Coiled Tubing Operations

................................................................

18-1

Wireline Operations

.................................................................................

18-1

Downhole Wireline Equipment ................................................................ 18-2

Pressure and Fluid Control

......................................................................

18-6

Special Services ...................................................................................... 18-9

Tools

for

Downhole Measurements ......................................................... 18-9

Coil Tubing O perations ................................................................................ 18-9

Chain Injector

........................................................................................ 1

8-1

Axial Load Capacity ............................................................................... 18-25

Depth Limitations ..........................................................................................

18-27

Buoyancy

...................................................................................................... 18-28

Tapered S trings

............................................................................................

18-30

Buckling ........................................................................................................ 18-31

Capacity and Displacement

.......................................................................... 18-31

Fluid Unloading in Casing .............................................................................

18-40

Friction Pressure

.......................................................................................... 18-42

Well Testing with Coiled Tubing ...................................................................

18-44

References ................................................................................................ 18-44

Additional References on Coiled Tubing ................................................... 18-46

Workover Fishin g .......................................................................................................

19-1

Location of Stuck Point ............................................................................ 19-6


13/661

References

.

ishing

....................................................................................

19-8

References

.

illing

.....................................................................................

19-8

Plug and A bandonm ent Procedures ..................................................................... 20-1

Legal Requirements ....................................................................................... 20-2

Setting Cement Plugs

.....................................................................................

20-2

Other Plugging Processes .............................................................................. 20-6

Milling

a Packer

....................................................................................... 20-7

References

-

Plug and Abandonment ..........................................................

20-7

Effects of Com pletion, Stimu lation and Workover A ctivities on Surface Facility

Operations .............................................................................................................. 21-1

Stimulation Flowbacks .................................................................................... 21-7

Testing the Backflow ...................................................................................... 21-7

Causes of Upsets .................................................................................... 21-7

Flowback Duration ........................................................................................ 21 -1 2

Treating the Returning Acid

..........................................................................

21-13

Treatment Choices

.......................................................................................

21-13

Oil Foams ..................................................................................................... 21-14

References

................................................................................................ 21

1

4

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14/661

Intro du ction: Basic Well Com pletion Con cepts

Porosity

Porosity is the fraction of the total volume of the rock that is pore (non rock) space or void and not

made of solid pieces of the formation.

It

will be filled with a gas, water or hydroca rbon

or

two or more

at the same time. Porosity will range from a high of 40-50% in some m arginally consolidated chalk for-

mations to a low of near zero in some of the evaporites (anhydrite). The average po rosity of producing

reservoirs ranges from about 5 1 5 % in limestones or dolomites, 10-25% in sandstones and over

30%

in many of the chalk formations. In most unconsolidated formation, poros ity depends upon the grain

size distribution; no t on the abso lute size of the grain itself. Po rosity can be in the order of 35-40%

if

all grains are close to the same size, but in most cases where

a

wide range of grain sizes are avail-

able, the porosity will be between 15-25%. Severe cases of formations with mixtures of large and very

small grains may have porosities less than 15%.

Lower porosities, such as 10% or less, are usua lly the result of chemical mod ification of the pore

structure, i.e., recementation, precipitation of additional minerals, or leaching and reprecipitation. In

some cases, the very consolidated sandstones with overgrowth of quartz m ay have porosities down to

near zero.

Geologists further subdivide po rosity into several descriptive classifications that he lp engineers

describe the flow of fluids through the formation and into the wellbore. The major classifications are

briefly described in the follow ing paragraphs.

1. Matrix porosity or intergranular porosity - the porosity between the grains of the formation.

2.

Vug porosity - porosity in the solution chambers that may range from a ten th of a millimeter to

voids larger than a basketball.

3.

Fracture porosity

-

the void space created within the walls of an open natural fracture.

4 .

Micro porosity - the voids between the clay platelets or particles. Although a large micro porosity

may exist, production of fluids from them is often difficult since the fluids are usually held by

strong cohesive forces.

The matrix porosity is referred to as the primary porosity and most other poros ities are secondary.

Usually, the pore space described by natural fractures and vugs are produced or swep t very early

(flush production) and their continuing use becomes as a conductive pa thway to the wellbore. Long

term production rate estimates are usually based upon the reserves in the matrix except in very large

fields where solution porosity (vugs) is very extensive.

Porosity values derived from neutron or sonic logs are usually used alone with other log inform ation

and well observations to es tablish whethe r a section of rock is pay. Although the use of porosity in

this manner is common, it can also be very m isleading. Obviously, porosity is not a stand along value

for establishing the quality of pay. Shales, for example, have porosities of 30%

or

more but lack the

conductive pathways (permeability) to make them economic except where fractured gas-rich shales

exist in massive sections.

The location and type of porosity has a great affect on the performance of a well. R elying totally on a

log derived porosity, especially in a carbonate, may provide unexpected low produc tion or may result

in missing productive intervals. The occurrence of lime muds, a low porosity deposit common within

limestones may isolate porosity an d result in much lower effective porosities than reported with a log.

Fossils, porosity within grains, and isolated vugs encased by grain overgrowths may also result in high

porosity readings without adding

to

the porosity of the reservoir. These porosity problem s are usually

only spotted with the aide of core exam inations.

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Lower porosity rocks (less than

10%)

may be pay in a few instances if microfractures exist at reservoir

conditions. The open microfractures serve as drainage paths for fluid flow from very low porosity but

extensive parts

of

the rock.

Saturat ion

The fraction of pore space containing w ater is called the water saturation and usually denoted by an

Sw.

The remaining fraction of the pore space that contains oil or gas is called hydrocarbon saturation

Sh.

The simple balance

sh = 1 -

Sw accounts for all of the pore space within a rock. In almost

every porous formation, there is at least a small amount of water saturation. Usua lly when the sedi-

ments were laid down, the matrix materials were dispersed in water.

A s

the hydrocarbon entered the

porous formation, water was displaced from many

of

the pores, although the displacement process is

not efficient enough to move all the water. This displacement process, whether it was oil displacing

water over geologic time, o r water displac ing oil during water drive or water flooding, results in a lower

saturation of the fluid being displaced. If a very large amount of the driving fluid is displaced, the quan-

tity of the initial fluid reaches a point, usually a few percent of the pore space, where it cannot be

reduced further. This level of fluid is the irreducible saturation of that fluid. Therefore , an irreducible

water saturation, S,,,, is the saturation o f water in the core that cannot be removed by m igration of

hydrocarbon. This water

or

oil,

Soil

may be trapped in the small pores, held by high capillary attraction,

or bound to clays as a surface layer or in the clay lattice.

Permeabi l i ty

Permeability, denoted by a lower case

k,

s a m easure of the conductance of the formation to flow of a

fluid. The h igher the permeability, the easier it is (takes less driving pressure) for a fluid to flow

through the rock matrix. The law was originally derived by a French engineer named dArcy to

account for the flow of water through sand filters. The original permeability concept used darcies as

a

unit of measurement, but most productive formations will be between

0.001

md

(1

md =

0.001

darcy)

and

1000

millidarcies

(1

darcy). Permeability depends on the absolute grain size of the rock, how well

the sediments are sorted, presence of fractures, and how much chemical modification has occurred in

the matrix. Flowing and bound fluid properties also affect the permeability. Large-grained sediments

with a minimum of fine particles (large, open pores) usually have high permeabilities whereas very

fine-grained sediments with small pores have lower permeabilities. Porosity does not always relate

directly to permeability. Materials such as shales and some chalks may have very high porosities but

low permeability because of lack of effective connection of the pores.

Permeability to

oil,

water and gas m ay b e different because of viscosity differences and other influ-

ences such as wetting and the issue of the thickness of the liquid coating on the pore wall. Oil wet for-

mations are usually thought to be less permeable to the flow of water than water wet formations

because the molecular thickness of the oil coating is thicker than that of water. This leaves less pore

space for fluids flow. When m ore than one phase exists in the pore, relative permeability relationships

govern the flow.

Relat ive Permeabil i ty

The effects of relative permeability explain many of the problems involved in formation damage and

reduction of flow from a formation, either on initial production

or

after treating with a material which

severely oil wets the formation.

As

will b e pointed out in the chapter on formation damage, problems

with relative permeability include a significant drop in permeability to the saturating fluid as trace

amounts of a second, immiscible phase are introduced in the flowing liquid. Reductions of up to

80%

of

initial permeability are common when saturation of an immiscible phase is increased from zero to

approximately

20

or

25%.

It is this significant reduction in permeability that explains m uch

of

the dam-

age behind overtreatmen t with an oil-filming chemical, such as an oil-based drilling m ud, or the use of

highly absorptive surfactants

or

solvents. The surface of the rock also plays an important part since

the charge of a surfactant controls the attraction to a particular formation face. It must be remembered

that severe we ttability problems such as the absorption of cationic m aterials onto sandstones and the

absorption of anionic materials onto limestones can play a significant role in permeability reduction.

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16/661

The reduction from this coating or wetting may be severe and can be long-lasting, depending on the

tenacity of the coating.

Matrix cleanup of this type of wetting is imperative to fully restore the flow capacity of the forma tion.

Cleanup of this type of dam age mus t take into account both the stripping of the relative permeability

influencing layer and the type of rock surface to which it is adsorbed.

Natural Fractures

Natural fractures are breaks in the fabric of the rock caused by a wide variety of earth forces. These

natural fractures may have widths of a few thousandths of an inch to a tenth of an inch or more. Natu-

ral fractures generally h ave a common direction that corresponds to forces generated by a significant

geologic event in the area such as folding, faulting, or tectonic forces. Where solution etching

or

cementation forces are active, the fractures may be widened into extens ive vugs with perm eabilities of

hundreds of darcies or filled completely with precipitated mine rals. Stylolites or gouge filled frac tures

are examples of these behaviors. Na tural fractures influence flush production or high initial production

rate that diminishes quickly after bringing on a new well

or

the start of flow in a well that has been

shut-in. Although they serve as conductive pathways for oil or gas production, they also will transmit

water at a much faster ra te than the formation matrix, leading to early breakth rough of water or other

type floods and sweep problems in reservoir engineering.

Reservoir Pressu re

The pressure that the reservo ir fluids exert on the well at the pay zone is the reservoir pressu re. In sin-

gle pay completions with little or no rat hole (extra hole below the pay), the reservoir pressu re is the

bottom hole pressure,

BHP.

The initial reservoir pressure is the pressure at the time of discovery.

Flowing bottom hole pressure is pressure exerted as the result of a drawdo wn (differential pressure

produced by flowing the well). Shut-in pressure is the stable pressure reached after the well has b een

shut in long enough to co me to equilibrium. Shut-in pressures are often quoted as a function of time.

The initial pressure is usually a function of depth of burial but may be modified by other forces at the

time of burial or at a later time. Driving pressure may be supplied by a number of mechanisms

depending upon the characteristics of the oil and the surrounding geologic and physical forces. The

genera l types of reservoir drive forces (to the limit of general interest in well completions) are:

1.

Solution gas drive - a volumetric displacement where all the driving energy or pressure is sup-

plied by gas expans ion as the pressure is reduced and the gas comes out of solution. In reser-

voirs above the bubble point, all the gas is dissolved in the oil and there is no free gas. In these

reservoirs, there may b e a volume change

of

the oil as the pressure drops and gas breaks out

of

solution. Reservo ir pressure decrease s with fluid withdrawals.

2. Gas Cap

-

a volumetric displacemen t where the oil is below the bubb le point, i.e., there is free

gas or gas saturation in the pores and there may be a gas cap. Reservo ir pressure dec reases

with fluid withdrawals.

3.

Water drive -water influx into the reservoir from edge, bottom or water injection wells can pro-

vide very consistent drive p ressure to a reservoir. Like the oil, the water m oves through the most

permeable pathways of the formation towards the pressure drop produced by rem oval of fluids.

The water pushes part of the oil in front, entering some of the pores and displacing the oil. Oil

production continues long after the breakthrough

of

water at the producing well since the forma-

tion may contain a number of streaks that have permeability differences an order of magnitude

or more. R eservoir pressure may rem ain the same or drop with fluid withdrawals, depending

upon how fast the incoming water replaces the withdrawn fluids.

4. Reservoir compression through com paction in poorly consolidated, high porosity reservoirs is

also a method of supp lying driving energy but it usually generates serious problems in the res-

ervoir. In these reservoirs, which may o ften be initially over pressu red, the reservoir fluids are a

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overbu rden load supporting element. W ithdrawal of the fluids requires the m atrix of the formation

to support more of the load from the overlying sediments (overburden). In some poorly consoli-

dated or weak formations, the matrix compresses under the load, leading to lower porosity and a

continued pressure on the remaining fluids. Although this is a definite form of pressure mainte-

nance, when the porosity is decreased, the permea bility also is reduced. Compaction of the p ay

in massive sections may also lead to subsidence of several feet at the surface

--

a critical prob-

lem for some offshore rigs and se a level land fields.

5. Pressure ma intenance or sweep projects using water or gas are our methods of increasing

recovery. These processes come with m any of the same advantages and limitations as their nat-

ural counterparts.

Pressures

To a workove r engineer, pressure can be a powerful tool or a nightmare. The difference is in how pres-

sure control is handled. The following "sho rt list" of pressures and pressure related terms p resents an

idea of what and how pressures are important to the workover.

1.

Reservoir Pore Pressure

-

The pressure of the reservoir fluids, often expressed as a gradient in

psilft. The initial reservoir pressure is the pressure at the time of discovery. Fluid withdrawals

from a reservoir are made by lowering the pressure in the wellbore. The flow of fluids toward the

low pressure creates zones of lower pressure or pressure gradien ts extending into the reservoir.

The reservoir pressure can only be measured at the wellbore in a new well or in a well that has

experienced comp lete buildup.

2.

Flowing Bottom Hole Pressure -T hi s pressure is measured at the productive zone during flow.

A

value of flowing bo ttom hole pressure is usually reported with a flow rate or a choke se tting.

A

change i n the flow rate will change the flowing bottom hole pressure.

3. Drawdown

-

Drawdown is the pressure d ifferential set by the difference of the reservoir pressure

and the flowing bottom hole pressure.

4.

Flowing Tubing Pressure

-

A surface m easurement of the pressure in the tubing, prior to the

choke, at a particular flow rate. It is equal to the flowing bottom hole pressure minus the hydro-

static pressure exerted by the fluids in the tubing. Because of entrained gas production and gas

breakout as the well is produced, it is rarely possible

on

iquid/gas producers to accurately calcu-

late the flowing bottom hole pressure from the flowing wellhead pressure. Only when the compo-

sition of the fluid in the tubing is known can the down hole pressure be calculated.

5. Shut-in Surface Pressure

-

Any pressure measured at the surface immediately after a w ell is

shut-in will change as bottom hole p ressure builds up toward reservoir pressure and the fluids in

the tubing come to an equilibrium. S urface measured shut-in pressures are useful in some b uild-

up tests to assess the productivity of a well.

6.

Productivity Index

-

The productivity index is a measurement of well flow potential. It is a term

generated from a delivery plot of flow rate and pressure from a particular well. It is comm only

expressed as a potential flow rate per pressure drop such as barrels per day per psi. By multiply-

ing the P I by the intended drawdown, a flow rate of the well can be predicted. The PI is estab-

lished by test on the well. It changes with time.

7. Fracture Breakdown Pressure - A measurement of what pressure is required to hydraulically

fracture the rock. The breakdown pressure is usually attained from drilling data, breakdown

tests, or fracture stimulations. It is usually expressed as a gradient of pressure per unit of forma-

tion depth such as psi/ft.

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8. Fracture Extension Pressure -T h e pressure necessary to extend the fracture after initiation. Like

fracture breakdown pressure, it is relevan t to a particular well or field.

9. Friction Pressure - When fluids are flowed at h igh rates through a conduit, there

is

a resistance

to flow caused, at least partly, by friction

of

the fluids at the boundaries of the conduit and by tur-

bulence (mixing) of the fluids. Whether the con duit is pipe

or

a fracture, friction represen ts a

back pressure. Friction is expressed as pressure at a rate for a unit length of a particular conduit.

10. Bubble Point Pressure - In a reservoir that contains an undersaturated oil, there will be no gas

cap. As the pressure

is

drawn down, the solution gas will break out of solution. Because of rela-

tive permeability and saturation concerns , the occurrence of reaching the bubble point usually

coincides with a drop in production.

Pressure Differential

Pressure differential

is

probably the m ost important pressure during drilling, completion, workover and

production. The differential pressure between the wellbore and the formation dictates which direction

fluids will move and at what rate they will move. Additional controls such as reservoir permeability and

native and injected fluid viscosity also have an affect, as does the presence of solids in the wellbore

fluid when the pressure differential is toward the form ation.

In general, drilling pressure differential should b e as low as possible to m inimize formation damage

and the amoun t of fluid invasion from wellbore fluids. However, during any drilling, comp letion or work-

over operation, the pressure differential m ust be toward the wellbore (higher pressure in the wellbore

than in the reservoir) when well flow is not wanted. M aintaining pressure differential is the same as

ma intaining well control. Ce rtain conditions, such as intentional or accidental swabbing caused by

swab cups or large-diam eter tools, can create low pressures at the bottomhole, even with a column of

high pressure fluid above the swab or tool. It is the rate of movement and the diameter difference

between the objec t in the h ole and the inside of the hole itself that determ ine the sw ab or underbal-

ance loads. Each step of a drilling, comp letion or workover operation, particularly when tools or equip-

ment are removed from the hole, should b e examined to determine

if

swab loads can unbalance the

pressure differential and sw ab fluids into the wellbore.

During production, pressure differential towa rd the we llbore is essential for fluid flow. Colum ns of

standing liquids, excessive backpressures or large amounts of solids in the fluids in the wellbore will

act as a check valve, severely limiting produc tion flow into the well.

The study of pressu re differential and p ressure drop is commonly done us ing a nodal analysis pro-

gram. These programs compute pressure drops and backpressures

on

a system, and help identify

those points that may be bottlenecks to good production practices. There are many instances of wells,

some even with large-diameter tubing where the tubing has been found to b e a choke on the produc-

tion from the well. Changing out the tubing to a larger size in many cases has doubled production from

a h igh capacity well.

Well Temperature

The reservoir at static conditions has a shut-in or rese rvoir tempe rature that is characteristic of the

depth times the geothermal gradient for that area. A 13,000

ft

deep rese rvoir in one part of the world

may have a bottom hole temperature of 16OoF, while a similar depth reservoir in a hotter geothe rmal

area may be 360F.

As the well flows, the bottom h ole temperature will drop depen ding on the type and am ount of gas and

the pressure drop. The cooling is produced by the expansion of gas. Temperature reductions low

enough to freeze water may form ice or hydrates in some gas wells while wells with a smaller ratio

of

gas to liquids will flow hot to surface .

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19/661

Fluid Properties

The composition of the fluid in the formation, at various points in the tubing and at the surface have

major affects on the performance of he well and the selection

of

production equipment. The following

terms are required know ledge to describe the fluid a nd their changing nature.

1.

2.

3.

4.

5.

6.

Gas-oil-ratio,

GOR,

the amount of free gas associated with the oil production. The gas may ordi-

narily be in solution or free gas as in a reservo ir with a gas cap. When the gas volum e is

expressed as a function of the total liquids, the value is the gas-liquid-ratio, GLR. Wells with

GLRs above 8000 are considered gas wells, while those with a

GOR

less than 2000 are labeled

oil wells. The wells in between 2000 and 8000 are combination wells. The actual GOR value is

usually m easured at the surface, its value downhole changes with pressure.

Water-oil-ratio, WOR, is the am ount of water being produced in ratio to the oil production.

Bubble point refers to the p ressure that a free gas phase will form in an undersaturated oil. The

significance is the addition of another phase that, most likely, will lower the relative permeability.

Dew point is the pressure and temperature at which the light hydrocarbon gases, Cs-C,, begin

to

condense into a liquid. The addition of anothe r phase will lower relative permeability.

Cloud point is the temperature in an oil system where paraffin crystals appear (cj8+ fraction

begins to solidify).

Pour point is the temperature below which the o il will

no

longer pour.

High

Temperature

and High

Pressure Wells

Wells with pressures over 0.6 psi/ft and temperatures over 300F are often referred to as HTHP wells

or high temperature, high pressure wells. These wells account for less than

1%

of the total wells

drilled, but may cost

5%

or more of the total expenditures for drilling and completions. The risk, reward

and cost can a ll be very great in these types of wells. Very special workover and completion opera-

tions are necessary to adequately complete and produce these wells.

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Introductions

Geology

The geologic understanding of the pay and the surround ing formations plays an important part in the

design of well comp letions and stimulations. The b rief introduction given here will only give a glimpse

of the sub ject ma tter in the field. Th is treatment of geo logy is very simplistic; reference articles and

books are available for every segment.

The type of formation, composition, strength, logging basics, leakoff sites and other parameters may

be available from a detailed geolog ic investigation. This information is useful for pay zone identifica-

tion, fluid and additive selection, longevity of fluid contact, and selecting casing points.

There are several major classifications of rocks of interest to the petroleum industry: sandstones, car-

bonates (limestone and dolomite) evaporites, and shales are only the major groups. Several others,

such

as

mudstones, siltstones and washes, are subd ivisions of the major classifications.

Sandstones are predominately silicon dioxide and may have various amounts of clay, pyrite, calcite,

dolomite or other materials in concentrations from less than

1

%

to over

50%.

Sandstone formations

are generally noted for being a collection of grains. The grain size may range from ve ry small, silt

sized particles (5 microns) to pea size or larger. The grains fit together to form a matrix that has (hope-

fully) some void space between the particles in which oil or other fluids may accumulate. The grains

are usually held together by a cem ent that may be clay, silica, calcite, dolomite, or pyrite. Som e

cementation of the grains is critical for forma tion strength; however, excess cementation reduces

porosity and permeability.

Sands are deposited in a variety of depositional environments that determine the in itial sedimentkock

properties. The depositional env ironmen t is simply what type of surroundings and forces shaped the

deposits. In the following descriptions of depositional environment, the energy level is labeled as

either high or low depending upon the leve l of force that accom panied the deposition of the sediments.

High energy deposits are those with sufficient wind or current to move large pieces of debris while low

energy is sufficient to m ove only the smaller particles. The importance of energy is described later.

Common depositional environments are:

1.

2.

3.

4.

5.

Deltas

-

These m outh of river deposits provide some of the larger sandstone deposits. Because

of the enormous amount of natural organic material swept down the river systems , the deltas are

also rich in hydrocarbons. Quality of the reservoir rock deposits may vary widely because of the

wide variations in the ene rgy level of the systems.

Lagoonal deposits - May be regiona lly extensive along the shores of ancient seas. Lagoonal

deposits are low energy deposits that are hydrocarbon rich. Permeability may vary w ith the

energy and amount of silt.

Stream beds - A moderate to low energy deposit with some streaks of high energy along the fast

flowing parts of the stream s. Stream beds are known to wander extensively and chasing these

deposits with wells requires very good geologic interpretation, plus a lot of luck. The deposit vol-

umes are also lim ited and frequently deplete quickly.

Deep m arine chalks

-

These are often the most massive deposits available, built up at the bot-

tom of ancient seas by the death of millions of generations of plankton-sized, ca lcium fixing

organisms. They can be very consistent, thick deposits. Natura l fracturing is common.

Reefs

-

These forma tions were built in the same manner as the reefs of today, by animals that

take calcium from the sea water and secrete ha rd structures. Because of the cavities rem aining

from the once living organisms, reefs that have not undergone extensive chemical mod ification

are among the m ost permeable of the carbonate deposits.

ii-1


21/661

6.

Dunes - The effects of desert winds on the sands have a shaping effect that can be seen in the

arrangement of the grains. These deposits may be m assive but are usually lower energy. Perme-

ability may vary considerably from top to bottom.

7. Alluvial fan

-

Zones of heavy water run-off such as from mountains are extremely high energy

runoffs. Common constituents of these formations may range from pebbles to boulders and

cementation may be very weak. Formations such as the g ranite washes are in this classification.

8. Flood plains - Occur along lower energy rivers and form during flood stages when the rivers

overflow the banks and spill into adjacen t low areas. Flood plain deposits are mostly silt and

mud.

The level of energy with each type of deposit can b e visualized by their modern depositional counter-

parts. The importance of energy is in the sorting of the gra ins and the average size of the grains . As

seen in the description

of

permeability in the p receding section, a rock with larger grains and the

absence of very small grains leads to high permeability. When small grains are present, the perme-

ability is m uch lower. When there is a mixture of the very large and very small grains, such as in some

alluvial fans, the p ermeability can be very low. The exten t of grain differences in a forma tion is terme d

the sorting, with well sorted formations having similar sized grains and poorly sorted forma tions

showing a very wide size range.

The events that happen after the deposit is laid down are also factors in well completions and may

have a devasta ting effect on reservoir engineering. Som e of these forces are active for a short period

in geologic time such as faulting and salt domes, and others like salt flows and subsidence, are active

during the productive life of the well. The faulting, folding and salt movement make some reservoirs

difficult to follow. Continuo us forces are often responsible for formation creep in open holes, spalling,

and casing sticking a nd collapse problems. A lthough these geologic movement factors cannot be eas-

ily controlled, the well comp letion operations can be modified to account for many of them, if he prob-

lems are co rrectly identified early in the p roject life.

Chem ical modifications also influence the rese rvoirs, though m uch less drastically than the uplift

forces of a salt dome, for example. Most carbonates (not including the reefs) are laid down by accu-

mulation of calcium carbona te particles. Limes tone may recrystallize or convert to dolomite by the

addition of magnesium. Be cause the limestone is soluble in ground water and very stable (resistant to

collapse), the l

well completions stimulations (george king)

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