DRILLING FLUIDS PROCESSING HANDBOOK free download

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CONTENTS
Biographies xvii
Preface xxiii
1 Historical Perspective and Introduction 1
1.1 Scope 1
1.2 Purpose 1
1.3 Introduction 2
1.4 Historical Perspective 4
1.5 Comments 11
1.6 Waste Management 13
2 Drilling Fluids 15
2.1 Drilling Fluid Systems 15
2.1.1 Functions of Drilling Fluids 15
2.1.2 Types of Drilling Fluids 16
2.1.3 Drilling Fluid Selection 17
2.1.4 Separation of Drilled Solids from Drilling Fluids 20
2.2 Characterization of Solids in Drilling Fluids 25
2.2.1 Nature of Drilled Solids and Solid Additives 25
2.2.2 Physical Properties of Solids in Drilling Fluids 26
2.3 Properties of Drilling Fluids 31
2.3.1 Rheology 32
2.4 Hole Cleaning 38
2.4.1 Detection of Hole-Cleaning Problems 38
2.4.2 Drilling Elements That Affect Hole Cleaning 40
2.4.3 Filtration 45
2.4.4 Rate of Penetration 47
2.4.5 Shale Inhibition Potential/Wetting Characteristics 51
2.4.6 Lubricity 52
2.4.7 Corrosivity 53
2.4.8 Drilling-Fluid Stability and Maintenance 54

2.5 Drilling Fluid Products 54
2.5.1 Colloidal and Fine Solids 54
2.5.2 Macropolymers 55
2.5.3 Conventional Polymers 56
2.5.4 Surface-Active Materials 57
2.6 Health, Safety, and Environment and Waste Management 58
2.6.1 Handling Drilling Fluid Products and Cuttings 58
2.6.2 Drilling Fluid Product Compatibility and Storage
Guidelines 58
2.6.3 Waste Management and Disposal 62
References 66
3 Solids Calculation 69
3.1 Procedure for a More Accurate Low-Gravity Solids
Determination 70
3.1.1 Sample Calculation 73
3.2 Determination of Volume Percentage of Low-Gravity Solids
in Water-Based Drilling Fluid 77
3.3 Rig-Site Determination of Specific Gravity of Drilled
Solids 78
4 Cut Points 81
4.1 How to Determine Cut Point Curves 85
4.2 Cut Point Data: Shale Shaker Example 90
5 Tank Arrangement 93
5.1 Active System 94
5.1.1 Suction and Testing Section 94
5.1.2 Additions Section 95
5.1.3 Removal Section 95
5.1.4 Piping and Equipment Arrangement 96
5.1.5 Equalization 98
5.1.6 Surface Tanks 99
5.1.7 Sand Traps 100
5.1.8 Degasser Suction and Discharge Pit 102
5.1.9 Desander Suction and Discharge Pits 102
5.1.10 Desilter Suction and Discharge Pits (Mud Cleaner/
Conditioner) 103
5.1.11 Centrifuge Suction and Discharge Pits 103
5.2 Auxiliary Tank System 104
5.2.1 Trip Tank 104
5.3 Slug Tank 105
5.4 Reserve Tank(s) 105

Scalping Shakers and Gumbo Removal 107
7 Shale Shakers 111
7.1 How a Shale Shaker Screens Fluid 113
7.2 Shaker Description 116
7.3 Shale Shaker Limits 118
7.3.1 Fluid Rheological Properties 119
7.3.2 Fluid Surface Tension 120
7.3.3 Wire Wettability 120
7.3.4 Fluid Density 120
7.3.5 Solids: Type, Size, and Shape 120
7.3.6 Quantity of Solids 121
7.3.7 Hole Cleaning 121
7.4 Shaker Development Summary 121
7.5 Shale Shaker Design 122
7.5.1 Shape of Motion 123
7.5.2 Vibrating Systems 133
7.5.3 Screen Deck Design 134
7.5.4 g Factor 136
7.5.5 Power Systems 140
7.6 Selection of Shale Shakers 143
7.6.1 Selection of Shaker Screens 145
7.6.2 Cost of Removing Drilled Solids 145
7.6.3 Specific Factors 146
7.7 Cascade Systems 148
7.7.1 Separate Unit 150
7.7.2 Integral Unit with Multiple Vibratory Motions 150
7.7.3 Integral Unit with a Single Vibratory Motion 152
7.7.4 Cascade Systems Summary 152
7.8 Dryer Shakers 153
7.9 Shaker User’s Guide 154
7.9.1 Installation 155
7.9.2 Operation 156
7.9.3 Maintenance 157
7.9.4 Operating Guidelines 158
7.10 Screen Cloths 159
7.10.1 Common Screen Cloth Weaves 160
7.10.2 Revised API Designation System 167
7.10.3 Screen Identification 174
7.11 Factors Affecting Percentage-Separated Curves 174
7.11.1 Screen Blinding 176
7.11.2 Materials of Construction 177
7.11.3 Screen Panels 178

13.3.5 Running Centrifuges in Series 318
13.3.6 Centrifuging Drilling Fluids with Costly Liquid
Phases 320
13.3.7 Flocculation Units 320
13.3.8 Centrifuging Hydrocyclone Underflows 321
13.3.9 Operating Reminders 321
13.3.10 Miscellaneous 321
13.4 Rotary Mud Separator 321
13.4.1 Problem 1 322
13.5 Solutions to the Questions in Problem 1 324
13.5.1 Question 1 324
13.5.2 Question 2 324
13.5.3 Question 3 324
13.5.4 Question 4 325
13.5.5 Question 5 325
13.5.6 Question 6 325
13.5.7 Question 7 325
13.5.8 Question 8 325
13.5.9 Question 9 326
13.5.10 Question 10 326
14 Use of the Capture Equation to Evaluate the Performance
of Mechanical Separation Equipment Used to Process
Drilling Fluids 327
14.1 Procedure 330
14.1.1 Collecting Data for the Capture Analysis 330
14.1.2 Laboratory Analysis 330
14.2 Applying the Capture Calculation 331
14.2.1 Case 1: Discarded Solids Report to Underflow 331
14.2.2 Case 2: Discarded Solids Report to Overflow 331
14.2.3 Characterizing Removed Solids 331
14.3 Use of Test Results 332
14.3.1 Specific Gravity 332
14.3.2 Particle Size 332
14.3.3 Economics 333
14.4 Collection and Use of Supplementary Information 334
15 Dilution 335
15.1 Effect of Porosity 337
15.2 Removal Efficiency 338
15.3 Reasons for Drilled-Solids Removal 339
15.4 Diluting as a Means for Controlling Drilled Solids 340
15.5 Effect of Solids Removal System Performance 341

WELL LOGGING AND FORMATION EVALUATION free download pdf

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INTRODUCTION

The purpose of this book is to provide a series of techniques which will
be of real practical value to petrophysicists in their day-to-day jobs. These
are based on my experience from many years working in oil companies.
To this end I have concentrated wherever possible on providing one recommended
technique, rather than offer the reader a choice of different
options.
The primary functions of a petrophysicist are to ensure that the right
operational decisions are made during the course of drilling and testing a
well—from data gathering, completion and testing—and thereafter to
provide the necessary parameters to enable an accurate static and dynamic
model of the reservoir to be constructed. Lying somewhere between
Operations, Production Geology, Seismology, Production Technology and
Reservoir Engineering, the petrophysicist has a key role in ensuring the
success of a well, and the characterization of a reservoir.
The target audience for this book are operational petrophysicists in their
first few years within the discipline. It is expected that they have some
knowledge of petroleum engineering and basic petrophysics, but lack
experience in operational petrophysics and advanced logging techniques.
The book also may be useful for those in sister disciplines (particularly
production geology and reservoir engineering) who are using the interpretations
supplied by petrophysicists.

CONTENTS
Introduction ix
1 Basics 1
1.1 Terminology 1
1.2 Basic Log Types 3
1.3 Logging Contracts 9
1.4 Preparing a Logging Programme 11
1.5 Operational Decisions 14
1.6 Coring 16
1.7 Wellsite Mud Logging 21
1.8 Testing/Production Issues 24
2 Quicklook Log Interpretation 29
2.1 Basic Quality Control 29
2.2 Identifying the Reservoir 30
2.3 Identifying the Fluid Type and Contacts 32
2.4 Calculating the Porosity 34
2.5 Calculating Hydrocarbon Saturation 37
2.6 Presenting the Results 40
2.7 Pressure/Sampling 42
2.8 Permeability Determination 45
3 Full Interpretation 49
3.1 Net Sand Definition 49
3.2 Porosity Calculation 51
3.3 Archie Saturation 53
3.4 Permeability 54
4 Saturation/Height Analysis 59
4.1 Core Capillary Pressure Analysis 60
4.2 Log-Derived Functions 64
5 Advanced Log Interpretation Techniques 67
5.1 Shaly Sand Analysis 67
5.2 Carbonates 73
5.3 Multi-Mineral/Statistical Models 74
5.4 NMR Logging 76
5.5 Fuzzy Logic 85
5.6 Thin Beds 87
5.7 Thermal Decay Neutron Interpretation 93
5.8 Error Analyses 96
5.9 Borehole Corrections 101
6 Integration with Seismic 103
6.1 Synthetic Seismograms 103
6.2 Fluid Replacement Modelling 108
6.3 Acoustic/Elastic Impedance Modelling 110
7 Rock Mechanics Issues 115
8 Value Of Information 119
9 Equity Determinations 125
9.1 Basis for Equity Determination 126
9.2 Procedures/Timing for Equity Determination 127
9.3 The Role of the Petrophysicist 129
10 Production Geology Issues 137
10.1 Understanding Geological Maps 140
10.2 Basic Geological Concepts 147
11 Reservoir Engineering Issues 155
11.1 Behavior of Gases 155
11.2 Behavior of Oil/Wet Gas Reservoirs 159
11.3 Material Balance 162
11.4 Darcy’s Law 163
11.5 Well Testing 166
12 Homing-in Techniques 171
12.1 Magnetostatic Homing-in 171
12.2 Electromagnetic Homing-in 185
13 Well Deviation, Surveying, and Geosteering 193
13.1 Well Deviation 193
13.2 Surveying 195
13.3 Geosteering 197
13.4 Horizontal Wells Drilled above a Contact 203
13.5 Estimating the Productivity Index for Long
Horizontal Wells 205
Appendix 1 Test Well 1 Data Sheet 207
Appendix 2 Additional Data for Full Evaluation 215
Appendix 3 Solutions to Exercises 218
Appendix 4 Additional Mathematics Theory 251
Appendix 5 Abbreviations and Acronyms 264
Appendix 6 Useful Conversion Units and Constants 268
Appendix 7 Contractor Tool Mnemonics 271
Bibliography 309
About the Author 313
Acknowledgments 314
Index 315

lecture 7 ( Downhole Motors)

 Downhole Motors

About this chapter

The positive-displacement mud motor (PDM) is the most indispensable tool at the DD’s

disposal. It is vital that the DD understand how to utilize the PDM to best advantage. The

basics of PDM design are covered in this chapter.

With the PowerPak mud motor, Anadrill has added a reliable and high-quality tool to its

range.

It is recommended that, in the short term, the DD be aware of the exact specifications of

"third party" PDMs which he may have to use.

PDM design, specifications, operating procedures, etc., are covered in this chapter. The

basics of steerable PDMs and steerable BHA design are also covered in this chapter.

Objectives of this Chapter

On completing this chapter the directional driller should be able to do the following

exercises:

1. Draw a diagram of a PDM, showing the major components. Describe the function

and purpose of each component.

2. Explain the main differences in construction between 1:2 lobe and multilobe PDMs.

3. Explain the uses of a rotor nozzle.

4. Describe what is meant by hydraulic thrust when using a PDM.

5. Explain the procedure involved in making up a PDM with a bent sub in a kickoff

BHA.

6. Describe the basic service which is done to a PDM after POOH, prior to laying it

down. Assume water-base mud.

7. Describe what precautions are necessary when drilling with a PDM.

8. Explain what surface indication(s) the driller has of PDM operation (and possible

problems) downhole.

9. Explain the main difference(s) in design between a straight PDM and a steerable

PDM.

10. Explain how an estimate is made of the buildup rate achievable with a bent-housing

steerable BHA.

11. Give examples of typical steerable BHAs designed to build inclination from vertical

to maximum angle and to hold this inclination until the next casing point.

12. Explain the effect the upper (string) stabilizer has on steerable BHA performance.

lecture 6 (Drilling Jars)

Drilling Jars

About this chapter

Until recently, the Earthquaker Drilling Jar and the Shock Guard were the only two DD

tools which were provided directly by Anadrill for the drilling of directional wells.

The Earthquaker is still the most reliable and effective mechanical drilling jar on the

market. Clients have confidence in the Earthquaker because of its track record.

This chapter is designed to explain the theory and operation of the EQ Jars. Their

position in the BHA and the constraints thereon are covered here and in Chapter 11.

It is recommended that, in addition to this DD training manual, the Anadrill DD carry the

EQ Jar manual with him on every job. The manual has additional information (e.g.

rig-floor tripping load adjustment, EQ Jar specifications and fishing diagrams) which are

beyond the scope of this book.

Objectives of this Chapter

On completing this chapter the directional driller should be able to do the following

exercises:

1. Describe the objective of jarring.

2. Describe the different types of jars available.

3. Describe how the tripping mechanism of the EQ Jar operates.

4. List the advantages and disadvantages of the EQ Jar vis-a-vis hydraulic jars.

5. Describe the major constraints on EQ Jar position in the BHA.

6. Show what is meant by Pump Extension Force.

7. Calculate the weight indicator reading when the driller jars DOWN. Assume the

pumps are on and there is wall drag.

8. Show how the driller cocks the EQ Jars

·  after jarring UP

·  after jarring DOWN

9. Calculate the maximum allowable UP setting for the EQ Jar.

6.1 Using Drilling Jars

6.1.1 Drilling Jars

Drilling jars are run as part of most directional BHAs. On vertical wells, drilling jars

may or may not be run, depending on the client. Drilling jars are designed to deliver an

impact in either an upward or a downward direction. Some jars work in one direction

only.

Inside, a jar is basically a sliding mandrel that allows a brief and sudden axial

acceleration of the drillstring above the jar. Travel of this mandrel (the hammer) is

limited by a stop (anvil) on the outer sleeve (Figure 6-1).

6.1.1.1 Jarring Objective

To transfer the potential energy stored in the stretched drill pipe to kinetic energy in the

BHA above the jars. At the end of the jar stroke, a stress wave is sent to the stuck pipe.

The magnitude of the stress wave is related to the velocity of the accelerated BHA. The

duration of the wave is related to the length of the BHA.

Kinetic Energy =

1

2

MV2

M = Mass (weight) of BHA above the jar

V = Velocity (speed) at which the mass is moving when the jar fires (hammer strikes

anvil) in feet/second.

There are three types of drilling jars:

·  Mechanical

·  Hydraulic

·  Hydromechanical.

6.1.1.2 Mechanical Jars

Mechanical jars operate using a series of springs, lock and release mechanisms.

Hydraulic jars operate using the controlled passage of hydraulic fluid. Hydromechanical

jars are a hybrid of both designs, usually hydraulic up and mechanical down.

A mechanical jar trips up at a preselected tensile force, and trips down at a preselected

compressional force. The jar trips only at the set threshold. This is normally beyond the

forces reached while drilling. The position of the mechanical jar while drilling is either

cocked (neutral) or extended. Drilling is never conducted with the jars tripped down as

unnecessary jarring might damage the bit and BHA components.

The release mechanism of a mechanical jar is set either downhole or at surface,

depending on jar design. There are two main designs. One uses the principle of the

torsion spring. These mechanical jars are delivered to the rig with specific up and down

tripping load settings. Their release force can be varied downhole by 10 - 15% by

applying torque to the drillstring. Left- hand torque decreases spring tension; right-hand

torque increases it. The Dailey L.I. Jar uses this design. Another design uses an

expanding sleeve with slots, lugs and ancillary springs. The overpull necessary to trip the

jar can be reduced downhole by increasing mud flow rate. The Anadrill Earthquaker

(EQ) Drilling Jar uses this latter design. It will be covered in some detail later in this

chapter.

6.1.1.3 Hydraulic Jars

A hydraulic jar consists of two reservoirs of hydraulic fluid separated by a valve. When

tension or compression is applied to the tool in the cocked position, fluid from one

chamber is compressed and passes through the valve at high flow resistance into the

second chamber. This allows the tool to extend or contract. The distance traveled is

called the metered stroke. When the stroke reaches a certain point, the compressed fluid

is allowed to suddenly bypass the valve. The valve trips as the fluid rushes into the

second chamber, instantly equalizing pressures between the two chambers. The greater

the force on the jar, the greater the compression of the fluid and the sooner and more

forceful the release. This is the principle of the Anadrill Hydraquaker Drilling Jar

(Figure 6-2).

Hydraulic jars do not trip at a preselected threshold. When, and how forcefully, the jar

trips is determined by the magnitude of the applied tension or compression. To trip up,

the force of the blow is proportional to the overpull. The greater the overpull on the

drillstring, the sooner the jars trip and the harder the blow. Thus, the hydraulic jar has the

advantage of having a continuously-variable jarring force, within its design limits.

Another advantage of hydraulic jars is that, for sizes 6 1/2" OD, they have a larger ID

than comparable mechanical jars.

Once a hydraulic jar is cocked, it will fire if given enough time to complete the metered

stroke. This gives hydraulic jars an advantage in high-angle and horizontal wells. Here,

excess drag may prevent the driller from applying sufficient tension or compression to

trip a mechanical jar. A cocked hydraulic jar will eventually fire, even with minimal

tension or compression. However, this can be a disadvantage also, as accidental jarring

(particularly in vertical wells) with the pipe in slips is dangerous and could lead to a

fishing job.

Repeated jarring with a hydraulic jar can lead to overheating of the hydraulic fluid. This

reduces its viscosity, shortening the metering time and tripping the jar before the desired

tension can be applied. Consequently, jarring force decreases over time. Although some

changes have occurred recently, an adequate design for hydraulic jars has yet to be

proven i.e. visco jets.

 

One major advantage of mechanical jars is that they will not fire until the threshold

setting is reached. They are often perceived as being more rugged and durable than

hydraulic jars.

6.1.1.4 How does the Earthquaker (EQ) Drilling Jar Work ?

The major external components of the EQ Jar are shown in Figure 6-3. Note that some

EQ Jars (older design) have a Jack Nut. The new design dispenses with the Jack Nut.

The function of the Jack Nut was to extend the EQ Jar prior to running in the hole to

drill. This is no longer deemed necessary (See below).

The EQ Jar has a relatively simple tripping mechanism that can be adjusted on surface, if

required. In the EQ Jar, the relationship between the Trip Mandrel, Trip Sleeve, Friction

Sleeve, Adjusting Sleeves and Spring Tubes (Figure 6-4) is what determines whether the

jar is cocked or tripped. The Trip Sleeve acts as a radial spring along its length. The

Spring Tubes are sets of three concentric tubular springs having a very high spring rate

(only 0.1" reduction in length for a compressive load of 100,000 lbs.).

Figure 6-4 is an expanded view of the EQ Jar tripping mechanism in four different

positions, one of which (position 2) is a "snapshot". In the cocked position, the Trip

Sleeve is in its normal state. It is closed around the Trip Mandrel, with the teeth and

grooves on the ID of the Trip Sleeve meshed with the teeth and grooves on the OD of the

Trip Mandrel. The teeth on the OD of the Trip Sleeve contact the teeth on the Friction

Sleeve crest-to-crest. The Friction Sleeve is held securely inside the Middle Housing and

acts as an integral part of the housing.

The housings are free to slide up and down a fraction of an inch over the Trip Mandrel

until the Spring Tubes contact the end of the Trip Sleeve. Adjusting Sleeves, threaded

into the housings at top and bottom, control the amount of free movement. Rotation of

the Adjusting Sleeves controls the amount of free movement and changes the point

where resistance is encountered. It is the Adjusting Sleeves which are rotated to a

number of different positions (corresponding to specific tripping loads) when the EQ Jar

is calibrated in the workshop. On the rig, if the "UP" or "DOWN" trip settings have to be

adjusted, the lower or upper adjusting sleeve, respectively, is rotated to the desired

position, corresponding to a specific tripping load on the EQ Jar calibration sheet (Refer

to EQ Jar Manual).

When contact is made between the Trip Sleeve and the Spring Tubes, additional pushing

or pulling of the EQ Jar causes compression to begin in either the Upper or Lower Spring

Tube, respectively. As tension on the tool increases, pressure grows between the Trip

Sleeve and Trip Mandrel teeth. The high spring rate of the Spring Tubes at the end of the

Trip Sleeve and the contact angle of the Trip Mandrel teeth on the Trip Sleeve teeth,

forces the Trip Sleeve to expand. This expansion is restricted by the Friction Sleeve teeth

which are positioned to confine the Trip Sleeve. The Spring Tubes compress until the

Housing and Friction Sleeve have moved enough that the Trip Sleeve is no longer

constrained by the Friction Sleeve teeth. This point is determined by the EQ Jar setting.

At this point, the Trip Sleeve instantaneously expands off the Trip Mandrel and engages

with the teeth and grooves on the ID of the Friction Sleeve. The Housings, now free to

move, accelerate up or down until the Hammer strikes the Anvil. This completes the

jarring cycle. The Trip sleeve expansion is maintained through the free stroke by

Expansion Pads at either end of the Trip Sleeve.

Recocking of the jar occurs as the Trip Sleeve, still engaged with the Friction Sleeve, is

repositioned over the Trip Mandrel. When the teeth of the Trip Sleeve realign with the

teeth on the OD of the Trip Mandrel, the Trip Sleeve returns to its normal position by

closing around the Trip Mandrel and disengaging form the Friction Sleeve. With the

tension no longer applied, the Spring Tubes extend to their full length, completing the

recocking. The cycle is now ready to repeat, in either direction, as often as possible.

To summarize, following are the three “major” positions of the EQ Jar (Figure 6-5):

1. Jar Tripped Down The mandrel has been released from the Trip Sleeve and

expanded into the Friction Sleeve in the “jarred down” position.

2. Jar Cocked The mandrel is locked in position inside the Trip Sleeve, with preset

loads restrining the Trip Sleeve crest-to-crest with the teeth of the Friction Sleeve.

The Spring Tubes are relaxed.

3. Jar Tripped Up The mandrel has been released from the Trip Sleeve and expanded

into the Friction Sleeve in the jarred up position. The jar is in tension for running in

the hole and drilling.

6.1.1.5 Features of the EQ Jar

1. With the EQ Jar in the drillstring, the driller can start jarring up or down

immediately if the pipe becomes stuck.

2. Both up and down tripping loads can be independently adjusted to a maximum of

180,000 lbs. (for some sizes) either in the workshop or at the rig-site (Refer to EQ

Jar manual). Torque has no effect on these preset hitting loads.

3. The EQ Jar spline system (for rotation) means that there is no torsional slack in the

mandrel. This is useful in DD work, especially when orienting.

4. The working parts are enclosed in oil to minimize wear or malfunction due to mud

solids etc.

5. A compensating piston minimizes pressure differentials on all seals. Preloaded

V-packing on moving seal areas eliminates both high and low pressure leaks.

6. The jar will trip at the same preset load, regardless of time in the hole or downhole

temperature.

7. Internal compensation allows for high extension force and compression placements.

It also provides a means for downhole load adjustment.