abnormal subsurface pressure

Trainee Pressure Engineer Version 1.00

TRAINING MANUAL

December 1, 1998

INTERNATIONAL LOGGING, INC.

Pore Pressure Engineering i

Table Of Contents VERSION 1.00................................................................................................................................................................ 1

TABLE OF CONTENTS ..............................................................................................................................................I

PORE PRESSURE ENGINEERING....................................................................................................................... 1

INTRODUCTION............................................................................................................................................................. 1 What Is Overpressure And Why Study It?.......................................................................................................... 1 Responsibilities........................................................................................................................................................ 1

WELLBORE PRESSURE CONCEPTS ............................................................................................................................. 3 Hydrostatic Pressure.............................................................................................................................................. 3 Overburden Pressure ............................................................................................................................................. 3

Obtaining Bulk Densities from E-Logs ................................................................................................................. 4 Obtaining Bulk Densities From Cuttings Bulk Density........................................................................................ 5

Limitations......................................................................................................................................................... 5 Obtaining Bulk Densities from Cuttings Density Column .................................................................................... 6

Limitations......................................................................................................................................................... 6 Obtaining Bulk Densities from Drilling Models ................................................................................................... 6 Calculating OBP .................................................................................................................................................... 6

Formation Pressures.............................................................................................................................................. 6 Normal Hydrostatic Pressure................................................................................................................................. 6 Subnormal Pressures.............................................................................................................................................. 7 Overpressure.......................................................................................................................................................... 7

Artesian Well ..................................................................................................................................................... 7 Hydrocarbon Column ........................................................................................................................................ 7

Pressure Representation........................................................................................................................................ 8 Pressure/Depth Representations............................................................................................................................ 8

Equilibrium Density, Equivalent Density ......................................................................................................... 8 Pressure Gradients............................................................................................................................................. 8 Hydrodynamic Levels ....................................................................................................................................... 8

Definitions .................................................................................................................................................... 8 Flow .............................................................................................................................................................. 9

Stress concepts ........................................................................................................................................................ 9 CAUSES OF ABNORMAL SUBSURFACE PRESSURE .................................................................................................10

Introduction ...........................................................................................................................................................10 Undercompaction..................................................................................................................................................11

Conclusion ...........................................................................................................................................................12 Diagenesis..............................................................................................................................................................12

Clay Diagenesis ...................................................................................................................................................12 Clay Minerals ..................................................................................................................................................13 Clay Chemistry and Structure.........................................................................................................................13 Diagenetic Reactions (Dewatering) .................................................................................................................13

Theory and Experimental Observations .....................................................................................................13 Models of Montmorillonite Dehydration....................................................................................................13

Consequences of Clay Diagenesis...................................................................................................................14 Shale Water Salinity...................................................................................................................................15

Summary .........................................................................................................................................................15 Carbonate Compaction........................................................................................................................................15 Dolomitisation.....................................................................................................................................................15

Effects and Relevance .....................................................................................................................................16 Gypsum/Anhydrite Relationships........................................................................................................................16 Evaporite Deposit Seals .......................................................................................................................................16 Solution Processes ...............................................................................................................................................17 Organic Matter Transformation...........................................................................................................................17

Thermal Processes................................................................................................................................................17 Aquathermal Pressuring.......................................................................................................................................17

Objections........................................................................................................................................................18

Pore Pressure Engineering ii

Conclusion.......................................................................................................................................................18 Osmosis...................................................................................................................................................................18

Conclusion ...........................................................................................................................................................19 Tectonic Movements and Deformation .............................................................................................................19

Uplift....................................................................................................................................................................20 Tectonic Faulting .................................................................................................................................................20 Folding.................................................................................................................................................................22 Tectonics and Sedimentation...............................................................................................................................22

Deltaic Areas ...................................................................................................................................................22 Growth Faults .............................................................................................................................................22 Shale Diapirism..........................................................................................................................................22

Subduction Zones ............................................................................................................................................23 Conclusion.......................................................................................................................................................23

Diapirism.............................................................................................................................................................23 Implications.....................................................................................................................................................23 Effects on Pore Pressure Gradients.................................................................................................................23 Summary Of Tectonic Effects.........................................................................................................................24 Pore Fluids And Confinement .........................................................................................................................24

Miscellaneous Processes.....................................................................................................................................24 Mud Diapirs and Sandstone Dikes ......................................................................................................................24 Contemporaneous Faulting..................................................................................................................................25 Permafrost............................................................................................................................................................25

Production and Charging....................................................................................................................................25 Repressuring........................................................................................................................................................25 Piezometric Fluid Levels .....................................................................................................................................25

Conclusion.............................................................................................................................................................25 OVERPRESSURE DETECTION TECHNIQUES.............................................................................................................28

Introduction ...........................................................................................................................................................28 Normal Compaction Trend .................................................................................................................................28 Characteristics of Undercompacted Zones......................................................................................................28

Transition Zone....................................................................................................................................................28 Diagenetic Cap Rock ...........................................................................................................................................28

List of Overpressure Detection Methods..........................................................................................................28 Pre-spud Data .......................................................................................................................................................29

Geophysical data..................................................................................................................................................30 Seismic Methods.............................................................................................................................................30

Very High Resolution Seismic ...................................................................................................................30 High Resolution Seismic ............................................................................................................................30 Conventional Seismic Methods..................................................................................................................30 3-D Seismic ................................................................................................................................................30 Seismic “S” Wave .......................................................................................................................................30 Interpretation...............................................................................................................................................30

Reflection Analysis ................................................................................................................................30 Interval Velocities ..................................................................................................................................31 Estimating The Sand/Shale Ratio...........................................................................................................32 Amplitudes .............................................................................................................................................32

Gravimetry.......................................................................................................................................................32 Offset Well Data..................................................................................................................................................33 Piezometric Maps................................................................................................................................................33

While Drilling Data..............................................................................................................................................33 Introduction..........................................................................................................................................................33

Real Time Drilling Methods................................................................................................................................34 Drill rate...............................................................................................................................................................34

Formation Breakdown Mechanism Of the Bit ................................................................................................35 Lithology .........................................................................................................................................................35 Compaction.....................................................................................................................................................36 Differential Pressure ........................................................................................................................................36 WOB................................................................................................................................................................36 RPM.................................................................................................................................................................36 Torque .............................................................................................................................................................36 Hydraulics .......................................................................................................................................................37

Pore Pressure Engineering iii

Viscosity.....................................................................................................................................................37 Water-loss (Filtration Rate)........................................................................................................................37 Suspended Solids........................................................................................................................................37

Bit Type And Wear................................ ................................ ................................ ................................ .........37 Personnel And Equipment...............................................................................................................................38 Conclusion.......................................................................................................................................................38

D Exponent ..........................................................................................................................................................38 Corrected d exponent.......................................................................................................................................39 Factors That Influence The Dc Exponent........................................................................................................39

Discussion...................................................................................................................................................39 Mechanical Parameters included in the d exponent formula .................................................................39

Turbine Motors ..................................................................................................................................40 Hole Section Change ..........................................................................................................................40

Other Mechanical Parameters ................................................................................................................40 Bit Type / Drilling Action ..................................................................................................................40 Bit Wear .............................................................................................................................................40 Bottom Hole Assembly Configuration ................................ ................................ ..............................42 Hole Angle................................ ................................ ................................ ................................ .........42 Junk In The Hole................................................................................................................................42

Formation Parameters.............................................................................................................................43 Unconformities...................................................................................................................................43 Lithological Variations ......................................................................................................................43

Drilling Fluid Parameters .......................................................................................................................43 Bit Hydraulics ....................................................................................................................................43 Differential Pressure ..........................................................................................................................44

Calculating Pore Pressure Values from Dc Exponent.....................................................................................44 Eaton’s Method...........................................................................................................................................44 ∆P Ratio ......................................................................................................................................................45 Trend Lines .................................................................................................................................................45

Trend Line Fitting ..................................................................................................................................45 Trend Line Shifting ................................................................................................................................46

Application and Conclusion ............................................................................................................................46 Agip Sigmalog.....................................................................................................................................................46

Theory .............................................................................................................................................................46 Methodology ...................................................................................................................................................46 Conclusion.......................................................................................................................................................48

Drag, Torque And Fill ................................ ................................ ................................ ................................ .........48 Miscellaneous ......................................................................................................................................................48

Standpipe, Mud Flow Out, Differential Flow, Pit Volume .............................................................................48 Mud Weight Out..............................................................................................................................................49 Mud Resistivity In And Out............................................................................................................................49 M.W.D.............................................................................................................................................................49

Methods Depending On Lagtime .......................................................................................................................50 Gas .......................................................................................................................................................................50

Introduction.....................................................................................................................................................50 Background Gas ..............................................................................................................................................50 Gas Shows.......................................................................................................................................................51 Connection And Trip Gas................................................................................................................................51 Normalized Connection Gas ...........................................................................................................................52 Gas Composition.............................................................................................................................................52

Shale Density.......................................................................................................................................................53 Theory and Limitations...................................................................................................................................53 Methods Of Measurement...............................................................................................................................53

Heavy Liquids.............................................................................................................................................54 Variable Density Column ...........................................................................................................................54 Mercury Pump ............................................................................................................................................54 Pycnometer.................................................................................................................................................54

Methodology ...................................................................................................................................................54 Shale Factor .........................................................................................................................................................55 Flowline Temperature..........................................................................................................................................56

Introduction.....................................................................................................................................................56 Geothermal Concepts......................................................................................................................................56

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Measuring Mud Temperature..........................................................................................................................57 Surface Measurements................................................................................................................................57 M.W.D........................................................................................................................................................58 Bottomhole Measurements during Wireline Logging................................................................................58 Measurements while Running Wireline Logs ............................................................................................59 Bottomhole Measurements during Formation Testing...............................................................................59 Bottomhole “Temp Plates” Measurements.................................................................................................59 Thermometry ..............................................................................................................................................59

Conclusion.......................................................................................................................................................60 Mud Density ........................................................................................................................................................60

Example...........................................................................................................................................................61 Cuttings / Cavings................................................................................................................................................61 Cuttings Gas.........................................................................................................................................................62

Post-Drilling Data................................................................................................................................................63 E-logs ...................................................................................................................................................................63

Method Of Estimating Pore Pressure Magnitude From Resistivity And Sonic Logs .....................................63 Direct Pressure Measuring Tests .......................................................................................................................64 Summary.................................................................................................................................................................64

QUANTITATIVE PRESSURE EVALUATION................................................................................................................65 Introduction ...........................................................................................................................................................65 Equivalent Depth Method....................................................................................................................................65

Applications.........................................................................................................................................................65 Principle...............................................................................................................................................................65 Establishing Isodensity Lines ................................ ................................ ................................ ..............................67

Ratio Method.........................................................................................................................................................67 Applications.........................................................................................................................................................67 Principle...............................................................................................................................................................67 Establishing Isodensity Lines ................................ ................................ ................................ ..............................68

Eaton Method........................................................................................................................................................69 Application ..........................................................................................................................................................69 Principle...............................................................................................................................................................69 Establishing Isodensity Lines For The Dxc................................ ................................ ................................ .........70

Comparison of Previous Methods......................................................................................................................70 Sigmalog Evaluation ............................................................................................................................................71 Normalized ROP Evaluation (Prentice) ...........................................................................................................71 Evaluation By Direct Observation Of The Differential Pressure.................................................................71

Gas .......................................................................................................................................................................71 Mud Losses..........................................................................................................................................................71 Kick......................................................................................................................................................................71

Formation Tests ....................................................................................................................................................72 Evaluation of the Overburden Gradient ...........................................................................................................72

FRACTURE GRADIENT................................................................................................................................................73 The Overburden Relationship.............................................................................................................................73 States of Stress Underground.............................................................................................................................73 Poisson’s Ratio......................................................................................................................................................74 Terzaghi and Biot..................................................................................................................................................74 The Relationship Between σ1 and σ3 ...............................................................................................................75 Formation Fracture Gradient Prediction Formulas......................................................................................75

Hubbert And Willis..............................................................................................................................................75 Limitations.......................................................................................................................................................76

Matthews And Kelly............................................................................................................................................76 Limitations.......................................................................................................................................................76

Eaton....................................................................................................................................................................76 Limitation ........................................................................................................................................................76

Christman.............................................................................................................................................................77 Anderson, Ingram And Zanier .............................................................................................................................77 Daines ..................................................................................................................................................................77

Advantages ......................................................................................................................................................78 Disadvantages ..................................................................................................................................................78

AGIP....................................................................................................................................................................79

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Pilkington.............................................................................................................................................................79 Breckels And Van Eekelen ..................................................................................................................................79 Bryant ..................................................................................................................................................................79 Conclusions On The Different Fracture Pressure Detection Techniques ............................................................80

BASIC WELL CONTROL .............................................................................................................................................81 Shut-in Procedures...............................................................................................................................................81

Introduction..........................................................................................................................................................81 Shut-in Procedures ...............................................................................................................................................81

Drilling Ahead – Surface BOP Stack In Use ..................................................................................................81 Tripping Pipe – Surface BOP Stack In Use ....................................................................................................82 Drilling Ahead – Subsurface BOP Stack In Use.............................................................................................82 Tripping Pipe – Subsurface BOP Stack In Use...............................................................................................82 Exercises ..........................................................................................................................................................83

Basic Well Control Theory..................................................................................................................................83 Examples ................................ ................................ ................................ ................................ ..............................83 Summary................................ ................................ ................................ ................................ ..............................85

Exercises ..........................................................................................................................................................86 Kill Procedures.....................................................................................................................................................86

Slow Pump Rate ..................................................................................................................................................86 Obtaining Shut-in Pressures and Effects of Gas Migration .................................................................................86 Identification of Influx................................ ................................ ................................ ................................ .........87

Exercises ..........................................................................................................................................................88 Kill Mud Weight ..................................................................................................................................................88

Exercises ..........................................................................................................................................................88 Introduction To Kick Killing Procedures ............................................................................................................88

Introduction.....................................................................................................................................................88 Wait And Weight Method...............................................................................................................................89

Introduction.................................................................................................................................................89 Procedure For Wait and Weight Method....................................................................................................89 Pressure Schedule For Drill Pipe................................................................................................................90

Exercises ..........................................................................................................................................................91 Driller’s Method..............................................................................................................................................91 Concurrent Method..........................................................................................................................................91

Introduction.................................................................................................................................................91 Procedure For The Concurrent Method......................................................................................................92

Exercises ................................ ................................ ................................ ................................ ..............................92 Kill Procedures With Subsurface BOP Stacks ....................................................................................................92

Introduction.....................................................................................................................................................92 Problems Associated With Kick Detection.....................................................................................................92 Hanging-off .....................................................................................................................................................93 Subsea BOPs...................................................................................................................................................93 Choke Line Pressure Loss...............................................................................................................................93 Exercises ..........................................................................................................................................................94 Kill Procedures ................................................................................................................................................94

Introduction.................................................................................................................................................94 Procedure For Calculating An Unknown Value Of Reduced Circulating Pressure ...................................94 Suggested Procedure For Killing A Well Using A Subsea Stack ................................ ..............................94

Other Considerations In Deepwater Drilling .......................................................................................................95 Comparison Of The Three Methods Of Well Control.........................................................................................95

Conclusions.....................................................................................................................................................97 Exercises ..........................................................................................................................................................97

Kick Tolerance.....................................................................................................................................................97 Exercises ..........................................................................................................................................................98

Saltwater Or Oil Kicks................................ ................................ ................................ ................................ .........98 Example...........................................................................................................................................................98

Weight Material Required And Mud Volume Increase..................................................................................... 100 Examples ....................................................................................................................................................... 100 Exercises ........................................................................................................................................................ 101

DRILLING FLUID BASICS ................................................................................................................................. 102

FUNCTIONS OF DRILLING FLUIDS.......................................................................................................................... 102

Pore Pressure Engineering vi

DEFINITION OF TERMS............................................................................................................................................ 102 BASIC CLAY CHEMISTRY BEHAVIOR .................................................................................................................... 102

Causes, Description And Remedies For Clay Behavior............................................................................. 103 Dispersion.......................................................................................................................................................... 103 Flocculation ....................................................................................................................................................... 103

COMMON CONTAMINANTS AND TREATMENT ..................................................................................................... 103 Salt........................................................................................................................................................................ 103 Anhydrite............................................................................................................................................................. 103 Cement ................................................................................................................................................................. 104

DRILLING FLUID ADDITIVES................................................................................................................................... 104 Weighting Agents ............................................................................................................................................... 104 Thinning Agents................................................................................................................................................. 104 Filtra tion Control Agents ................................................................................................................................. 104 Caustic Soda....................................................................................................................................................... 104 Other Additives................................................................................................................................................... 105

BASIC TYPES OF DRILLING FLUIDS....................................................................................................................... 105 Spud Muds / Native Muds................................................................................................................................. 105 Organic-thinned Freshwater Muds................................................................................................................ 105 Lime Muds........................................................................................................................................................... 105 Gyp Muds............................................................................................................................................................ 105 Salt / Polymer Muds.......................................................................................................................................... 105 Low Solids Mud.................................................................................................................................................. 106 Saltwater Muds................................................................................................................................................... 106 Saturated Salt Muds.......................................................................................................................................... 106 Oil Based Muds.................................................................................................................................................. 106

BASIC HYDRAULICS ........................................................................................................................................... 107

RHEOLOGY AND HYDRAULICS .............................................................................................................................. 107 Introduction and Definition.............................................................................................................................. 107 Viscosity............................................................................................................................................................... 107

NEWTONIAN AND NON-NEWTONIAN FLUIDS ...................................................................................................... 107 Introduction ........................................................................................................................................................ 107 Newtonian Fluids............................................................................................................................................... 108 Non-Newtonian Fluids...................................................................................................................................... 108 Flow Patterns And Velocity Profiles Of Non-Newtonian Fluids............................................................... 109 Viscosity Vs. Shear Rate................................................................................................................................... 109

HYDRAULICS............................................................................................................................................................. 109 The Bingham Plastic Model ............................................................................................................................. 110

Procedure ........................................................................................................................................................... 110 The Power Law Model...................................................................................................................................... 111

Procedure ........................................................................................................................................................... 111 The Aims Of Hydraulics.................................................................................................................................... 111

Equivalent Circulation Density.......................................................................................................................... 112 Annular Flow Pattern......................................................................................................................................... 112 Typical Annular Velocities ................................................................................................................................ 112 Slip Velocity...................................................................................................................................................... 112

Bingham Plastic Model Slip Velocity Formula................................ ................................ ............................ 113 Power Law Model Slip Velocity Formula .................................................................................................... 113 Conclusion..................................................................................................................................................... 113

Pressure Losses At The Bit................................................................................................................................ 114 Jet Velocity........................................................................................................................................................ 114 Bit Hydraulic Horsepower................................................................................................................................. 115 Jet Impact Force................................................................................................................................................. 115 Surge and Swab Pressures ................................................................................................................................. 116

Procedure....................................................................................................................................................... 116 Suggested Solution Approach.......................................................................................................................... 116 Some Observations On Hydraulics................................................................................................................. 117

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OPTIMUM BIT HYDRAULICS ......................................................................................................................... 119

INTRODUCTION......................................................................................................................................................... 119 CONSTRAINTS........................................................................................................................................................... 119

Minimum Flow Rate.......................................................................................................................................... 119 Maximum Flow Rate ......................................................................................................................................... 120 Maximum Pump Pressure ................................................................................................................................ 120

BIT HYDRAULICS (KENNETH SCOTT METHOD )................................................................................................... 120 Procedure............................................................................................................................................................ 120

B.V. RANDALL METHOD........................................................................................................................................ 121 Guidelines........................................................................................................................................................... 121 Procedure............................................................................................................................................................ 122

Pore Pressure Engineering 1

Pore Pressure Engineering

Introduction Pressure evaluation is an integral part of formation evaluation.

A Pressure Engineer or DLS operator is first an experienced logging geologist. He has gained a thorough understanding of rig procedures, personnel relationships, basic and advanced mudlogging techniques, and interpretation. He has possibly been exposed to pressure evaluation methods either by logging in DLS units or by having performed basic logging duties in areas of overpressure occurrence.

The logging geologist’s basic understanding and experience must then be utilized to the fullest extent. His further education is attained through continuing experience, studying the books/technical manuals supplied to him by ILO, and participating in special training programs in order to achieve the level of expertise expected of the ILO Pressure Engineer.

What Is Overpressure And Why Study It? Any fluid (oil, water, etc.) which is contained within rocks beneath the Earth’s surface is under pressure. The weight of the rocks, fluid and atmosphere above and the containment of the rocks surrounding the fluid cause this pressure.

The pressure of the fluid is defined as being “overpressured” if the pressure of the fluid is greater than would normally be expected at a certain depth. When the pressure of the fluid is less than would normally be expected at a certain depth, the rock is defined as being “underpressured”.

Overpressure can be a major problem in the oil industry, and a major danger to drillers. If you drill into a layer of rocks, where the pore pressure suddenly increases, and the drilling techniques that are employed have not been engineered to cope with the higher pressures, you can get a sudden kick. There is a further possibility that a blow out could occur. Modern rigs have devices to try and prevent a blow out occurring. But, if these devices fail, you have a potential disaster in the making. Oil and gas are flammable, and oil rigs have a lot of metal and electrical systems, which have the potential to generate a spark. If a blow out happens, there is a good chance of oil or gas catching fire so instead of just a gushing oil well, you have a burning oil well, or a major explosion.

It is therefore important to the oil industry to be able to predict when you might drill into an overpressured zone, so that the correct drilling techniques could be employed.

Responsibilities When a logging geologist is promoted to a Trainee Pressure Engineer, he accepts a great responsibility because the decisions and reports made in the course of his duties are of importance to the drilling operations as a whole. Reports should thus be accurate, subject to critical examination in difficult situations, and, most important of all, they must be able to be substantiated.

Both the Trainee Pressure Engineer and his senior, either a Pressure Engineer or Senior Pressure Engineer, work in very close cooperation with the operator’s engineer, geologist and company representative, the rig superintendent and toolpushers, drillers, the mud engineer/s and the operator’s representatives at the local base or in town. The ability to communicate with these personnel is vital.

During the performance of his duties the Pressure Engineer will find that some wells are trouble-free and very undemanding; however, this is no reason to reduce the quantity or quality of his observations and records. Conversely, some wells or intervals will place enormous stress and


responsibility upon the pressure engineer such that his knowledge and his capabilities will be tested to the utmost. Every well is different, and knowledge may be gained from every wellsite situation. The completion of a demanding assignment which results in the attainment of total depth with the minimum amount of hole problems and the maximum amount of information is one of the most rewarding aspects of the job.


Wellbore Pressure Concepts

Hydrostatic Pressure Hydrostatic pressure is the pressure exerted by the weight of a static column of fluid.

In a column of fluid at rest, the pressure exerted by the fluid at any given level is:

• The result of the unit weight and vertical height of the fluid column.

• Independent of the dimension and geometry of the fluid column

• Exerted in all directions equally.

The formula for calculating hydrostatic pressure is:

Ph (psi) = 0.0519 x MW (ppg) x TVD (ft) (Imperial)

Ph (Kpa) = 0.098 x MW (kg/m3) x TVD (m) (Metric)

Overburden Pressure Overburden pressure at a given depth is the pressure exerted by the total weight of the overlying formation.

The OBP is the result of the combined weight of the formation matrix plus the fluids in the pore space, overlying the formation of interest. This combined weight is referred to as the bulk density, ρb. The bulk density of a sediment is a function of:

• Matrix density

• Porosity

• Density of the pore fluid

Sediment porosity decrease under the effect of burial (compaction) is proportional to the increase in overburden pressure. In the case of clays, this reduction is essentially dependent on the weight of the sediments. In sandstones and carbonates, this relationship is a function of many parameters other than compaction, such as diagenetic effects, sorting, original composition and so on.

A decrease in porosity is necessarily accompanied by an increase in bulk density.

The calculation of the OBP is the first step in the analysis of wellbore pressures.

Formula for Sp: Sp = 0.433 x Σ (ρb x H)

Formula for Sg (OBG): 0.433 x ∑ (1-φ) x ρma + (φ x ρ f )

Where: 0.433 = constant for converting g/cc to psi/ft

φ = porosity of fm expressed as a fraction

ρma = density of rock matrix in g/cc

ρf = density of fluid in g/cc

Substance Density g/cc

Sandstone 2.65


Substance Density g/cc

Limestone 2.71

Dolomite 2.87

Anhydrite 2.98

Halite 2.03

Gypsum 2.35

Clay 2.7-2.8

Freshwater 1.00

Seawater 1.03-1.06

Oil 0.6-0.7

Gas 0.015

Drilling fluids 1.03-2.04

Table 1 Table of lithologies and average densities.

Bulk density can be obtained from:

• E-logs

• Cuttings density measurement

• Some mathematical drilling models

Obtaining Bulk Densities from E-Logs Get bulk density readings from density E-logs of offset wells and a suitable lithological interval

Derive bulk density from sonic logs:

Step 1: derive porosity

φ = (∆t - ∆tma) / (∆tf - ∆tma); where:

∆t = transit time read from the sonic log in µsec/ft

∆tma = transit time of the matrix in µsec/ft

∆tf = transit time of the fluids in the pore in µsec/ft

Note: use values of 180-200 µsec/ft for ∆tf .

For ∆tma use the following values:

Lithology Matrix Transit times

Dolomite 43.5

Limestone 43.5-47.5

Sandstone 47.6-55.6

Clay 167-62.5

Anhydrite 50

Gypsum 52.6


Lithology Matrix Transit times

Quartz 55.6

Salt 66.7

Granite 50

Table 2 Table of Lithology and Matrix transit times.

For loose sands:

φ = ((∆t - ∆tma) / (∆t + 200)) x 1.288

for uncompacted shale:

φ = ((∆t - ∆tma) / (∆t + 200)) x 1.568

for cemented rock:

φ = (∆t -∆tma) / 153

Step 2: derive bulk density

ρb = (1 - φ) x ρma + (φ x ρ f) or

φ = (ρma - ρb) / (ρma - ρ f )

for cemented formations:

ρb = 3.28 – (∆t / 88.95)

for loose formations:

ρb = 2.75 – 2.11 x ((∆t - ∆tma) / (∆t – 200)) <- this is the most common equation used to process ρb from sonic logs.

The above equations assume:

The tool is calibrated to read zero porosity when ρb = 2.75 g/cc

The pore fluid is connate water, ρb = 1.03 g/cc and ∆tf = 200 µsec/ft

Obtaining Bulk Densities From Cuttings Bulk Density The recommended method to be used while drilling and waiting for E-log results.

Procedure:

Fill a mud balance cup with a volume of clean cuttings equivalent to the density of drill water, Dw (1.03 g/cc or 8.33 ppg)

Top up the cup with drill water and obtain the combined density of cuttings and drill water, R.

Calculate the density: ρb = Dw / ((2 x Dw) – R) g/cc

Limitations Possible hydration of clay cuttings in the annulus and consequent swelling will cause lower bulk density readings

Oil mud contamination of cuttings reduces bulk density readings


Obtaining Bulk Densities from Cuttings Density Column Purpose: to obtain shale density and assess the degree of compaction

The density gradient column is a partial mixture of two fluids in a graduated cylinder such that the densities of the two fluids vary evenly from top to bottom. Calibration beads of varying densities suspended in the mixture permit the user to prepare a calibration graph of the density of the fluid with respect to column height.

Limitations • Special facilities have to be provided because of the toxicity of the substances used

• Operator error – degree of consistency and careful of methodology

• Problems of hydrated or oil wet cuttings give low density readings

• Some substances might be heavier than 2.85 g/cc

Obtaining Bulk Densities from Drilling Models Ex: Agip Sigmalog

Calculating OBP Calculate the OBP for the first interval. In onshore areas it is from the depth of the water table and in offshore areas it is the water depth.

Calculate the OBP for each lithological interval

Add all the intervals to get the OBP at a certain depth

Formation Pressures Formation pressure is the pressure of the fluid contained in the pore spaces of the sediments or other rocks. It is also called pore pressure .

The three categories of formation pressure are:

• Subnormal pressure: This is the pressure below hydrostatic pressure.

• Hydrostatic pressure: A function of pore fluid density.

• Overpressure: Pressure in excess of hydrostatic pressure, and usually limited by the overburden pressure.

The relationship of overburden pressure and pore pressure is illustrated below:

OBP = pore pressure + matrix confining stress

The overload is supported at a particular depth by the pore pressure at that depth and the vertical component of the matrix stress, σ1.

The pressure gradient is affected by the concentration of dissolved solids and gases in the fluid column, and varying temperature gradients. An increase in dissolved solids (higher salt concentration) tends to increase the normal pressure gradient, whereas increasing amount of gases in solution at higher temperatures would decrease the normal hydrostatic pressure gradient.

Normal Hydrostatic Pressure In normal hydrostatic conditions formation pressure and hydrostatic pressure are equal.


Water density is a function of the concentration of dissolved solids, usually expressed as salinity. As formation waters vary greatly in salinity, they also vary in density. The Table below illustrates this point.

Water Type Salinity (Cl-)

mg/l

Salinity (NaCl)

mg/l

Water Density

g/cm3

Fresh Water 0 to 1500 0 to 2500 1.00

Sea water (example) 18000 30000 1.02

Formation water (ex.) 10000 16500 1.01

36000 60000 1.04

48000 80000 1.05

60000 100000 1.07

Salt water saturated in NaCl 192667 317900 1.20

Table 3 Water density in relation to salinity (at 20 deg C, standard conditions)

The range of average densities generally used for sedimentary basins varies from 1.0 to 1.08 sg (8.33 to 9.00 ppg).

Subnormal Pressures One of the commonest causes is the reservoir outcropping at a lower altitude than the elevation at which it was penetrated during drilling. This explains why such pressure anomalies are so frequently encountered in mountainous areas.

The position of the water table in relation to the land surface is also a cause of subnormal pressure, esp. in arid areas.

Another, rarer situation is the marked reduction of average fluid density due to the presence of a significantly thick gas column. The shallower the depth of the reservoir in question the more marked will be the effect.

Overpressure

Artesian Well If the intake point (outcrop) of an aquifer is situated at a higher altitude than the wellsite then the formation pressure will be abnormally high.

Hydrocarbon Column Within a hydrocarbon bearing reservoir the fluid column creates a pressure anomaly. This is at its maximum at the top of the reservoir. The force that the water exerts on the hydrocarbon interface due to buoyancy is a function of the differences in density between the water and hydrocarbons. The resulting pressure anomaly at the top of the hydrocarbon column is derived by the following formula:

Phc = 0.052 x H x (d – dc) where,

Phc = pressure anomaly at the top of the hydrocarbon column

H = height of the hydrocarbon column

d = density of the water


dhc = density of the hydrocarbons

Overpressure due to this difference in density progressively decreases from a maximum at the top of the reservoir to zero at the water-hydrocarbon contact. Any overpressure already existing in a series is increased by such an additional anomaly.

Pressure Representation

Pressure/Depth Representations

Equilibrium Density, Equivalent Density The primary aim of drilling mud is to counterbalance formation pressure, which is generally expressed in terms of equilibrium density.

Equilibrium density represents the average mud weight required to counteract formation pressure.

Equivalent density or Equivalent circulating density is the density corresponding to mud column pressure in relation to depth.

Equivalent density (not mud weight) has to be compared with equivalent density to assess the state of balance of the borehole.

The rotary table (RKB) is used as the datum in calculating equivalent density.

Pressure Gradients Formation pressure gradient is the unit increase in pore pressure for a vertical increase in depth.

The formation pressure gradient should be calculated by reference to the top of the water table in onshore areas and to the sea level in offshore areas.

Overburden gradient is the unit increase in stress exerted by the weight of overlying sediments for a vertical increase in depth.

The upper limit at which a rock forming a borehole can withstand pressure from the mud column is called fracture pressure. Fracture gradient is the unit increase in fracture pressure for a vertical increase in depth.

Hydrodynamic Levels

Definitions Fluids possess energy which can be expressed as a hydrodynamic potential.

This potential may be represented as ahead of water using the following general formula:

H = ((Px 10) / d) + Z where,

H = hydrodynamic level or head (meters)

P = formation pressure at depth Z (kg.cm-2)

d = water density

Z = subsea depth of the measure point (absolute depth in meters)

Depending on our knowledge of fluid densities, it is possible to define three types of hydrodynamic levels:


Pseudo-potentiometric level: d = 1

Represents formation pressure as a head of fresh water.

This is often applied when the fluid density is unknown – hence the name pseudo potentiometric level.

In the case of an outcropping aquifer it is possible to assume that the pseudo-potentiometric level is given by the altitude of the outcrop, so that H = Z.

Piezometric level: d = well measurement

Represents formation pressure as a head of salt water. The salinity is that measured in a test sample.

The piezometric level is the height at which the water level stabilizes in a non-artesian well.

Potentiometric level: d = average density

The density used corresponds to the average density of the water column saturating the reservoir between the intakes and the datum point.

In the case of a fresh water aquifer, the potentiometric level (or true level) corresponds to the pseudo-potentiometric and piezometric levels.

Flow Maps of potentiometric levels show that even in deep-lying aquifers hydrodynamic flow occurs. True hydrostatic conditions do not in practice exist at the basin level.

If the potential of a given fluid is not uniform, a force acts upon the fluid to push it in the direction of minimum potential.

Stress concepts Unlike liquids, which can withstand only internal loads which are equal in all directions (isotropic distribution), solids can support differing loads in a variety of directions. When a solid is subjected to external forces it reacts by redistributing elementary internal loads, called stresses. These differ in two important ways from the pressures undergone by liquids:

• They differ in spatial direction: a given stress ellipsoid can have any orientation;

• There are two types. These differ according to how the load is applied. If loading is perpendicular to the elementary surface in question the stress is said to be normal, and can be compressive or tensile. Tangential loading of the given elementary surface produces what is called shear stress.

A number of items of information are needed in order to define stress conditions at a given point.

The mechanics of continuous environments state that at any given point in a solid there exist three planes intersecting at right angles. Their orientation is unknown, but they are subject to normal stresses only. They are known as the principal planes, and the associated stresses are known as the principal stresses. These planes are therefore not subjected to shear stress. This means that six parameters are required to describe stress conditions at a point in a solid: the values of the three principal stresses and the three orientation parameters of the principal planes.


Causes of Abnormal Subsurface Pressure

Introduction Pore pressures can be normal, i.e., simply the pressure exerted by a column of water, or they may be abnormal or subnormal. Normal pore pressure at a point in the geologic section will be the hydrostatic pressure due to the average density and vertical depth of the column of fluids above that point – that is, to the water table or sea level. The convention is that abnormal pressures are higher than normal and subnormal pore pressures are lower.

Abnormal pressure has many origins. The object of this chapter is to list them and attempt to explain each one of them in detail. This would give the user enough information to understand the phenomena properly and decide what line of action should be taken when faced with the resulting problems during drilling operations.

Abnormal pressures are hydrodynamic phenomena in which time plays a major role. Every occurrence of abnormal pressure has a limited lifespan, governed on one hand by the continued existence of the reason of the overpressure and on the other by the effectiveness of the seal.

A closed or semi-closed environment is in fact essential for abnormal pressure to exist and above all to be maintained.

The formation of abnormal subsurface pressures can be the result of one or more processes.

The relevant processes are:

A. Undercompaction

B. Diagenesis

Clay diagenesis

Clay minerals

Clay chemistry and structure

Diagenetic reactions

Consequences of clay diagenesis

Carbonate Compaction

Dolomitisation

Gypsum/anhydrite relationships

Evaporite Deposit Seals

Solution Processes

Organic Matter Transformation

C. Thermal Influences

Aquathermal Pressuring

D. Osmosis

E. Tectonic Movements And Deformation

Uplift

Faulting

Folding

Halokinesis


Sediment Deformation

F. Miscellaneous processes

Mud diapirism

Contemporaneous faulting

Permafrost

G. Production and Charging

Piezometric fluid changes

Undercompaction The principle behind undercompaction arises from the balance between overburden pressure and the ability of a given formation to expel water.

Compaction is a process whereby grains respond to a load stress by inelastic deformation. This is an irreversible process. Elastic deformation may also take place but to a negligible degree for clastic sediments.

In sedimentary basins the source of this load stress and cause of the deformation is the burial of sediments by subsequent sedimentation during subsidence.

Compaction factors that are relevant to abnormal pressures are:

• Rate of deposition

• Volume of sediment deposited

If the sedimentation rate is slow, normal compaction occurs, that is to say that equilibrium between increasing overburden and the ability to expel fluids is maintained. The rapid burial of some sediments may inhibit certain diagenetic processes from taking place or being completed.

When the interstitial fluid supports part of the overburden, there is undercompaction. This has the effect of simultaneously retarding any reduction in porosity or increase in density.

Since porosity in clays can vary from 80% to less than 10% in 5000 meters. It is easy to see that the volume of water expelled in this way is considerable.

A reduction in clay porosity is accompanied by an increase in bulk density. Measurements of clay porosity and density form the basis of the study of compaction.

To summarize, normal clay compaction is the result of the overall balance between the following variables:

• Clay permeability

• Sedimentation and burial rate

• Drainage efficiency

Pore pressure intensity is dependent on the sedimentation rate.

Because the sedimentation rate is often greater than which is needed to allow dewatering of excess fluid, abnormal pressure is very frequent in the following environments (these are sites of rapid sedimentation):

• Recent deltaic formations

• Passive continental margins

• Accretion prisms of subduction zones


Generally speaking, the more recent the phase of active subsidence, the greater the probability that pressure anomalies will be encountered.

The probability of abnormal pressure existing increases with the thickness of clay intervals where draining layers of sand or silt are absent.

The presence of drains within the argillaceous series is an essential factor governing abnormal pressure. The presence and magnitude of the abnormal pressure appear to be related to the ratio of sand to clay in the sedimentary series.

Harkins and Baugher (1969) show that when continental sands and clays cover marine clays, abnormal pressure develops preferentially in environments with a sand content of less than 15%. It will be readily understood that this percentage limit is itself a function of several factors, in particular the degree of confinement of the sand bodies.

The mechanism for expelling water from clays towards porous reservoirs is the same as that for a fluid to migrate towards zones of lower resistance to flow. As expulsion rate is at maximum close to drains, the early stages of this process lead to compaction in the immediately adjacent clay beds. The resulting reductions in porosity and permeability retards further fluid expulsion. In certain cases this same mechanism can contribute to the formation of diagenetic cements which affect the sands at the clay boundary.

The fluid pressure of within clay is often assumed to be similar to that in the adjacent sand body with which it is in contact. However, during the compaction process the pressure in the clay further away from the drain is probably higher. This hypothesis, proposed by Magara (1974) seems logical but has never been tested experimentally.

The increases in formation pressure, which can be attributed to the effects of sedimentation rate, are sometimes insufficient to explain certain pressure anomalies.

Conclusion The overburden effect is defined as the result of the action of subsidence on the interstitial fluid pressure of the formation. If fluids can only be expelled with difficulty relative to burial conditions, they must support all or part of the weight of the overlying sediments.

Porosity decreases less rapidly than it should with depth and clays are then said to be undercompacted.

Formation pressure intensity is controlled as much by the rate of subsidence as by the dewatering efficiency. Imbalance between these two factors is the most frequent cause of abnormal pressure.

Diagenesis Diagenesis is the physical and chemical changes that take place within a rock after deposition.

Clay Diagenesis The closest interrelationship between diagenetic and compaction processes occurs with clay minerals, specifically the alteration of montmorillonite to illite. Other diagenetic processes that can influence the pore pressure gradient are:

• Alteration from Calcite to dolomite

• Gypsum / anhydrite Stability

• Certain results of solution deposits

For the purposes of biogenic hydrocarbon provenance, the diagenetic activity of clay minerals is the most important process at work in sedimentary basins.


Clay Minerals Argillaceous minerals form part of the phyllosilicates group, which are characterized by alternatively arranged sheets of (Si, Al or Fe3+)2O5 tetrahedra and octahedra.

The most significant clay minerals present in argillaceous rocks are:

• Kaolinite

• Vermiculite

• Montmorillonite

• Illite

Smectites are sometimes referred to instead of montmorillonites.

Clays are the products of weathering and alteration processes on parent material. The type of rock and the prevailing conditions will determine the initial product of these processes.

Clay Chemistry and Structure The simplest clay mineral, pyrophyllite, is formed by the superposition of two tetrahedral sheets bonded by Al3+ ions in the octahedral position. The structure of pyrophyllite is electrically neutral. The sheets are connected by residual links called van der Waal’s bonds.

Substitution of Si4+ cations in the tetrahedral layer by Al3+ creates a negative charge that is compensated by the adsorption of cations (Mg and Ca) and interlayer water. This new structural type is characteristic of, for instance, montmorillonite (smectite family). A strong cation exchange capacity, or water adsorption capacity, gives this type of clay its “swelling” behavior on contact with water.

Montmorillonites are the products of alkaline conditions and the alteration of basic material with available Mg and Ca. They are the most common clays in marine environments and also the most widely distributed. They are transported in suspension. They are swelling clays.

Further substitution of Si4+ cations by Al3+ increases the electrical imbalance and in particular allows potassium or calcium ions to be fixed in an interlayer position. The presence of these interlayer potassium ions prevents the entry of liquids, or other cations, into the structure. The clay loses its capacity to adsorb water and may gradually change to illite, which belongs to the mica family.

Kaolinite is another frequent constituent of clays. It is a purely aluminous variety like pyrophyllite, with the difference that its structure is asymmetric and its interreticular distance is 0.71 nM. It has a better thermodynamic stability than the smectites.

See diagram …..

Diagenetic Reactions (Dewatering)

Theory and Experimental Observations The diagenesis of montmorillonite is thermodynamic, and specifically endothermic, because the main agent of change is heat, and the main source of heat is the increase of temperature with burial. It is essentially an endothermic de-watering of Montmorillonite.

Models of Montmorillonite Dehydration The water content of the mineral is of three types:

• interstitial pore water

• inter-lattice oriented water


• lattice surface oriented water : this has the strongest bond to the mineral

Powers (1959) suggested a two-stage model for the expulsion of water from the smectites:

Stage 1: free pore water expelled near the surface under the influence of pressure.

Stage 2: interlayer water released gradually, first under the effects of pressure, then increasingly under the influence of temperature.

Burst (1969) improved on this model and proposed three stages of dehydration: (see diagram……..)

Stage 1: Expulsion of free pore water and part of the interlayer water, as far as the last two molecular layers, under the influence of pressure. This process takes place increasingly slowly as permeability declines relative to depth.

Stage 2: Expulsion of the last-but-one molecular layer of interlayer water under the influence of temperature increase. The temperature at which water is released at this stage occurs between 90 and 100 degC.

Stage 3: Gradual expulsion of the last molecular layer of interlayer water.

Check with the Sperry Sun books on this three-stage dewatering process:

Stage 1: initial burial of the sediment expels the majority (80%) of the free (locally marine) interstitial pore water in the clay lithology.

Stage 2: Increasing temperatures from 180 to 220 degF release 2 or more layers of inter-lattice oriented water with associated cations. The water expelled will be rich in ions and silica.

Stage 3: Increasing temps to 280 degF, and the availability of K ions, enable the exchange of the last 2 layers (relatively fresh but may contain excess K ions) oriented water from the mineral into the lithology.

There are, however, three areas of uncertainty, namely the quantity of water adsorbed onto the clay sheets, its density and the temperature range needed for dehydration.

Jonas et al (1982) and Fripiat and Letellier (1984), who studied the thermodynamic and microdynamic properties of water at or near mineral surfaces, arrived at two conditions important for current thinking:

• that surface influences affect no more than two or three molecular layers;

• that the structure of this bound water is not noticeably different from that of free pore water, and it therefore seems improbable that its density could reach the values previously quoted, regardless of its position in the pore spaces (i.e. between fine particles or in the interlamellar spaces).

Regardless of this controversy, it will be noted that the release of water can probably contribute significantly to the creation of abnormal pressure, since it occurs at high temperatures, and therefore at considerable depths where the capacity for water expulsion under the influence of the overburden is reduced.

A high geothermal gradient or the confinement of an argillaceous body will both modify clay diagenesis. The abnormally high porosity (and water content) of undercompacted zones explains why their geothermal gradient is abnormally steep. This is a factor that can encourage dewatering and transformation of montmorillonite. On the other hand, abnormal pressure retards dewatering and increases salinity, tending to alter the diagenetic process by comparison with an unsealed environment.

Consequences of Clay Diagenesis The most potent control over the pore pressures associated with these processes is the ratio of reservoir to source, in normal circumstances the sand/shale ratio,


Shale Water Salinity The expulsion of relatively fresh connate waters from the clay mineral leaves the normally pressured clay ion enriched. Osmosis draws water back to the clay and pore pressure increases. Alternatively, and most probably contemporaneously, ionic concentration takes place at the centers of clay/shale bodies from which fluids can’t be expelled, and those fluids released from the fringes of the bodies are attracted into the center instead of being expelled.

Summary With initial compaction montmorillonite loses 2 or more of its layers of oriented water and most of its free pore water.

With increasing temps and the presence of K ions the last two layers of oriented water are released and illite is formed.

The effects on porosity and permeability are such that montmorillonite, a mineral which readily absorbs water, is converted to illite in a process that expels water. This water should be removed and thus porosity and permeability decreased. If expulsion or removal is inhibited the lithology becomes undercompacted and the pore fluid pressure gradient abnormally high.

Although clay diagenesis is a contributory factor to abnormal pressure, it is thought to be a secondary rather than a major cause. By adding to the abnormal pressure from overburden effects (undercompaction) it can explain pressure gradients which rise more steeply than the overburden gradient.

Carbonate Compaction By virtue of their texture, carbonates do not generally undergo the effects of undercompaction seen in clays and shales. Chalk is an exemption, being made up of coccoliths, which tend to take up a horizontal arrangement during compaction. This special texture makes chalk behave rather like clay with respect to porosity reduction and water expulsion during burial. These pelagic sediments are deposited slowly, and their initial porosity is around 70%. This porosity is gradually reduced to a value of between 5 and 10% at 3000 m. Very thick chalk deposits may develop undercompaction because of their low permeability.

When porosity declines to a level of 35% or less, mechanical compaction is replaced by “chemical compaction”(i.e. processes involving pressure-solution). At this stage the coccoliths dissolve at their points of contact and CaCO3 is precipitated in the pore spaces with the result that porosity and permeability are diminished.

Dolomitisation Transformation from trigonal calcite, CaCO3, to trigonal Dolomite, CaMg (CO3)2.

The conditions whereby this process may take place are many and varied, and are influenced by the presence of other molecules and ions in such substances as dissolved CO2 and magnesian brines, MgCl2. The presence of between 6-7% NaCl in solution lowers the temp range at which dolomite will precipitate. If sulfate ions, SO4, are present the temp of precipitation can be lowered.

Dolomites occur as:

• primary deposits like the Permian evaporites in no. England.

• Derived by metasomatic alteration thru penecontemporaneous dolomitisation over a large area of unconsolidated limestone deposited on the sea floor.

Secondary dolomitisation is caused at depth by circulating solutions rich in Mg and CO2, possibly derived from the breakdown of earlier dolomites. Dolomitisation followed by breakdown and re-calcitisation is also widely known.


Effects and Relevance There is an increase in the bulk density of the mineral from 2.71 to 2.86 g/cc. Thus the volume of the mineral is decreased and there is an increase in porosity and permeability of a sediment composed of this material.

The increase in porosity without an appropriate change in the volume of pore fluid is a common source of abnormally low pressures. Dolomitisation increasing the permeability can result in under-pressured formations where lost circulation of drilling fluids can occur. If the pore pressure is abnormally high in the dolomites it is this type of lithology that can be a source of pore fluid influx.

Gypsum/Anhydrite Relationships Gypsum is the initial deposit of calcium sulfate, CaSO4, associated with marine sediments, esp. evaporites. It is a hydrated form (CaSO4.H2O), and Anhydrite or Hemihydrate is the dehydrated form.

CaSO4.2H2O <> CaSO4 (anhydrite) + 2H2O

CaSO4.2H2O <> CaSO4.1/2H2O (hemihydrate) + 3/2H2O

Anhydrite occurs as the result of diagenetic dehydration of gypsum, but it may rarely occur as a primary deposit depending on the stability between the two minerals as controlled by salinity, temperature and pressure. In general it is the secondary mineral produced by dehydration.

The temperature of transition to anhydrite in pure water is about 40 degC, but that this may be lowered considerably by the presence of NaCl in solution to 25 degC; increasing pressure; and the presence of sulfates and other ions.

The physical changes that take place are an increase in density from 2.35 to 2.98 g/cc, a 40% loss in volume, and an overall increase in substance volume, anhydrite plus water of dehydration, of about 1%.

Anhydrite is very rarely porous. The excess fluid is deposited in normal detrital pore spaces and/or it would assist in the replacement by dissolving and re-distributing surrounding evaporites. Void spaces within the gypsum/anhydrite assemblage will be occupied by halite.

Some authors regard the rehydration of anhydrite and the associated increase in bulk as responsible for abnormally high pore pressures. This is entirely unfeasible below 3000 ft. Another reason might be due to the waters of dehydration trapped with anhydrite, but the mechanisms by which this might happen are not apparent.

Evaporite Deposit Seals Evaporite deposits can have different roles in abnormal pressure:

• A passive role, i.e., as a seal

• An active role, i.e. as a pressure generator like diapirs (see discussion on diapirs)

Evaporites are totally impermeable, which makes them an almost perfect seal. Because of their inherent plasticity they also have a degree of mobility, and any fractures which occur can repair themselves. This is esp. true of rock salt (halite).

During sedimentation, the sealing efficiency of evaporite deposits is a barrier to vertical expulsion of fluid from underlying sediments. If lateral hydraulic conductivity is insufficient for adequate drainage, the overburden effect will continue to increase and may bring about abnormal pressure in reservoirs and clays alike. Exs: Permian shales underlying Zechstein salt (northern Germany), Saharan Triassic and the Iranian Sudair.

However, on the regional scale this mobility can jeopardize the effectiveness of the seal.


Solution Processes Solutions move about within sediments dissolving and/or precipitating substances. The effects might be to deposit materials in void spaces (silica dioxide in sandstones, lime and kaolin in other sediments), or enlarge or create void spaces by dissolution. The creation of void spaces by dissolution is not an obvious cause of abnormal pressure but it will cause an increase in density of pore water and thus affect the fluid pressure gradient.

The most significant contribution of solution processes to pressure development is the precipitation of an impermeable mineral layer to form a seal further impeding permeability.

Organic Matter Transformation At shallow depths organic matter contained in the sediments is broken down by bacterial action, generating biogenic methane. In a closed environment the resulting expansion can lead to abnormal pressure. Since it is rare for a good seal to exist at such shallow depths, the gas usually diffuses to the surface.

Trapped gas pockets can be a real threat to offshore drilling due to the absence of BOPs in the top hole. But, this can usually be revealed by high-resolution seismic techniques.

Bacterial activity decreases with increasing depth, gradually giving way to thermochemical cracking. The cracking involves transforming a heavy product into a lighter one under the influence of high temperatures.

Thermochemical generation of light hydrocarbons such as methane proceeds at an increasing rate as temperature rises. It reaches a maximum above 100 degC to 120 degC and cont inues until carbonized kerogens are produced (see Figure ,,,,,,,,,,).

The cracking process creates hydrocarbons from organic matter and also produces light hydrocarbons from heavy ones. The transformation increases the volume. If this occurs in a closed environment, it can cause pressure to rise. This depends on the degree to which the environment is confined and the final nature of the hydrocarbon product.

As compaction proceeds and less water is expelled, decomposing organic matter would tend to cause the water to become saturated in gas and eventually produce free gas. If this gas is unable to escape it causes abnormal pressure. Pressure anomalies and undercompaction due simply to the overburden effect will be magnified if gaseous hydrocarbons are generated at the same time. Many authors agree that the rise in pressure may lead to microfissuring and allow pressure to be partially dissipated, thus contributing to primary migration.

Undercompacted clay zones often have a high gas content. This suggests that cracking of the organic matter makes a contribution to abnormal pressure. On the other hand, since some undercompacted clays have no sign of gas it can be assumed that hydrocarbon transformation is not the dominant cause of abnormal pressure.

Thermal Processes The effects are twofold, those on an open hydrodynamic system, which affect the compaction profile and those on enclosed systems i.e. entrapped fluids.

Aquathermal Pressuring The thermal expansion effect is a concept put forward by Barker (1972). It is a consequence of the expansion

Essentially any volume of the pore water that becomes isolated due to formation of permeability barriers is then a fixed volume subject to the effects of temperature and imposed pressure. The effects of pressure are those of increasing and decreasing depth. Temperature effects the actual


volume and density of the fluid. As the volume is fixed and expansion restricted, the density must be fixed and accordingly the fluid pressure gradient increase.

Any fixed volume of fluid will be subject to temperature-controlled expansion and contraction. Thus if a non-compressible liquid volume is raised through the geothermal gradient it will become under pressured; and if lowered it will become over pressured.

Aquathermal expansion (pressuring) only has an effect if the following conditions are satisfied:

• The environment is completely isolated.

• Pore volume is constant.

• The rise in temperature takes place after the environment is isolated.

In fact, for the thermal effect to be significant the system must be perfectly closed, since creation of overpressure is associated with a very small increase in the volume of water. The volume of increase is in the order of 0.05% for a burial of 1 km with a temperature gradient of 25 deg C/km (Magara, 1975). This means that even the smallest leak will reduce or even cancel out the thermal effect. Whether the expansion effect gives rise to any overpressure will depend on the extent to which the rate of expansion due to the rise in temperature matches the dewatering rate.

Even so, since the fluid expands so little, clays are usually sufficiently permeable to allow the additional volume to be dissipated in a short geological time given a “normal” geothermal flux. However, if the geothermal gradient steepens significantly and is accompanied by a rapid burial rate, the resulting increase in fluid volume may exceed dewatering efficiency.

Strong thermal anomalies associated with volcanic intrusions or nearby magma chambers may create local overpressures of limited duration (generally less than one million years).

Objections Many objections can be raised against thermal origins of overpressure due to the expansion of water. These are:

• Completely impervious formations are rare.

• Transition zones, which correspond to a gradual shift from hydrostatic to abnormal pressure, reflect the hydraulic transmissivity through clays.

• A rise in temperature reduces viscosity and makes fluids easier to expel.

Conclusion Aquathermal pressuring (expansion) has been proposed as an effect producing increased pressure in sedimentary sequences due to a temperature rise in the closed system.

The effect is governed not only by thermal conditions and water density, but more particularly by the permeability of the environment and the time factor. Its overall contribution is therefore not easy to quantify.

The importance of the thermal effect in the creation of abnormal pressure is a matter for great controversy. Some believe its role is negligible while others see it as a factor of some significance.

Osmosis Osmosis is the spontaneous movement of water through a semi-permeable membrane separating two solutions of different concentration (or one solution and water) until the concentration of each solution becomes equal, or until the development of osmotic pressure prevents further movement from the solution of lower concentration to that of higher concentration.


Osmotic pressure is virtually proportional to the concentration differential. For a given differential it increases with temperature.

It had been suggested that osmosis might contribute to the development of overpressure regimes. Several authors had proved experimentally that clay could be considered a semi-permeable membrane. Its effectiveness in this respect was patchy however, to such an extent that an increased content of very fine quartz in the clay was enough to cause a noticeable reduction in efficiency.

The flow of water through a clay bed is dependent upon the following:

• Differential pressure

• Differential concentration

• Differential electrical potential

• Temperature

• Thickness of the clay

• Size of the micropores

• Degree of fissuring

Kharaka and Berry (1973) drew attention to the fact that the efficiency of the membrane increases with the cation exchange capacity of the clay.

In a closed environment, the migration of water towards a reservoir with higher salinity tends to increase pressure in that reservoir until differential pressure is equal to osmotic pressure.

Osmosis is put forward by several authors to explain certain very rare instances of combined pressure and salinity anomalies, esp. the Morrow lenticular sandstones in Oklahoma where pressure anomalies are sometimes negative and sometimes positive.

The process of reverse osmosis consists of the migration of water from strongly saline areas towards areas of weaker salinity under the influence of pressure differential (“chocolate Bayou” field, Texas).

It thus seems possible that in certain sedimentary basins fluid flows generated by compaction and gravity may be accentuated or attenuated by the effects of osmosis or reverse osmosis.

Conclusion Although lab tests have proven that osmotic effects are real, the evidence for their existence in nature is far less certain.

It will be noted that lab trials used only thin membranes of pure clay and strongly contrasting saline solutions. These cannot easily be extrapolated to the geological environment.

It seems that the capacity for osmosis to generate abnormal pressure is limited to special cases such as sharply contrasting salinity, proximity to salt domes and lenticular series. In most instances of abnormal pressure, the role of osmosis is difficult to prove and must be thought of as minor.

Tectonic Movements and Deformation Any process that shifts sediment from its normal position of compaction deformation will affect the fluid pressures contained in that sediment. This means that tectonics may cause abnormal pressure or restore pressure to normal.

The link between tectonics and fluids can be viewed from two related standpoints:


• Tectonic activity causes rock deformations which have a direct or indirect effect on fluid pressure distribution;

• To a greater or lesser extent fluid pressure alters the way in which deformations develop as a result of stress.

The categories of tectonic movement and deformation involved are:

• Uplift

• Faulting

• Folding

• Diapirism

• Tectonic deformation: Sediment deformation

Uplift The crustal thinning that has aided downwarping has enabled higher heat flow into the basin that eventually results in upwarping.

Changes in formation relief and geometry are a direct cause of pressure redistribution. Relief induces hydrodynamic activity, which in turn is an underlying cause of some of the pressure anomalies observed.

Deep-lying sediments may be uplifted and part of the overlying strata then eroded. In this way zones of high pressure could be brought closer to the surface, which would make them appear anomalous. Such situations are referred to as paleopressures.

This hypothesis assumes a closed system and rapid uplift. But, this raises numerous objections:

1. Since tectonic movement is usually accompanied by fracturing, pressure would tend to dissipate.

2. The lower temperature at the reduced depth would decrease the fluid volume and therefore the pressure.

In fact temperature equalization probably ensures that fluid pressure declines more quickly than overburden pressure during erosion, thus leading to a negative pressure anomaly (Magara, 1975).

Tectonic Faulting The effect which faults have on fluid pressure distribution depends on many factors (see Elf p51):

• Whether they form an effective seal or on the contrary act as a drain

• How they displace reservoirs and sealing strata

• The original distribution of sealing and reservoir sequences

The structural uplifts along inversion axes are usually associated with strike-slip faults along the flanks of the inversion axes forming horst structures.

The downthrow of the graben structures in the North Sea has encouraged the generation of over pressures by various processes:

• Compaction mechanisms

• The downthrow of reservoirs, forming a seal and subjecting those fluids to aquathermal pressuring. (incidences of this phenomena are more readily observed in the Gulf of Suez).

Most tectonic faulting can be simplified into


• Normal

• Wrench

• Thrust

• Overthrust zones

Pore pressure gradients may be effected in various ways by faulting (compare with above):

• There may be an increase in the rate and volume of deposition across faults into the downthrown side.

• The fault may form a seal to fluid movement or bring a reservoir up against an impermeable formation.

• The faulting process may raise or lower a formation through the geothermal gradient with consequences for aquathermal or gas pressuring.

Normal faults are the result of a stress field where σ1 is vertical and σ3 is horizontal. As they are created by a system in extension and therefore tend to be open, they are often effective drains, and provide links between reservoirs that help to equalize pressure gradients. However, in the presence of saturated fluids the fault plane becomes, due to the localized pressure decrease, a site for syntectonic or premature crystallization of calcite, quartz, anhydrite or dolomite, none of that is very permeable. If this happens, faults will act as a barrier or seal to a reservoir.

Reverse faults are the result of a stress field where σ1 is close to horizontal and σ3 nearly vertical and are thus more likely to be closed. In very broad terms they tend to be a barrier to fluid circulation, either in their own right or because of the alterations they engender in surrounding formations.

Tear faults are the result of a stress field where σ1 and σ3 are horizontal and σ2 is vertical. As with normal faults, whether they act as a barrier or drain depends on whether there is syntectonic mineral crystallization. Their impact will also be affected by the relative displacement of the compartments on either side of the fault.

Fault displacement is also an essential factor in the distribution of fluid pressure. If a fault is to isolate a section of reservoir, it needs to displace its walls in such a way as to bring the porous layer into contact with an impervious layer. If movements bring reservoirs into contact at some point, pressure conditions in the two compartments will equalize.

Major faults, esp. strike slip faults, create fracture corridors or zones which act as a drain as long as the fractures are not sealed by mineralization.

Joints are fractures with little or no displacement. They are capable of depriving impervious rocks of their ability to act as a seal. On the other hand, plastic clays, anhydrites and above all salt deposits are self-repairing, and are the only seals capable of retaining their impermeability even in conditions of severe deformations (Iran, Iraq). Fracture intensity depends on both the stress field (type of tectonic activity) and the mechanical behavior of the layers.

Overthrust Zones

Fluids and at high pressure and temperature act as a lubricant for the movement of the overthrust block. Very pronounced overpressure can be induced by contact between the overthrust surface and the substratum. Rapid loading occurs, causing abnormal pressure in underlying confined sequences. The significance of these effects will depend on the thickness of the nappe and the degree of hydrodynamic confinement within the sequences beneath the overthrust.


Folding The same tectonic forces that cause thrust faulting will cause beds of sediment to buckle. This will have similar effects of raising and lowering beds through the compaction and geothermal gradients.

Tectonics and Sedimentation

Deltaic Areas The development of a delta depends on the balance between sedimentation rate, subsidence rate and eustatic variations in the sea level. Undercompacted zones are formed in underdrained or undrained parts of the delta.

The two zones of a delta are:

• Proximal zone, where growth faults will develop preferentially

• Distal zone with shale domes and ridges

Growth Faults Growth faults are also known as synsedimentary or listric faults. They possess a curved fault plane which is invariably concave towards the basin. This plane is nearly vertical in its upper part, then tends gradually to conform to the dip of the strata as its slope decreases towards its base. The downstream compartment displays thickening of the sediments in the form of a “roll-over” (compensation anticline) near the fault.

Although the importance of gravity in the development of growth faults is undisputed, trigger mechanisms are still open to debate. Basement tectonics, gravitational slumping of the sediments, salt or clay diapirism, differential compaction or a combination of these factors have all been suggested. Crans et al (1980) showed that during compaction, clays could slide down under own weight on a slope of less than 3deg. Lowering of the downdip compartment creates a surface depression that traps sediments. Their additional weight encourages further slipping. The slip plane is itself seated in an incompetent layer.

The base of the updip compartment of growth faults often includes a ridge of undercompacted shale (residual shale mass) resulting from differential compaction.

The preferential site for hydrocarbon accumulation is the rollover structure of the downdip compartment against the fault. If such structures are drilled, there is always the risk of crossing the fault and penetrating the ridge of undercompacted shale, thus risking a sudden rise in formation pressure.

Shale Diapirism Shale domes are the result of intrusive flow from underlying layers (shale diapirism). They are always undercompacted, and therefore abnormally pressured.

Shale domes are formed by processes similar to those which form salt domes and the following pressure anomalies are likely to be generated:

• Paleopressure due to uplifting previously deep-lying formations to shallower depths

• Confinement of pierced layers

• Isolated “rafts” on the top of the diapir. Because the overburden pressure transmitted to such isolated formations is omnidirectional, significant overpressure will develop within them (salt domes)

• Pressure transfer from the undercompacted clays to the pierced reservoirs


• Osmotic effects due to raised salinity in the water of formations close to the salt dome

Subduction Zones Argillaceous sediments are often buried rapidly in geosynclinal zones and in subduction zones where two tectonic plates converge. Very fine-grained sediments from the deltas accumulate on very thick beds in the rapidly subsiding arc foredeep. They are rapidly buried and come under the compressive deformation of the tectonic accretionary prism.

Undercompacted argillaceous layers are favorable to the development of overlying deformation because they act as lubricants, amplifying the movement. Decollement, the final compressive stage allowing overthrust to occur, depends on frictional forces at the base. These forces are cancelled out in an incompetent argillaceous environment, as undercompaction facilitates overthrusting.

Conclusion

Diapirism Halokinesis or Salt diapirism is the result of the plastic behavior of the salt. Massive salt has the ability to flow under a certain yield stress or mobility pressure.

Implications Mobile salt represents a pressure that has to be controlled in well bores, usually by drilling fluid density.

The mobility pressure reflects the overburden pressure once the internal yield stress is passed and this pressure is transmitted in all directions.

Salt can flow into a location and create a permeability barrier confining pressures, and also flow away from an area exposing other reservoirs to permeable formations enabling normalization of gradients.

When salt flows it finds areas of weakness where it displaces, cuts through and uplifts overlying sediments in various diapiric forms such as domes and walls.

Effects on Pore Pressure Gradients Effects on pressure gradients can be various and complex:

• Contamination of pore fluids: Pore fluids of formations near the intrusion will have an increase in the concentration of dissolved salts. There will be an increase in pore water density and possible acceleration or escalation of osmotic activity.

• Rafters: Large rafters of formations can become engulfed within the intrusive salt body and entirely sealed off from the normal hydrostatic gradient. The mobility pressure is transmitted to all the fluids within the enclosed rafter and the result is near lithostatic pore pressures.

• Associated tectonics: includes uplift of formations, lateral discontinuity of formations and induced faulting.

• Deformation of sediments

Porosity can be increased or decreased by deformation of the sediment along axes other than the vertical axis of overburden.


Summary Of Tectonic Effects The uplift of a sealed volume by any process will transport the pressure at which the volume was sealed, up through the geological column. The burial of sealed volumes of pore fluid has also been cited as a geopressuring mechanism.

The following factors that affect the formation of geopressures:

• Paleo-factors: depth at the time of sealing, paleo geothermal gradient, pore fluid composition

• Current factors: current depth, pressure of confinement, geothermal gradient, pore fluid composition

Tectonic mechanisms may be summarized as follows:

Extension > open fractures > pressure dissipation

Easy expulsion of fluids > compaction > normal pressure

Compression difficult expulsion > undercompaction > abnormal pressure > possible hydraulic fracturing > expulsion > compaction

Pore Fluids And Confinement In most circumstances the pore fluids will consist of a mixture of connate waters of variable salinity, with possible volumes of hydrocarbons, oil and/or gas. Also the waters may consist of differing ionic brines, and a gas portion may have appreciable volumes of H2S, CO2 or other non-hydrocarbon gases.

Gases are subject to the standard chemical laws relating to gases:

Boyle’s Law: states that the volume of a gas varies inversely as the pressure to which it is subjected (temperature constant)

Charles’ Law: states that the volume of a given mass of gas is directly proportional to the absolute temperature

Miscellaneous Processes

Mud Diapirs and Sandstone Dikes These features are overpressure phenomena that result from rapid deposition of sediments that are relatively mobile. The phenomenon is often associated with biogenic gas activity, which further facilitates movement. Diapirs and mud volcanoes are considerably more common than sandstone dikes due to the high water content and the low shear strength of marine clays. Mud volcanoes are the ultimate manifestation of clay diapirism. They tend to be situated along large, active transcurrent faults, such as Azerbaijan, New Zealand, Caspain Sea etc. If gas is present it intensifies the process by increasing differential pressure.

According to Fertl (1973) after Ganssers (1960) the following apply to diapiric activity in clay bodies:

• All current volcanoes are associated with late Cretaceous or younger sediments

• The sediments are marine

• Gas and connate water are invariably present

• The plastic beds are overlain by more competent lithologies


Implications: at a particular stage in development of a rapidly subsiding basin, massive shales can become pressured to lithostatic levels. This necessitates the release of this pressure that can take the form of mud volcanoes in extreme cases.

Contemporaneous Faulting These faults are compaction-related phenomena that develop as sedimentation takes place. Examples are the complexes of listric faults that develop in deltaic sediments during prograding sequences. These faults can seal reservoirs laterally and inhibit the migration of fluids with further compaction.

Possible results of listric faulting:

• A seal is formed to clay pore water expulsion.

• Depending on the rate of sedimentation there may be an associated volume increase across the faults.

These faults are believed to be curved with great thickening of the down thrown sediments. These masses of clay sediment form vast undercompacted bodies supporting the overlying more competent and normally compacted lithologies that may be considered to be “floating” on the overpressured formations. Theories of basinal thrusting cite these flattened out bases of these faults as potential thrust planes aided by highly pressured plastic formations.

Permafrost When water changes into ice its volume increases. Water contained in surface sediments of permafrost regions is frozen, but in certain conditions, pockets of ground surrounded by permafrost can exist in an unfrozen state. Such pockets are known as taliks. But ice is quite impermeable, so that if a talik does freeze, permafrost impedes expansion and encourages abnormal pressure to develop.

Although the phenomenon is very localized, it must be taken into account when drilling in regions of permafrost.

Production and Charging

Repressuring Older producing fields are sometimes subject to shallow formation pressure charging resulting from deeper level formation pressure migrating upward around poor or damaged cement jobs or corroded casing.

Underground blowouts also introduce higher pressures into shallow formations.

Excessive equivalent mud densities can induce supercharging of permeable formations.

Piezometric Fluid Levels The down dip segment of a monoclinal aquifer will be subject to an artesian pressure, due to an extended hydrostatic head.

Conclusion Identifying the cause of the over pressure is generally a delicate matter, and calls for a sound knowledge of the geology of the region. Below are the points that need to be considered:

• The crucial importance of seals and drains in maintaining abnormal pressure


• Time is the determining factor in fluid dispersal (that’s why overpressure zones are commonly found in young sedimentary sequences)

• High pressure may result from a combination of various causes

• Most high-pressure zones are more likely to be found in clay-sandstone sequences

• The lithological changes which some of the causes bring about can be used for detection purposes during drilling

The characteristics and typical environments of the various origins are summarized in the following table:

Origin Characteristics Environment

Overburden effect Major contribution to the existence of abnormal pressure

Leads to undercompaction

Geographically widespread

Long-lasting effect linked to sedimentation rate

Young clay-sand sequences:

• Deltas

• Passive continental margins

• Accretionary prisms of subduction trenches

• Evaporite deposits

Aquathermal Expansion of water

Requires a very well sealed environment

Temperature plays a major role

May be superimposed on the overburden effect

Closed system w/ steep geothermal gradient

Volcanic zones

Tectonics Very varied characteristics due to redistribution of masses and fluid pressures

Faults, folds, overthrust faulting, clay diapirism, salt diapirism

Lateral pressuring

Cracking of organic matter and hydrocarbons

Cracking = increased volume

Develops either in undercompacted environments or independently

Important role of temperature

Sediments rich in organic matter

Clay diagenesis Second order cause. May be superimposed on the overburden effect

Geothermal gradient plays a major role

Significant smectite proportion in the original deposit

Thick argillaceous sequences

Osmosis Rare second order cause

Transient, unstable phenomenon

Difficult to prove

Interlayering of clay with lenticular reservoirs of contrasting salinity

Miscellaneous:

Sulfate diagenesis

Special cases: localized, transient phenomena

Evaporite deposits

Chalk


Origin Characteristics Environment

Carbonate compaction

Permafrost

Talik / permafrost

Table 4 Origin and characteristics of different environments.


Overpressure Detection Techniques

Introduction There are numerous techniques available to the pressure engineer, which assist in the prediction, detection and evaluation of overpressured formations.

Normal Compaction Trend In order to evaluate abnormal pressure linked to compaction anomalies it is necessary to define a normal compaction trend for reference purposes.

Compaction data will give a linear trend on a logarithmic plot of porosity vs. depth. Argillaceous sediments must be used for determining this relationship.

The following influences the slope of a normal compaction curve:

• The mineralogy and relative proportions of the phyllosilicates in the clay

• The non-argillaceous mineral content (quartz, carbonates, organic matter, etc)

• The sedimentation rate, which conditions the texture by means of the spatial arrangement of particles. Porosity is lower if sedimentation occurred at a lower rate.

• The geothermal gradient

Characteristics of Undercompacted Zones

Transition Zone

Diagenetic Cap Rock

List of Overpressure Detection Methods Below is a tabulation of methods used to aid the engineer in predicting and evaluating overpressured zones.

Method Phase of Operation

Predictive Methods

Regional geology

Geophysical methods

Before drilling

Parameters while drilling

Drilling rate

D exponent

Sigmalog

Normalized drilling rate

While drilling (real time)


Method Phase of Operation

MWD

Torque

Drag

Mud parameters

Pit levels

Mud flow

Pump pressure

While drilling (real time)

Mud parameters

Mud gas

Mud density

Mud temperature

While drilling (lagged)

Cuttings analysis

Lithology

Shale density

Shale factor

Shape, size, abundance

Cuttings gas

While drilling (lagged)

Wireline logs

Resistivity

Sonic

Density/neutron

Gamma ray

After / while drilling

Direct pressure evaluation (formation tests)

DST

Wireline formation tests (RFT)

After drilling

Well seismic check

Checkshot

VSP

After drilling

Table 5 Table of overpressure detection methods.

Pre-spud Data Geophysical data

Geological prognosis

Nearest offset well data

Piezometric Maps


Geophysical data The geophysical methods used are:

Seismic velocity (most frequently used)

Gravity (rarely used)

Magnetic survey (rarely used)

Seismic Methods

Very High Resolution Seismic A technique generally used for studying the seabed. Its depth of investigation is limited to 50-100 meters. Its resolution range is down to less than a meter. It is important for platform anchorage and can also reveal gas pockets and dismigrations (gas chimneys) close to the surface.

High Resolution Seismic This has a resolution in the 1-5 meter range and a depth of investigation between 1000-1500 meters. It is an adjunct to conventional seismic methods in the superficial blind spots of the “twilight zone”.

Conventional Seismic Methods It has a lower resolution of 5 to 50 meters and a depth of investigation extending to down several thousand meters. It is the most important source of information about abnormally pressured zones in the vicinity of wells to be drilled.

The seismic section can reveal gas zones (bright spots), faulting and diapirs. It provides an indication of lithologies and facies and zones of undercompaction.

Analysis of internal velocities by deduction from seismic velocities is particularly useful when assessing the development of compaction and the sand-clay ratio.

3-D Seismic The 3D method gives a subsurface scan on a regularly spaced grid of points instead of a pattern of lines. Acquisition is done through a line spacing of 50-100 meters instead of wide seismic loops. This results in establishing the geometry of structures with greater accuracy and the lateral acoustic variations of a given seismic horizon can be defined in 3D.

Seismic “S” Wave The above mentioned techniques are concerned with primary or compressional seismic waves (“P” waves), in which particles move in the direction of propagation. ??????????

Interpretation

Reflection Analysis The classic way of representing transit times is by means of a seismic section. By analyzing the subsurface continuity od seismic horizons with the external shape and internal parameters of reflections (their amplitude, phase and frequency), it may be possible to establish seismic facies corresponding to the depositional setting. By using seismic wave train sequences and facies to identify sedimentation patterns it is possible to arrive at an overall distribution of lithologies. This is called seismic stratigraphy.


Undercompacted zones can be revealed by the nature of low-frequency reflections. If these are poor or reflections are absent (blind zone), this could mean a monotonous sequence of undercompacted clays. The transition zone, limiting the undercompacted series may sometimes be revealed by a few high amplitude reflections followed by an apparent low frequency wave train.

These criteria for the exploration of undercompacted zones are, however, not conclusive and may be due to other processes such as salt diapirism, a compact uniform series, reefs, laccoliths, etc.

However, if these indications occur together, they strengthen the likelihood of undercompacted clay being present, esp. if the correlations or regional geology suggest a comparable interpretation.

It must be emphasized that the time section produced by seismic techniques can be distorted with respect to the true picture at depth if the structure is complex. In such cases, 3D seismic methods can give a more precise picture of deep-lying structure.

Interval Velocities

Where structures are not very complex and the series is sufficiently thick, it is possible to evaluate transit times and calculate the propagation velocity for each interval in the formation.

This velocity is a function not only of the density, porosity and fluid content of the rocks, but also of their elastic properties and stress conditions.

Two aspects of velocity analysis are useful in detecting pressure anomalies:

• Establishing velocity/depth curves translated into ∆t transit times (pseudo-sonic log). Undercompacted zones by virtue of their lower density, higher porosity and abnormally low vertical stress have lower velocities.

• The interval velocity which is dependent on the lithology and on its state of compaction. For normal compaction conditions, velocity gradually increases with depth.

The velocity of an interval is a function of its maximum burial, but for a tectonically inactive subsident basin, velocity may be linked directly to depth. The curve of normal compaction when velocity is expressed on a logarithmic scale is a straight line, and is known as the compaction trend.

There are several laws defining this relationship, among them is the Chiarelli-Serra Law:

V = AeBZ

Or

LogV = A + BZ on a semi-logarithmic paper

Where,

V = interval velocity

A and B = constants

Z = depth

Faust’s Law introduces the factor of geological age into the formula by postulating that velocity increases uniformly with age. The linearity of this relationship is only valid for a given geological period.

LogV = A + B LogZ + C logT

Where,

C = constant

T = geological time


Quantitative pressure evaluation may be carried out using either the equivalent depth method or the Eaton method.

Estimating The Sand/Shale Ratio This method is used successfully in deltaic zones. It is based on the fact that, on a semi-logarithmic plot of ∆t vs depth, the points for normally compacted clay are the slowest. A trend line passing through these points represents the clay trend. Another line drawn parallel to it based on a velocity 25% higher defines the sand trend. The position of the measured velocities in between these trend lines gives an estimate of the sand/shale ratio.

Reliable interpretation of velocity analyses relies on information about a number of criteria depending on terrain, signal quality and subsequent processing:

• Unforeseen changes in lithology

• High angle dip

• Faulting

• Complex tectonics

• Static corrections

• Normal move-out corrections

• Multiple reflections

• Abnormal seismic paths

Amplitudes

The amplitude of the signal reflected from the contact between two layers depends on the interface reflection coefficient. This coefficient is a function of the contrast between the acoustic impedances of each layer. Acoustic impedance is the product of the density and the acoustic velocity.

The presence of gas sometimes creates significant amplitude anomalies. Studying such anomalies is the very basis of detecting hydrocarbons directly from seismic data.

On the other hand, lateral amplitude variations can also be due to lateral facies changes that must be taken into account when extrapolating on the basis of reference wells.

Gravimetry This method is generally used to investigate the major structural elements of a basin and the configuration of its underlying basement on a regional scale.

Density contrasts in geological formations create gravimetric anomalies. This can arise from a number of causes occurring at different depths, and are therefore complex to interpret. On the other hand, using gravimetry in conjunction with seismic techniques can help resolve uncertainties of either a gravimetric or seismic nature.

Using a time section with identified seismic horizons, it is possible to calculate the gravimetric effects caused by geological formations of known geometry and density. Subtraction reveals gravimetric anomalies associated with geological phenomena which do not show up on seismic sections.

Since undercompacted formations can display density contrasts amounting to several tenths g.cm3, it is reasonable to assume that they can be revealed by gravimetric techniques provided the volume of the sediments concerned is big enough.


Onshore gravimetry is usually of a higher resolution than that offshore.

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This, esp. the seismic velocity profile, gives an overall, although often inaccurate, indication of formation lithological type, tops and possible overpressured zones. The velocity of sound waves increases with depth for normal compaction for any lithology. It also becomes more inaccurate with increasing depth, it frequently predicts formation tops too high or too low, it may be extremely misleading without knowledge of local geology. It may detect structures that do not exist or, conversely, miss formations or structures that do exist.

The usefulness of the seismic ve locity survey lies in its detection, by velocity anomalies, of overpressured zones. It must be kept in mind that seismic profiles can be very easily misinterpreted. When supported by offset well data, esp. geology, the seismic profile obtains greater reliability in predicting / detecting overpressured zones.

Other geophysical methods that assist in predicting overpressured zones include gravity and magnetic surveys.

A plot of seismic velocity, combined with knowledge of local geology, will yield qualitative expectations of required mud weight increases necessary to balance formation pressures.

Offset Well Data It is information derived from the drilling and testing of a well (s) in the vicinity of the proposed well.

Identification of geological environments of deposition often yields important clues as to problems and pressures that may be encountered.

For example: For deltaic environments we can expect the following:

• A thick shale, siltstone, sand sequence with thin, shallow, high pressured sand lenses

• swelling clays responsible for tight hole and high rotating torque

• the development of at least one major zone of overpressure accompanied by several smaller zones

• a pressure reversal at depth and the presence of growth faults and thick shales acting as stratigraphic / structural traps.

The more wells drilled in the structure or within proximity, the better the estimates of formation pore pressures and fracture gradients.

Piezometric Maps Piezometric maps give an appreciation of abnormal pressure distribution factors.

While Drilling Data

Introduction By far the most relevant and significant data for overpressure prediction, detection and calculation becomes available during the drilling of the well.

Below is a summary of the changes to the numerous indicators as an overpressured zone is approached or drilled:


Pressure Indicator Change in Value Reason for change

Drill rate (ft/hr) Increases Formation is undercompacted, differential pressure at the bit is approaching zero

D exponent Decreases As ROP increases, d-exponent decreases, reflecting overall increased formation drillability

Total gas Increases Reflects greater volume of in situ gas

Background gas Increases Greater volume of in situ gas, loss of overbalance

Connection Gas increases Reflects loss of overbalance as formation pressure approaches mud hydrostatic

Torque increases Often due to loss of overbalance, causing hole to come in around collars and stabilizers.

Drag increases Reflects hole instability due to loss of overbalance

Fill increases Hole instability

Flowline density decreases As overbalance is lost, formation fluid contaminates drilling fluid

Flowline viscosity increases Formation fluid is often hotter, containing mineral hardness, causing mud fluctuation

Flowline salinity increases The more highly saline formation fluid enters the well bore as overbalance is diminished.

Shale density decreases Reflects undercompaction in an overpressured environment.

Cuttings shape, size increases Reflects hole instability, less gouging of formatic presence of cavings.

Presence of gypsum increases In an evaporitic environment, anhydrite rehydrates to gypsum in the presence of water, being both a cause and a result of overpressure.

Flowline temperature increases Overpressured zones, possessing greater than normal pore fluid, act as thermal insulators.

The standpipe pressure and pump rate exhibit changes in downhole conditions and may consequently be utilized to determine loss of overbalance.

Real Time Drilling Methods

Drill rate If all else is equal, for a particular lithology, ROP will decrease with increasing depth in a normally pressured environment. This is because most sedimentary lithologies become denser hence possess greater compressive strength, with increasing depth. An overpressured formation tends to be undercompacted with respect to its depth making it easier to drill out. But the association is


not necessarily definite due to the numerous factors that are too random and affect drill rate. The following factors all have a major influence:

1. Lithology

2. Compaction

3. Differential pressure

4. WOB

5. RPM

6. Torque

7. Hydraulics

8. Bit type and wear

9. Personnel and equipment

Before taking a look at he above factors, a few comments are in order about how the bit operates downhole at the rock face. The effect this has on the ROP will be seen later on.

Formation Breakdown Mechanism Of the Bit The efficiency of a tooth bit depends on its ability to shatter rock and remove fragments from the bottom of the hole. The process uses the impact of each tooth on the rock face to form a series of small craters.

There are four stages of the process:

Impact – Bit tooth pressure on the formation increases to the limit of the rock’s mechanical strength

Wedge formation – Once the mechanical strength limit has been exceeded, the rock forms a pulverized wedge beneath the tooth. The wedge compacts and horizontal stress develops.

Fracture – horizontal stress increases until the rock fractures and forms a crater.

After fracture – the crater consists of fractured rock.

The ease with which fractured rock is removed from the crater depends on the differential pressure at the bit and how much friction is present to stop fragments moving along the fracture.

If the mud weight is too high, the increased differential pressure leads to high friction along the fractures, causing fragments to drop.

Lithology This is a major factor controlling ROP changes. The drillability of a rock depends on its porosity, permeability, hardness, plasticity and abrasiveness, as well as the cohesion of its constituent particles.

All else being equal, a change in ROP reflects a change of lithology. Cuttings analysis must be cross-checked against changes in ROP. When examining compaction, ROP analysis is in two stages. The first stage identifies argillaceous beds and the second examines how penetration rate changes within them.

It is common that an increase in silt content can reduce shale drillability up to a certain point, after which drillability improves again.

Unlike most parameters, it seems unlikely that such changes in lithological detail will ever be quantified. They depend on the experience of the geologist.


Compaction The compaction of a sediment is reflected by its porosity, that is to say the extent of matrix grain-to-grain contact.

With unchanging lithology and no changes in any of the other variables, ROP will gradually decline as compaction increases. The reverse happens if there is undercompaction. The relative change in ROP is a function of the degree of undercompaction.

Differential Pressure Differential pressure (∆P) is the difference between the pressure exerted by the mud column and the pore pressure.

For any given lithology ROP slows as ∆P increases and vice versa. For example, according to Goldsmith (1975) a ∆P of 500 psi (35 kg/cm2) can cause the ROP to slow down by around 50%.

In undercompacted shales, lower ∆P and increased undercompaction cause higher ROP. Some authors believe that compaction has a negligible effect, implying that there must be a direct relationship between ROP and ∆P. This hypothesis is probably only valid over short intervals.

WOB Changes in WOB have more effect on ROP than any other drilling parameter.

Generally speaking, ROP increases with WOB.

A minimum WOB, called the threshold weight, is needed to get drilling started. This could be negative in the case of a slightly consolidated formation, since jetting alone is sufficient to ensure penetration.

Above the threshold weight ROP rises almost proportionally with WOB. Above a certain point called the flounder point the ROP stops rising since the bit teeth become jammed in the rock. The idea of a flounder point is valid only for soft formations.

RPM It was initially thought that the relationship between ROP and RPM was linear. But Vidrine & Benit (1968) and also Prentice (1980) considered the relationship exponential:

R = Na

Where,

R = ROP

N = RPM

a = exponent defined empirically on the basis of wellsite tests for a given lithology and WOB

Prentice’s graphs have an exponential appearance because the bit teeth gradually spend less time in contact with the formation as RPM increases.

Later research has shown that the shape of the curve depends on lithology (see Figure …….). The relationship in soft formations is nearly linear, but the harder the rock in question, the shorter will be the linear part of the graph.

Torque This parameter is never taken into account directly, since it is very difficult to assess. Surface measurements can’t separate bit torque from string torque. As depth increases, so does the amount of contact between the borehole walls and the drillstring, so that torque gradually increases too.


The use of MWD will probably allow the relationship between ROP and torque measured at the bit to be established.

Torque at the bit is a measure of the amount of energy needed to break down the rock. This energy is proportional to the product of torque and RPM.

An anomalous rise in torque can have a number of causes. One of these can be a change in differential pressure associated with entering an abnormally pressured zone.

In a negative differential pressure regime, the mechanical behavior of shales may cause torque to rise in either of two ways:

1. By swelling of plastic clays, causing a decrease in hole diameter

2. By an accumulation of a large amount of cuttings around the bit and stabilizers

The plastic state of clays in superficial formations may cause the bit to ball-up. If balling-up occurs at greater depths, it may indicate that the bit is entering a transition zone. A reduced and steady torque usually indicates balling-up.

Torque must be thought of as a second order parameter for diagnosing overpressure.

Hydraulics The effect of hydraulic flow on ROP varies for different degrees of consolidation. The effects of hydraulic flow on ROP are not fully understood at the moment.

It still worth noting that a change in the flow rate can cause a change in the ROP.

Mud properties can also affect ROP. How they do this is not easy to discover, since many mud characteristics are interdependent.

Viscosity Effective cleaning of the bit face is particularly dependent on mud viscosity. A low-viscosity, turbulent fluid is more effective than a viscous, laminar one. Low viscosity at the bit may improve penetration.

Water-loss (Filtration Rate) It is believed that in some cases water-loss can affect penetration rate. This happens as follows: fluid percolates into the fractures caused by the bit teeth and helps to expel rock fragments. This may be mainly because water-loss helps bring mud pressure and pore pressure into equilibrium.

Suspended Solids Solids can have the effect of reducing immediate water-loss, and in certain cases this can limit ROP.

If there are many solids in the mud, penetration can be impeded because the teeth are prevented from making clean contact with the formation.

This effect is thought to be relatively insignificant.

Bit Type And Wear Optimizing the ROP chiefly depends on matching the bit type to the formation.

The usual critical parameters for tri-cone bits are:

• Tooth height and spacing

• Amount of axial offset per cone


• Resistance to wear

Bits are classified by the hardness of the formations they are designed to drill.

A major change in bit type distorts the value of the drilling rate and alters drilling performance in the event of changes in lithology. This is a hindrance when interpreting progressive changes in the ROP.

For these reasons, when approaching undercompacted zones the bit should not be changed to a type other than the one already in use.

At the end of its useful life, a bit can mask changes in lithology, compaction or differential pressure due to a decrease in ROP under the effects of wear.

Tri-cone bit-wear affects both teeth and bearings. Tooth bits undergo gradual tooth wear, but bearings can wear out quite abruptly once they are no longer water-tight. Insert bits tend not to wear out gradually, but instead their inserts break off in hard, abrasive formations. Insert breakage depends on how well the bit is matched to the formation, on the RPM and on vibration.

A diamond bit proceeds by making scratches or grooves, not by cratering. Relationships between ROP and drilling parameters follow different rules. RPM and possibly hydraulic flow are the main factors and their relationship with the ROP is linear.

Personnel And Equipment

Conclusion Under ideal conditions in shales, ROP can be thought of as dependent on porosity, and therefore a way of detecting undercompaction. In normal use, however, many parameters affect the reliability of the measurement. To use it properly we have to employ drilling models, such as the Dxc, the Sigmalog or normalized drilling rate.

D Exponent The d and dc exponents (Dx and Dxc) were developed to help in correcting or “normalizing” the drill rate for the effects of changes in WOB, RPM, hole size and mud weight with respect to the recognized effects of differential pressure and compaction on ROP.

Jordan and Shirley (1966) developed the d exponent method in the mid-60’s for overpressure detection in the US Gulf Coast. The commonly accepted equation is for Standard US units:

d = log (R/60N) / log (12W/106D)

For Standard Metric Units:

d = (1.26 – log (R/N)) / (1.58 – log(W/D))

Where, R = ROP (ft/hr)

N = RPM

W = WOB, lbs

D = bit size, in.

Where lithology is constant, the d exponent gives a good indication of the following:

• The state of compaction



Calculating d exponent in shales makes it possible to follow their stages of compaction and reveal any undercompaction.

For normally pressured sediments, the d exponent yields a trend of increasing values with depth; a trend of decreasing values is often indicative of increasing pore pressure. If so interpreted, and if plotted on semi-log paper, the difference between observed and expected values of d exponent represents the magnitude of the pore pressure.

Corrected d exponent The d exponent may be corrected and normalized for changes in mud weight and/or ECD by the following:

Dxc = d exponent x (normal pressure (ppg) / ECD or mud weight (ppg)).

It is important to realize that this modification does not correct the d exponent for the overbalance. The dc exponent is much more sensitive to differential pressure fluctuations. It is particularly sensitive to large changes in mud weight with no associated changes in pore pressure. Therefore, it is much more indicative of pore pressure changes if the differential pressure is small. An important benefit of this modification is a smoothing of the data facilitating the positioning of trend lines.

The dc exponent could be possibly modified further and have the ECD corrected for cuttings load as the denominator. This may be useful in situations of rapid top-hole drilling or inadequate flow rates and hole cleaning.

dc = d x (Pn/(Ecf + (ECD-MW)))

Where Ecf = mud weight with cuttings – mud weight, i.e. the effective static mud density in the annulus.

Factors That Influence The Dc Exponent Let us first review the factors that influence the dc exponent:

1. Mechanical and drilling fluid parameters included in the dc exponent formula

2. Other mechanical parameters

• Bit type / drilling action

• Bit wear

• Bottom hole assembly configuration

• Hole angle

• Junk in the hole

3. Formation parameters

• Unconformities

• Lithological variations

4. Drilling fluid parameters not in the dc exponent modification

• Bit hydraulics


Discussion

Mechanical Parameters included in the d exponent formula


Turbine Motors When a turbine motor is run, where minimal bit weights and high RPM are used, the dco values are deviated and these values should be ignored. In this case it is futile to shift the trend line because:

1. The drilling action associated with the turbine run is controlled and not influenced by the formation’s drillability.

2. The hole angle is being changed and it is very difficult to fit or shift a trend line to deviating well data.

3. The turbine run might be short.

This is not to say that trend line shifts are never appropriate for turbine runs. Along, straight run of a similar drilling action on a competent formation may well require a shift.

It is possible in situations of extensive controlled drilling, such as ROP restraint to facilitate good hole cleaning, that trend shifts may help in the interpretation. Any such shifts must be considered as temporary and a return to a normal drilling action will require a return to the original trend.

Hole Section Change It is often observed that the calculated dc exponents are quite different above and below a change in hole size. All of the basic formula inputs are usually changed at such a stage.

There is no easy way of assessing the pore pressure in such a situation. The bit weight per bit area expression in the formula should accommodate the change in hole size or the model is invalid. Sometimes the established trend line should be continued in anticipation of the pore pressure increasing.

Other Mechanical Parameters

Bit Type / Drilling Action

The d exponent was formulated for the drilling action of mill tooth bits. However, in recent years the method was applied to insert, PDC, Stratapax and diamond bits. When there is a change from one type of drilling action to another there is usually a noticeable change in the dco. Therefore, it is usually necessary to shift the trend line.

Another aspect of bit type is whether the bit in the hole is suitable for the formation being drilled. Such a situation may require a temporary shift in the trend line. However the data obtained during such a situation will be poor and should be subsequently neglected.

Bit Wear Dulling of bit teeth, particularly on rock bits, occurs on more competent formations. It is not usually evident in shales unless they have reached maximum compaction. This is unusual in Tertiary sediments, but may occur in older formations. It is often encountered in clastic limestones and is usually very evident on the dco plot. It is not normally necessary to shift the trend but interpretive adjustment may be necessary.

Ways Of Correcting For Bit Or Tooth Wear

There are several ways of trying to correct for the effects of bit wear on d exponent. They usually derive from two different approaches based on an inversely proportional relationship between ROP and a function of tooth wear as follows:

R = 1 / (F (H))

Where,


R = relative ROP = R1/R0 with

R1 = ROP corresponding to bit wear H

R0 = ROP corresponding to zero bit wear

F (H) = bit wear function

H = tooth wear (on a scale of 0 to 1); bit wear is usually noted on a scale of T1 to T8 at the wellsite – e.g. T4 = 4/8 = 0.5

Giving

R0 = R1 x F(H)

The value of R obtained by these methods is substituted in place of the unadjusted value of R in the d and dxc equations.

The function F(H) differs in the two methods as follows (see Graph/s ……..):

Galle and Woods correction method (1963)

F(H) = square root of (0.93 x H2 + 6H +1)

Giving,

R0 = R1 x the square root of (0.93 x H2 + 6H +1)

Vidrine and Brent correction method (1968)

F(H) = 1 + 2.5H

Giving,

R0 = R1 x (1 + 2.5H)

There is a slight difference between the two methods. These methods have only limited use, however, because the degree of bit wear cannot be known with certainty while drilling is in progress. Either of the following relationships can be used instead (see Figure ,,,,,,,,,,,,):

• A linear relationship between wear and total rotating time or between wear and RPM

• A linear relationship between wear and footage drilled

Bit wear trends are established for each bit. Wear is then estimated while drilling, by reference to the trend for the previous bit used in comparable circumstances.

Example:

A graph is made of the previous bit run:

Previous bit T6 = H0 = 0.75

Total rotating time: t0 = 20 hrs

Tooth wear axis

Total rotating time or footage axis Prev bit


Current bit: rotating time: t = 12 hrs

You can graphically calculate the bit wear from the current graph or use the following formula:

H = H0 x (t/t0)

H = 0.75 x (12/20) = 0.45

The bit wear function F(H) was established for tooth bits. For other types of bit some authors suggested applying a correction coefficient K to F(H):

Tooth bits: K=1

Insert bits: 0.4 < K < 0.6

Diamond bit: 0 < K < 0.2

No bit wear correction: K = 0

It should be noted that it is unsatisfactory to introduce correction coefficients for other bit types using a relationship based on the wear characteristics of tooth bits, because the wear processes involved are quite different.

Discussion

Bit wear corrections are frequently used by mudlogging companies, but are not entirely satisfactory for the following reasons:

1. Any relationship between ROP and wear is not realistic.

2. Bit wear formulae do not take lithology into account. In particular they ignore the hardness and abrasiveness of the formation being drilled.

3. Bit wear evaluation while drilling takes no account of WOB.

Bottom Hole Assembly Configuration The stabilizer of the BHA may support some of the drilling weight and result in erroneous data. This will be particularly evident in deviated wells. The phenomena may also occur in plastic formations such as salt or highly pressured shales/clays. In this case the shales/salts etc will support the drill string and in the process makes dc exponent evaluation very difficult.

Hole Angle When a directional well is being drilled, the weight recorded at the surface is greater than the actual weight being applied at the bit due to string friction. As deviation increases the vertical component of the drilling weight is decreased. Also the vertical section of he interval for averaging the drilling parameters is decreased.

The d exponent values will be higher than their true value unless true WOB values are available from the MWD measurements.

It is not possible to fit a straight -line trend to a dco plot through a section when the hole angle is being increased or decreased. But if the hole angle is consistent and the plot is against TVD the trend line can be shifted horizontally to fit the deviated well data.

It should also be noted that the compaction trend must be established using vertical depths and not drilled depths.

Need !!!!! Examples on trend line and hole deviations.

Junk In The Hole


The ROP will naturally be reduced by debris such as broken teeth or cones on the hole bottom. There should be no adjustment of the trend line for such a situation.

Formation Parameters

Unconformities Permanent trend line shifts are valid when the bit drills through a major unconformity. The drillability trend of shales emulates the compaction profile, crossing an unconformity into older more compacted sediments may reduce the ROP and a shift of the trend line will be necessary.

Actual occurrences of contrasting compaction histories in adjacent formations are rare in oil prospecting areas.

Example needed.

Lithological Variations

The dc exponent technique is only valid for shales and clastic limestones. Within this lithological limitation there are further limitations of composition and structure.

Composition

The user must select shale and limestone data points of similar composition and mineralogy. It is unlikely that this problem will occur in an area of consistent sedimentation such as subsiding marine basins or deltaic environments. However, it is frequently the case in areas of shelf sedimentation such as the Arabian Gulf. In this area it is possible to have differing trend lines for shale, argillaceous limestone, marly limestone and grainstones: all on the same dc exponent plot. However it is unnecessary to consider shifting of trend lines for different composition.

Structure

The structural influences on shale and limestone drillability are those of porosity and induration. The very porous oolitic and pelletal limestones may well give erroneous increases in calculated pore pressures. Such situations may require individual interpretation, and a temporary shift of the trend line may be necessary.

At shallow depths sediments are less consolidated and will be washed out ahead of the bit by hydraulic forces. Shales in particular behave in an elastic manner. Therefore the drilling parameters that constitute the dc exponent, will not be entirely responsible for the ROP. Such data can’t be interpreted for the positioning of the trend lines or pore pressure. It is important to base the trend line upon properly indurated sediments.

Drilling Fluid Parameters

Bit Hydraulics Circulation rates may influence the ROP if there is considerable change. For example from good hole cleaning to annulus overloading. However the major hydraulic influence on ROP is at the bit. Bit hydraulic parameters are optimized to ensure all cuttings are removed from the bit teeth. This enables the bit to perform to its optimum efficiency, depending upon:

• The WOB/RPM relationship

• It’s suitability for the formation

• The degree of wear on the various bit parts

• The differential pressure between the formation at the bit and the ECD


Poor bit hydraulics will result in reduced ROP and appropriate trend line shifts may be a temporary necessity.

Differential Pressure As the overbalance between the ECD and pore pressure increases, the ROP decreases. There is no easy way of assessing the pore pressure in such a situation. A temporary shift in the trend line will be necessary to adjust for a mud weight increase. When the pore pressure increases, the original trend line should be used for pressure calculations.

When drilling with an overbalance in excess of 500 psi it is observed that the dc exponent is insensitive to changes in overbalance. It becomes very difficult to detect changes in the overbalance between say 800 psi and 1500 psi. the impact of this is that pressure reversals to decreasing pore pressures will go unnoticed and result in hole problems such as differentially stuck pipe or mud losses.

Calculating Pore Pressure Values from Dc Exponent Values for pore pressure may be calculated utilizing several methods:

1. Eaton’s: p = S – (σ x ((dc)o/(dc)n))1.2 (check formula if: (σ x ((dc)o/(dc)n) 1.2))

2. ∆P ratio: p = N x (dc)n/(dc)o

Where: p = pore pressure ppg

σ = S-N

N = normal pore pressure ppg

(dc)n = normal dc

(dc)o = observed dc

Eaton’s Method Eaton’s equation was derived with empirical data which applied known pressures to resistivity, conductivity and sonic logs from a broad range of US gulf Coast wells. The equation was then applied to the dc exponent data and found to be equally suitable. In using Eaton’s formula it should be noted that dc exponent profiles are of different character to plots of wireline data. Resistivity etc are direct measurements of lithological properties which are the result of the compaction history of the formation. The dc exponent values form a drillability curve that is similar to such compaction profiles, but the values are consequent on many more factors.

The exponential power 1.2 was found suitable to express the reduction in strength of a clay/shale formation with an associated increase in pore pressure. This power has been erroneously altered in many locations to fit (dc)o values of known data. However, the power simply expresses the response of clay/shale formations to pore pressure changes. As such the power should be suitable for all lithologies whatever the location.

Example:

Calculate the pore pressure at 1600 m using the first formula.

S = 1.85 sg

Pn = 1.04 sg

(dc)o = 0.65

(dc)n = 1.25

p = 0.801 psi/ft – (0.349 psi/ft x (0.65/1.25))1.2


p = 0.648 psi/ft = 1.50 sg

∆P Ratio Bryant in 1980 found out that the relationship p = N x ((dc)n/ (dc)o) gave him good results in the Middle East evaporite sequences. The formations containing abnormal pressure in this region are dolomites and limestones. These rocks are primarily chemically lithified and thus the normal clastic compaction relationship with drillability is invalid. The drillability in such formations is a function of rock strength and differential pressure. By establishing different trend lines for each lithology the above calculation can be made. The trend lines represent the strength of the formation and therefore they can be vertical if there is no evidence of compaction bonding. The deviation from the trend line can be considered as a reduction in rock strength.

Example:

Calculate the pore pressure at 9550 ft using the second formula.

Normal pore pressure = 8.8 ppg

(dc)o = 1.18

(dc)n = 2.65

p = 8.8 x (2.65/1.18) = 8.8 x 2.25 = 19.8 ppg

Trend Lines The trend line is critical to the evaluation of the dc exponent. It is also the means by which one controls the influences of factors not included in the dc exponent formula. There are two distinct stages of trend line manipulation:

• Trend line fitting to normally pressured data

• Trend line shifting to accommodate other influences as above.

Trend Line Fitting The facet of dc exponent that will change, from area to area or field to field , is the trend line. The slope and surface intercept will differ according to the geological history, wellbore deviation, formation thickness, etc. and it is by shifting and adjusting the trend line that the dc exponent can be properly evaluated.

The two questions the operator should ask are:

1. How will bad data appear?

2. What sort of slope will the trend line have? The slope is a function of geology and in particular the relationship of age to depth.

Example: (see pp 11-13 / 4-Drilling Models book) a well has Oligocene and Pliocene sands overlying mixed lithologies of the upper Miocene. These mixed lithologies include anhydrite, salt, sand and shales.

Applying these two questions it is evident that:

• The bad data is that which represents anhydritic shale. In the first case the ROP will be lower, and thus the dco values will be higher, than those of cleaner shale. For a sandy shale the reverse will be the case.

• In this case there is a very thick vertical sequence of tertiary sediments, particularly from the Miocene. The trend line will be near vertical. It is more steeply inclined than in an area of a large age range over a shorter depth interval.


Example (p14 Baroid books): the bad data is sandy shale which is evidenced by faster ROPs and lower dco values than for cleaner shales. The trend line is positioned so that all the bad data will be to the left of the trend line. The geological sequence is a more complete tertiary sequence over a shorter vertical interval. Therefore the trend line will be less near the vertical than the one above.

Trend Line Shifting Essentially there are only 4 situations that justify the shifting of established dc exponent trend lines. These are:

1. A permanent shift for a major unconformity. Note: this may be a rare occurrence.

2. A shift for a change in drilling section. This may be permanent depending on the drilling program.

3. A shift for a considerable change in hole inclination. This is valid for as long as the hole has that inclination +/- 5 deg.

4. Temporary shifts to the trend line for extreme changes in mechanical, hydraulic or other influences described in the section Factors affecting the dc exponent curve.

Shifting must be exercised with great caution and a studied consideration of all conditions influencing the dc exponent. It is strongly recommended that an original, established trend line is never completely abandoned, but retained for reference, even after the shift has been made.

Application and Conclusion The model is applicable for clay/shale sequences but has been shown to be relevant in other lithologies. The pressures of the reservoir rocks can be estimated from those pressures evaluated in immediately overlying clays or shales.

Calculations of pore pressure are made by comparing the observed values with those anticipated and by using Eaton’s formula. In evaporite areas a proportional ratio may be useful.

Agip Sigmalog

Theory AGIP and Geoservices developed the Sigmalog in the Po valley in the mid-seventies. The aim was to solve the shortcomings of the d exponent while drilling overpressured sequences of carbonates, marls and silty shales in deep wells. In essence the Sigmalog is an instantaneous ROP-pore pressure prediction model based on the relationship between drilling parameters, ROP, rock strength, a pseudo differential pressure at the bit and formation pressure. Whereas the d exponent may be considered a normalized ROP, the Sigmalog may be thought of as representing a rock strength parameter.

Methodology 1. Raw rock strength, square root of σt, is calculated from normalized drilling parameters (and

is, therefore, similar to d exponent).

Raw rock strength = (W 0.5 x N0.25)/(D x R0.25)

Where,

σt0.5 = raw sigma or total rock strength or Sigma Factor, dimensionless


W = WOB, tons

N = RPM

D = bit diameter, inches

R = ROP, meters/hr

2. The raw rock strength is then corrected for the effects of the compaction process (square root of σt’).

σt’0.5 = σt0.5 + 0.028 x (7 – (Z/1000))

where, Z = depth in meters

3. Next, the rock strength function sigma, (square root of σo) is calculated by adjusting the corrected raw rock strength for the effects of normal pore pressure and a pseudo-differential pressure at the bit (very similar to the dc exponent).

σo0.5 = F x σt0.5

where,

σo = corrected sigma

F = 1 + ((1 – ((1 + n2) x ∆P2)0.5)/(n x ∆P))

Where,

∆P = differential pressure of mud to formation fluid corresponding to the normal hydrostatic gradient, kg . cm2

n = factor expressing time required for the internal pressure of cuttings not yet cleared from the bit face to reach mud pressure

if σt’0.5 <= 1 n = 3.25/(640 x σt’0.5)

if σt’0.5 > 1 n = (1/640) x (4 – (0.75/σt’0.5)

the value of n is a function of formation permeability and porosity. As a general rule, σt’0.5 < 1 for sands and > 1 for shales. N is greater for shales than sands because it reflects the fact that the bit face is more difficult to clean in shales. Changes in n has a minor effect on σt’0.5. It is therefore not a problem to apply it to other sectors than the Po valley.

4. A reference trend rock strength (square root of σr) is then calculated using particular trend coefficients.

σr0.5 = α x (Z/1000) + β

where,

σr0.5 = parameter defining the reference conference trend.

α = trend slope

β = intersection of the trend with the horizontal axis for Z=0

Z = depth in meters

The slope of the trend usually remains constant at 0.0881 / 1000 m.

5. Determine porosity:

φ = 1 / (1.4 + (9 x σo0.5 x σr0.5 / σφ0.5)

σφ0.5 = trend of the σφ0.5 points most to the right


6. Finally, calculation of formation pore pressure is achieved by finding the ratio between the depth-corrected raw rock strength (σr0.5) and σφ0.5. The σr0.5 trend must be shifted to allow for changes of formation, bit or diameter, such that:

σr10.5/σr20.5 = σφ10.5/ σφ20.5

((the reference trend rock strength, (square root of σr/square root of σt’) and the current bit equivalent circulating density.)) ß check this one.

Rock strength parameter, σo0.5, is plotted against linear horizontal and vertical scales. For identical lithologies Sigmalog behaves like compaction, i.e. increases with depth. The highest values represent the lowest porosities.

A shift is required each time there is a change of lithology, diameter or bit type, but the slope remains the same. If values of σo0.5 start to fall without any change of lithology or drilling conditions, this suggests an increase in porosity and/or formation pressure.

Conclusion The efficiency of Sigmalog are very similar to those of d exponent. It is a method that is not easy to use and therefore ill suited to unexplored basins. Its use should be limited to clays and shales. On the other hand it relies too heavily on the operator’s judgement when determining the various trend shifts required. At the same time the interpreter has little control over the calculation stage.

Drag, Torque And Fill Drag, torque and fill are all indirect, qualitative indicators of overpressure; they are also indicators of hole instability and other mechanical problems which have nothing to do with overpressure.

Drag is the excess force that is necessary to pull the drill string up, whether it be for a connection or a trip. As overpressured shale is drilled into, drag is often noted. This due to the inability of the underbalanced mud density to hold back the physical encroachment of the formation into the wellbore. Drag is also due to inefficient hole cleaning, formation damage caused by the drilling fluid, hanging up of the stabilizers in deviated holes, etc.

Rotating torque often increases in an overpressured zone due to the physical encroachment of the formation (esp. shale) into the wellbore. Increases in rotating torque are also caused by stabilizers catching on hole deviations, out of gauge hole, thick wall cake, bearings locking up, etc. (see above discussion on Torque)

Fill is the settling of cuttings and/or cavings at the bottom of the hole. Fill is often observed when overpressured shale is drilled into; the shale tends to cave into the wellbore due to the inability of the inadequate mud density to hold back the formation. Fill is also due to mechanically unstable formation such as a fracture zone, the knocking off of formation by drill string components, ineffective hole cleaning, poor suspending properties of the drilling mud, etc.

One additional factor which invariably affects drag, torque, and, to a certain degree, fill is shale hydration. All shales will absorb water from the drilling fluid; in doing so, they expand, spall, heave and flow into the wellbore, often exerting tremendous hydrational pressures. Anytime any water-based drilling mud is used to drill shales, hydrational problems manifested as drag, torque, fill, stuck pipe or hole collapse may be expected in some degree. Hence extreme care must be exercised when interpreting the cause of drag, torque and fill.

Miscellaneous

Standpipe, Mud Flow Out, Differential Flow, Pit Volume


Standpipe pressure often exhibits a slightly decreasing trend in an overpressured zone; this is particularly true when a kick takes place. Mud flow out, pit volume and rate of pit volume change are also indicators of overpressure, particularly during a kick.

Differential mudflow measurement with the aid of electromagnetic flow meters is currently the best way for early detection of kicks or mud losses. Its advantage over the pit level monitoring system is that the surface mud movements do not have to be accounted for. It also gives quicker and more accurate response. It is costly and difficult to install.

Mud Weight Out Mud weight out will act as lagged, qualitative indicator, as the mud weight out often decreases when bottoms-up is circulated after a trip; it will also decrease anytime there is an influx of formation fluid, such as happens during a kick.

Mud Resistivity In And Out Mud resistivity in and out is also monitored in order to detect any influx of formation fluid that will occur when an overpressured zone is drilled into. Usually the pore fluids in an overpressured zone contain more dissolved salts than are in the drilling mud; in this circumstance the resistivity out will decrease (the mud conductivity out will increase).

The detection of changes in salinity while drilling requires a significant contrast in resistivity between mud and formation water. The release of formation water by drilling alone is insufficient in comparison to the volume of circulating mud to give rise to measurable changes in resistivity. Only kicks or continuous diffusion of formation water into the well, due to negative differential pressure, will show up as significant changes in resistivity. This technique is not effective for drilling muds containing a high salt content, nor is it effective for oil muds.

M.W.D. MWD techniques now provide a range of methods that are significantly improving the state of knowledge on bottomhole drilling parameters and formation evaluation:

• Bottomhole WOB

• Torque at bit

• Mud pressure

• Mud temperature

• Mud resistivity

• Formation resistivity

• Formation radioactivity

If the true WOB is known, drilling rate can be normalized with better accuracy.

Information on true bottomhole mud pressure gives a more accurate view of the effects of swab, surge and annular pressure loss.

Differential resistivity between mud in the drill pipe and the annular space may well be considered a kick indicator.


Methods Depending On Lagtime

Gas

Introduction Gas may be used as a qualitative and semi-quantitative indicator of overpressure. Gas is derived both from drill cuttings and from the in-situ formation, enters the drilling mud, and is circulated to the surface where it is broken out from the mud by a gas trap. ILO’s THA measures 1% gas in air as being equivalent to 50 units. Gas shows can be categorized according to its source as follows:

• Cuttings gas: gas released from the drilled formation and by the cuttings moving up the annulus

• Produced gas: gas issuing from the borehole walls. This may be due caving or swelling and can also arise from diffusion or effusion if differential pressure is negative.

• Recycled gas: if the mud is not completely degassed at the surface, it may be returned downhole still gas cut.

• Contamination gas: from petroleum products in the mud or from thermal breakdown of additives. Breakdown of organic matter in shales or thermal effects produced by the bit can also give rise to gaseous hydrocarbons.

The amount of gas detected at any point in the well is related to the:

• Hydrocarbon distribution

• Porosity and permeability of the formation


• Volume of rock drilled (the hole size, ROP)

• Circulation rate

• Mud characteristics (type, viscosity, temperature, hydrocarbon solubility, etc.)

• The measuring equipment

Background Gas Background gas is the gas released by the formation while drilling. It usually consists of a low but steady level of gas in the mud which may or may not be interrupted by higher levels resulting from the drilling of a hydrocarbon zone or from trips and connections.

An increase in the level of background gas from that found in overlying normally compacted shales occurs while drilling undercompacted formations. Such an increase is due to the following reasons:

A generally higher gas content

An increased ROP

A drop in differential pressure

The determining factor is ∆P. If the mud weight is too high it can mask or even eliminate gas shows.

If background gas variations are observed while drilling argillaceous sediments while the mud weight and other drilling parameters remain the same, this often indicates that the formation pressure has changed.


Any mud weight increase must be gradual. If background gas diminishes while the mud weight is being raised, it proves that the cause was ∆P.

Background gas is often a good method for detecting and monitoring abnormal pressure. But some undercompacted shales have no gas at all, which in this case this parameter could not be used.

Gas Shows If porous and permeable formations containing gas are penetrated while drilling gas shows can occur. ∆P governs their volume.

If mud weight is too high and fluid loss is not checked, gas shows will be reduced as the gas is flushed ahead of the bit.

Normal drilling conditions: the gas show exceeds the level of the background gas. Background gas level is the same before and after the gas show peak.

If ∆P is negative the gas show is bigger. Gas continues to flow from the reservoir as drilling continues in the non-reservoir section below, and this raises the background gas level.

Observing the form and abundance of gas shows can make it easier to detect a state of negative differential pressure. This is very important for the detection of abnormal pressures where there is no transition zone.

Connection And Trip Gas The presence of connection or trip gas may be typical of well imbalance. The equivalent density applied to the formation when the pumps are stopped (static) is lower than the ECD (dynamic). When the well is close to balance, the in pressure while static may allow gas to flow from the formation into the well bore.

The connection gas value must be reported net of the background gas value.

The quantity of gas observed at the surface when circulation is resumed depends mainly on the following criteria:


• Formation permeability

• Nature of the gas contained in the drilled formation

• Length of time pumps were stopped

• Movement of the drillpipe (swabbing upwards or surging downwards)

Observing the frequency and progression of connection gases can be a valuable aid in evaluating differential pressure.

To monitor connection gas correctly the following criteria should be observed:

• Lithology: preferential attention must be paid to connection gases from argillaceous sections. Permeability is then less critical and the gas arises from diffusion or cavings.

• Connection gases may be compared with one another, provided connection times are fairly uniform. On the other hand, in the case of trip gas stopping times vary and comparisons are more difficult.

• Coming out of the hole can produce a temporary condition of negative ∆P or exaggerate one that already exists. In order to keep the effects of swabbing on connection gas to a minimum it is recommended that pulling speed should be kept steady.

Below are some situations that can be encountered while drilling with a steady mud weight:


• Background gas stable – connection gas sporadic: This situation is not characteristic of formation pressure variation. Connection gas may be present due to swabbing, lithological changes or caving. However, variable connection conditions can give rise to this situation in a transition zone. Interpreting this situation is ambiguous.

• Background gas stable – connection gas increasing: This is typical of entering a transition zone. The stable background gas suggests positive ∆P. But the increasing incidence of connection gas reflects a decline in ∆P.

• Background gas and connection gas on the increase: This means that a zone of negative ∆P is being drilled.

The best information concerning well equilibrium is to be obtained from observing overall trends in connection gas irrespective of short-term fluctuations. In fact connection gas is more of a method for monitoring developments in pressure than a means of precisely defining the top of the overpressured zone.

Abnormal pressure is confirmed if, by adjusting the mud weight, the value of the connection gas is reduced.

Normalized Connection Gas In order to obtain standardized gas data, some companies recommend deliberately creating standard gas shows using a rule known as "10-10-10”. The method involves inducing gas slugs under three different sets of equivalent density conditions. Gas shows can then be interpreted more accurately.

Expound on method ………..

The method is good in principle, but is time consuming when applied regularly and may also lead to stuck pipe.

Gas Composition The occurrence or increased incidence of heavier gas components is commonly observed when drilling into transition zones. This can be used as a means of detecting undercompacted zones.

Undercompacted clays are often source rocks. If volatile hydrocarbons given off by maturation of organic matter due to heat stored in the undercompacted zone are trapped, drilling through this zone is accompanied by an increase in background gas. On the other hand, selective retention of heavy hydrocarbons as a result of the migration of light components through the transition zone leads to an anomaly in gas composition.

In normally compacted zones, there is generally less propane (C3) than ethane (C2). When drilling into or even towards a transition zone, this relationship is often seen to reverse. In other words the C2/C3 ratio is less than 1.

There are few published results on this subject.

Gas component analysis is affected by measuring instruments and mud characteristics. The preferential evaporation at the surface of lighter components and, inversely, the retention of the heavier components in the mud can falsify ratio evaluation. Measurements using vacuum evaporation techniques keep these disadvantages to a minimum.

Comparisons should be made between gas shows from argillaceous layers.

xxxxxxxxxxxxx

Gas is generally distinguished as either total gas or as connection/trip gas; the basis of the distinction is two-fold:

1. to examine hydrocarbon distribution


2. to determine relative degree of over- or under-balance.

Total gas represents the total amount measured at any particular interval and is dependent on the numerous variables mentioned above. Although total gas will give a good idea of hydrocarbon production potential, it is, for all practical purposes, only a qualitative indicator of overpressure.

Connection and trip gas are the amounts of gas which enter the wellbore when the well is in static condition (no circulation); as such, an increase in either with depth will indicate a loss of overbalance due to overpressure development. Hence, both are excellent qualitative indicators of overpressure; they are also semi-quantitative in that they indicate that the pore pressure to be close to that of the mud weight.

Shale Density

Theory and Limitations Shale density is historically the oldest method of calculating pore pressure while drilling. It is based on the theory that shale density in an undercompacted zone increases less rapidly and may even fall in comparison with the density of normally compacted clays and shales.

It is accepted that shale density increases with depth as overburden increases forcing pore fluids out in a process called compaction. However, in certain situations, compaction is hindered, curtailed or reversed (in the case of diagenesis of montmorillonite). In these cases, the porosity is abnormally high for that depth, the shale bulk density abnormally low, and the pore fluids support more than a normal share of the weight of the overburden.

For normal pressure, shale density values should yield a plot of increasing density versus depth; a departure from this to trend of decreasing density versus depth represents overpressure. Often, it is almost impossible to obtain a shale density trend, thereby eliminating shale density as an overpressure detection method.

The effectiveness of this method depends on the selected cuttings being representative of that particular zone or interval. Shale density data can also be misleading and inaccurate:

• In some areas, drilling does not go deep enough. The clays/shales encountered may not sufficiently consolidated to allow their densities to be measured.

• Shale cuttings are subject to hydration; hence, the shale sample may not truly reflect the properties of in situ shale. The mud type should also be considered. The use of reactive muds, mostly water-based muds, has an adverse effect on measurement quality.

• Shale exhibits varying mineralogy; hence care must be taken in the selection of the sample. The shale should be uniform in mineralogy, something that can not be discerned using the naked eye, or, for that matter, a reflecting microscope. Also, it must be assumed that the shale sample comes from the bottom and has not been mixed or settled during circulation or connections; also, it must not be a caving.

• The procedure for collecting shale densities may incorporate user inaccuracies. This results from improper processing of samples, different operators, the type of density column, the established trend line, etc.

• The density measurement technique is dependent upon proper calibration

• The inability to measure any valid density for shales at shallow depths in many marine basins; this precludes the establishment of a normal compaction trend.

• Lastly, there is some question to the validity of the equivalent depth hypothesis.

Methods Of Measurement


Heavy Liquids Kits of liquids of different densities are available. A set of densities from 2.20 to 2.70 g/cm3 in stages of 0.05 g/cm3 will cover the entire range of shale densities. The method is based on the Archimedes principle. Each cutting is immersed successively in liquids of increasing density until it no longer sinks.

In addition to the disadvantage of insufficient accuracy, cuttings must be transferred from one liquid to another with care in order to avoid any change in the density of the liquids through mixing.

Variable Density Column A variable density column can be prepared by partially mixing miscible liquids of known densities. The density distribution is checked using beads of calibrated density that can be used to prepare a graph of density against column height.

The most commonly used liquids are bromoform (d=2.89) and carbon tetrachloride (d=1.59), or the somewhat less toxic trichloroethylene (d=1.47).

Each cutting is immersed in the column after having been dried on absorbent paper, then all that is necessary is to read off the height at which the sample has come to a halt and check this value on the calibration curve in order to obtain the shale density.

As long as the column is properly calibrated this method is more accurate and faster than the previous method. It is the most widely used method.

Mercury Pump

Pycnometer

Microsol (Geoservices)

The principle behind this method involves comparing the weight of the cuttings in air and in water. Shale density is obtained by the formula:

ρb = L1 / (L1-L2)

L1 = weight in air

L2 = weight in water

Three or four measurements are made every 5 m. the arithmetic mean is taken to be the density.

Use of the Microsol is difficult, particularly offshore where it should not be used

Methodology All these methods require special treatment of the cuttings. Washing in every case and (in the case of the dense liquids, column and mercury pump methods) drying of the surface without heating (in order to avoid dehydrating the clays).

Where the dense liquids or column methods are used the cuttings should be selected to remove fissured fragments which can retain air. Observation of the background gas should draw attention to low densities which might result from the presence of gas in the shales.

It was hypothesized that an observed lower-than-normal shale density possesses the same matrix strength as normal density shale with the same density. This hypothesis is termed the depth of seal or, alternatively, the equivalent depth method.


Shale density measurements are made at frequent and regular intervals, and these values are plotted against depth. A trend line, representing normal compaction – normal pore pressure, is drawn in a best-fit manner. Then for any shale density which is lower than normal, a vertical line is extended upward to an intersection with the normal trend line. This point is the equivalent depth. The pore pressure at this point is known to be normal; in order to calculate the matrix stress, it necessary to subtract the pore pressure from the overburden pressure. The overburden pressure, therefore, is always required for this method. Overburden pressure is calculated by multiplying the shale density (gm/cc) by 0.433 in order to convert density into a unit of pressure gradient (psi/ft); this pressure gradient is multiplied by an interval thickness to arrive at an interval overburden. These interval overburdens are added cumulatively to present depth in order to have the value of overburden pressure.

Once the matrix stress pressure (in psi) is known, the abnormally pressured shale at the depth of interest is assumed to possess the same matrix stress pressure. This matrix stress pressure is then subtracted from the overburden pressure at this depth in order to find the pore pressure.

Example:

Problem: Calculate the pore pressure at 8500 ft.

Solution: Use S = σ + p (S = overburden pressure; σ = matrix stress pressure; p = pore pressure)

Depth of interest = 8500 ft

Equivalent Depth = 7000 ft

Normal pore pressure = 0.452 psi/ft = 8.7 ppg = 1.04 sg

S7000 = 0.752 psi/ft = 5262 psi (from overburden calculations)

S8500 = 0.782 psi/ft = 6256 psi (from overburden calculations)

S7000 – p7000 = 0.752 psi/ft – 0.452 psi/ft

σ7000 = 0.300 psi/ft = 2100 psi

σ8500 = σ7000 = 2100 psi

p8500 = S8500 - σ8500

p8500 = 6256 psi – 2100 psi

p8500 = 4156 psi = 0.489 psi/ft = 9.4 ppg (1.13 sg)

Shale Factor The shale factor technique is a method of measuring the cation exchange capability (C.E.C.) of the shale cuttings. Montmorillonite clay possesses a greater degree of cation exchange capability than illite clay; the measurement is based on the milliliters of methylene blue that is absorbed per gram of crushed shale sample. The theory behind this technique recognizes that montmorillonite clay disappears with depth as it diagenetically alters to illite and mixed layer clays; hence shale factor (expressed in ml/gm) should decrease with depth. Ideally, zones of shale overpressure contain greater-than-normal amounts of montmorillonite, the montmorillonite either having been delayed or only now in the process of being altered to illite; during this diagenesis, huge volumes of oriented, inter-particle water are released, thereby being a source of pressure generation. Hence a trend of increasing shale factor versus depth indicates overpressure development; this conclusion is usually corroborated by a trend of decreasing shale density.

In some marine basins like Australia’s Bass Strait, shale factor and shale densities are major overpressure detection techniques.

Shale factor is not a reliable technique for detecting abnormal pressures, and cannot on its own lead to the conclusion that they are present. It may however provide confirmation and assist interpretation. The res ults may also contribute to the recognition of lithological markers.


Flowline Temperature

Introduction Flowline temperature is a qualitative, lagged overpressure detection technique, utilizing trends and changes in the flowline temperature of drilling fluids. The theory behind its use lies in the fact that overpressured formations, possessing greater-than-normal quantities of pore fluid, act as thermal insulators to the natural flow of heat from the earth’s core. Ideally, then, an overpressured zone should be detected in a rise in flowline temperature above what is normal. In actual use, the flowline temperature is subject to numerous variables which include such things as:

• Lithology

• Formation thickness

• Circulation rate

• Circulating while drilling as opposed to conditioning mud

• Ambient and diurnal temperature

• Addition of new mud/dilutions

• Length of marine riser, etc.

Due to the influence of these many variables, good use of the flowline temperature as an overpressure detection tool demands attention and interpretation; the technique has usually had very limited success, esp. for offshore locations.

Geothermal Concepts The geothermal gradient is the rate at which formation temperature increases with depth. It is calculated as follows:

Gt = 100 x ((T2 – T1)/(Z2 – Z1)

Where,

Gt = geothermal gradient. DegC/100m

T1 = temperature (degC) at depth Z1 (m)

T2 = temperature (degC) at depth Z2 (m)

Average geothermal gradients vary from 1.8 and 4.5 degC/100m in sedimentary basins.

The geothermal flux represents heat flow. It is determined by:

Qt = λ x (∆T/∆Z)

Qt = geothermal flux (m.W/m2)

λ = thermal conductivity of a given formation (W/m.degC)

(∆T/∆Z) = geothermal gradient (degC/1000 m)

The conductivity of clay or shale can vary by a factor of 2 depending on the nature of the constituent clay minerals. The presence of organic matter tends to reduce thermal conductivity. Quartz on the other hand, greatly increases thermal conductivity.

The deposition of a thick sedimentary layer will act as an insulating blanket and reduce heat exchange between the basement and the surface.

It should be noted that porosity considerably decreases conductivity because of the very low conductivity of water. The nature of the fluid filling the pore spaces also plays a part. Gas is even less conductive than water. Porosity acts as a brake on heat transmission. This is particularly true


in the case of high sedimentation rates that do not allow the sediments to reach thermal equilibrium with the underlying basement.

As a result of their high porosity undercompacted clays behave like insulating bodies. Lewis and Rose (1970) have demonstrated the effect of an insulating body on heat flow. ( Figure ??? …………).

The distribution of isotherms shows a reduction in gradient on approaching the insulating body and an increase within it.

The fall in the rate of temperature increase on approaching an insulating body may act as warning of the presence of undercompacted clays. An increase in temperature gradient, however, is a feature common to undercompacted zones and other insulating formations, such as porous reservoirs and thick coals.

Measuring Mud Temperature

Surface Measurements The temperature in and out sensors records surface measurements.

To eliminate fluctuations in the temperature out reading caused by fluctuations of the temperature in value the differential temperature can be measured.

Because of the rapid circulation of the mud and the effects of forced convection, the measured temperature profile differs from the actual geothermal profile. The mud in the upper part of the hole is warmer than the formation, and in the lower part of the hole it is cooler.

The thermal profile established in a well while drilling depends essentially on the following factors:

• Inflow temperature, which depends on the amount of cooling at the surface which is generally a few degrees (between 1 and 5 deg C)

• The rate of inflow which acts on two ways:

1. It controls the speed at which mud and the calories it contains return up the annulus

2. Together with the pump pressure, it controls the hydraulic energy fed into the system, which also heats up the mud

• The thermophysical properties of the mud

• The bottomhole temperature

The thermal profile is not very sensitive to local variations in geothermal gradient or ROP.

Below is a table which compares the temperatures measured at the surface with those measured with the wireline logs.

Depths (m) Hole Diam (in)

Flow Rate (l/min)

Pump Press. (bar)

Wireline Log Temp, deg C

Mud Temp Out, deg C

900 17 3/8 3700 95 35 37

2582 12.25 2200 165 71 56

4625 8.5 1700 130 126 60

4850 5.75 650 135 150 46

5048 5.75 650 135 165 40


At the top part of the well the mud temperature out sensor recorded a higher temperature than that of the wireline log. A reduction in flow from 1700 l/min to 650 l/min produces a fall of 14 deg C in the temperature out reading. M.W.D. tests have shown that a reduction in flow may in fact be accompanied by an appreciable fall in bottomhole temperature while drilling.

There are rare cases where mud temperature out has actually been used to detect undercompacted zones. This is because many factors mask the temperature changes. These factors are:

1. Offshore drilling: the marine riser assists heat exchange between the mud and the surrounding sea. The amount of cooling depends on the length and size of the riser.

2. Drilling and circulating halts: these cause cooling of the mud in the circulating pits and in the upper part of the hole. The length of the halt determines the amount of cooling. Trend to trend plotting of mud temperature out will remove irrelevant scatter and takes account of stabilized temperatures only.

3. Surface operations: transfers of mud between active pits and reserve pits disturb the mud temperature in.

4. Climatic changes: in the case of an onshore well, exposure of the pits to the open air can result in significant mud temperature in variations due to the ambient conditions (sun, snow etc.)

5. String rotating speed: rotation of the string is transmitted to the mud and has an appreciable effect on thermal transfers at the borehole walls.

6. Lithology: in order to keep lithological effects to a minimum, preference must be given to temperatures relating to shales.

7. Fluid kick: an influx of formation fluid will bring about an increase in mud temperature out commensurate with its volume.

8. Influx or diffusion of gas: increase of gas near the surface will bring a reduction in temperature due to endothermic expansion.

9. Mud type: heat exchange between the formation and the mud will depend on the conductivity of the mud. Internal heating of the mud will depend on its specific heat.

10. Measurement quality: it may be affected by the position of the sensor, the mud level, and turbulence and settling of cuttings around the sensor.

11. Plotting measurements: poor graphical representation

The interpretation of mud temperature out should be regarded as qualitative. It may perhaps contribute to locating the top of the overpressured zone, and in favorable circumstances, the approach to it. It is unlikely that it could ever yield an estimate of the over pressure.

M.W.D. We can use the MWD to measure the bottomhole mud temperature while circulation is in progress.

Bottomhole Measurements during Wireline Logging Whenever a wireline log is run a maximum thermometer (sometimes 2) is attached.

A Horner plot is measured to extrapolate measured temperatures. This method is based on the assumption that the mud cools the formation during drilling or circulation. This sets up a temperature gradient between the walls and the surrounding formation. When circulation is stopped, the heat exchange between the formation and the mud tends to reduce the radius of the cooled zone and thereby the gradient. By extrapolating the temperature to infinite time it is


possible to deduce the true formation temperature, provided circulation was not continued too long after drilling stopped (implying excessive cooling).

The temperature/time relationship is as follows:

T = Tf – C log ((tk + ∆t)/∆t)

Where,

T = measured temperature

Tf = true formation temperature

C = constant

tk = bottom circulation time (Some authors recommend that the drilling time for the last meter should not be added to tk)

∆t = time elapsed between stopping circulation and logging tool on bottom prior to logging

A plot of T and (tk + ∆t)/∆t on semi-log paper is linear. Extrapolating the graph to a time factor of 1 provides an estimate of the formation temperature.

This method is only an approximation of the actual heating curve. It is only valid if the following condition is fulfilled.

a2/(4 x kt) << 1 (in practice < 0.07)

with

a2 = square of bottomhole radius (m3)

k = diffusivity of the system (m2/s)

t = time for which circulation stopped (s)

In practice this condition is only fulfilled for an 8.5” hole. In other circumstances the formation temperature will be underestimated.

Although 2 temperature/time pairs are sufficient to draw the straight line it is preferable to have three or four.

Measurements while Running Wireline Logs The Schlumberger AMS tool provides a continuous record of temperature during its descent.

Bottomhole Measurements during Formation Testing Temperature measurements of fluid produced in the course of formation testing are more representative of formation temperature. Two types of measurement may be performed:

• A maximum thermometer of the type used in wireline logging is placed in the mechanical pressure recorders

• Continuous thermometry in association with electronic pressure recorders

Such measurement s are not performed regularly and it is not common for them to be made at several depths within a given well.

Bottomhole “Temp Plates” Measurements

Thermometry


A continuous profile of the change in temperature of the mud column in a well can be obtained with thermometric logging tools (HRT, etc). these are generally used in either geothermal wells or in oil drilling to detect mud-loss zones or the top of the cement behind the casing.

The measured values are not representative of either formation temperatures or changes in the gradient, because mud temperatures are not stabilized in relation to the true formation temperature.

Conclusion Although undercompacted zones are accompanied by temperature anomalies, it is not easy to detect these using available methods for measuring mud temperature, These methods depend on a number of variables which frequently mask changes in geothermal gradient.

Bottomhole temperature measurements during logging , which have the disadvantage of being performed subsequently and in isolation, nevertheless provide a better estimate of true formation temperature. However, the quality of the measurement depends on the time elapsed since drilling ceased.

Mud Density With modern methods for measuring mud weight, particularly gamma ray density, mud weights in and out can be monitored continuously and accurately.

A decrease in mud weight out (for a constant mud weight in) may be due to the following:

• Expansion of gas released by drilling of the formation as it reaches the surface

• A kick of hydrocarbons or water (spontaneously or as a result of swabbing)

• Gas diffusion (if ∆P is negative)

• A bubble of air (after tripping or connection)

Most reductions in mud weight are due to gas released while drilling.

The volume of gas released at the bottom of the hole while drilling can be calculated using the following formula:

Vg = (1.27 x D)2 x π x (R/600) x φ x Sg

Where,

Vg = volume of gas released into the mud per minute (l/min)

D = hole diameter (ins)

R = ROP (m/hr)

φ = formation porosity

Sg = gas saturation of the formation

An estimate of the approximate volume at the surface can be calculated as follows:

Vgs = (Vg x P)/1.02

Where,

Vgs = the volume of gas at the surface (l/min)

P = hydrostatic pressure of the mud (kg/cm2)

1.02 = atmospheric pressure (kg/cm2)

The fall in mud density as a function of flow is calculated by this formula:


Dr = Do x (Q/(Q + Vgs))

Where,

Dr = density of gas cut mud (g/cm3)

Do = normal mud weight (g/cm3)

Q = mud flow (l/min)

No account has been taken of either temperature or the compressibility coefficient. Their effects can be ignored except when dealing with a deep well or steep geothermal gradient.

To calculate the equivalent bottomhole density:

Deqv = ((P - ∆P) x 10) / Z

∆P = ((Do – Dr)/Dr) x ln (P + 1.02)

This formula shows that the fall in equivalent bottomhole density will be greater, the shallower the depth at which the kick occurs.

Where a thick gas-bearing zone is being drilled continuously, drilling has to be done in stages with immediate conditioning of the mud system.

Isolated slugs of gas-cut mud most frequently cause decreases in density whose effects need neither an increase in mud weight nor a halt to drilling and at most a short circulation.

Example Let D = 12.25 ins., R = 30 m/hr, φ = 0.3 and Sg = 0.7; depth is 3500 m., MW = 1.3 sg;

Q = 2400 l/min

Find: volume of gas released into the mud

Vg = (1.27 x 12.25)2 x 3.14 x (30/600) x 0.3 x 0.7

Vg = 7.98 l/min

Find: volume of the gas at the surface and the hydrostatic pressure of the mud

P = (3500 x 1.3)/10 = 455 kg/cm2

Vgs = (7.98 x 455) / 1.02 = 3560 l/min

Find: the density of the gas -cut mud

Dr = 1.3 x (2400/(2400 + 3560)

Dr = 0.52

Find: the bottomhole equivalent density

∆P = ((1.3 – 0.52)/0.52) x ln(455 + 1.02) = 9.19 kg/cm2

Deqv = ((455-9.19)/3500) x 10 = 1.27

Cuttings / Cavings Wellsite geologists generally regard large cuttings as being cavings. But in sections of negative ∆P large cuttings may also be produced and be confused as cavings. A concomitant disappearance or sharp reduction in very fine cuttings can generally be used to decide the matter.

An increase in the volume and size of cavings implies instability of the borehole walls (thermal or mechanical imbalance when drilling).


The problem is mainly associated with argillaceous rocks, although all other formations may also be affected provided that they are located at sufficient depth.

High formation pressures contribute to destabilization of the borehole walls in two essential ways. On one hand, they reduce the strength of the rock, while on the other hand they can cause circular concentric tension fractures in low permeability formations such as shales.

The cavings observed at the shakers have two essential shapes (see Elf p. 157). The first is a flattened, elongated flake, frequently confused at first sight with the cleavage of a laminated shale. It has a concave cross-section. The second shape is more blocky, often with microfissures.

Laboratory tests have demonstrated that the fracture mechanism due to excessive compression can produce both types of cavings at the same time or in succession.

Plate-shaped cavings are therefore not a definite indication of overpressure, since stress effects in normally compacted rocks can also produce them.

Cuttings Gas Cuttings gas is gas produced by breaking a certain volume of cuttings in a blender.

Cuttings incorporate a microporous system containing formation fluid that is not polluted by the mud because of capillarity and adsorption forces. The non-polluted volume depends on the permeability of the rock. Shales retain a large proportion of their fluid content right up to the surface.

It is hoped that the frequently noted increase in gas content in undercompacted shales will be better detected by using cuttings gas. Similarly changes in the composition of gas indicators which frequently occur in transition zones may provide a means for the detection of abnormal pressure.

Conclusion

There are many methods for the detection of abnormally pressured zones while drilling, and they vary considerably in effectiveness. Below is a table of methods used classified on their corresponding degree of reliability.

Detection Reliability Real-time Methods Lag-time Methods

RELIABLE Drilling Rate

Dxc (without wear factor)

Normalized ROP

Sigmalog

Drag while making trips or connections

Flow measurement

Pit levels

Gas – Connection Gas

Gas – Background Gas

Gas – Reservoir Gas

MODERATELY RELIABLE M.W.D. (penalized by the absence of a porosity log)

Fill (resumption of drilling)

Torque

Gas – Gas Show composition

Gas – Trip Gas

Shale Density

Shale Factor

Pyrolysis

Abundance & size of Cavings


Detection Reliability Real-time Methods Lag-time Methods

Cavings shape

NOT VERY RELIABLE Pump Pressure Mud Temperature

RESEARCH IN PROGRESS X-Ray Diffraction

Cuttings Gas

Nuclear Magnetic Resonance

Post-Drilling Data

E-logs This technique comprises the use of particular e-logs. The core of this standard investigation includes SP, GR, CAL, Sonic, Density and Resistivi ty E-logs.

Plotting shale resistivity values on semi-log paper vs. depth should exhibit a trend of steadily increasing values for normally pressured sediments. A shift of the resistivity trend to lower values indicates greater than normal porosity hence overpressure.

A plot of shale sonic interval travel times vs depth for normally pressured shales (carbonates) should exhibit a trend of increasing values vs. depth; a divergence to greater-than-expected values indicates either a change in mineralogy or an increase in formation pore pressure. The GR and SP logs assist in the identification of shales and the caliper logs identifies out -of-gauge hole, for which sonic values are inaccurate and misleading. A benefit to using the sonic log is that the uppermost or starting point of the normal trend line should intersect the 190 to 200/4 sec/ft transit time value.

Method Of Estimating Pore Pressure Magnitude From Resistivity And Sonic Logs The method involves the establishment of a trend line through as many points as is possible which are representative of normally pressured shales (or carbonates). The magnitude of the pore pressure is a function of the difference between normal and observed values at the depth of interest.

The method commonly employed is Eaton’s suite of formulae that utilize ratios of observed and expected (normal) resistivity, conductivity and sonic values, plus values of variable overburden and matrix stress pressures. These formulae are as follows:

p = S - (σ x (Ro/Rn)1.2)

p = S - (σ x (Cn/Co)1.2)

p = S - (σ x (∆tn/∆to)3.0)

Where, p = pore pressure psi/ft

S = overburden pressure, psi/ft

σ = normal matrix stress pressure, psi/ft (S-pn)

R = resistivity

C = conductivity

∆t = interval transit time

o = observed


n = normal

Once the E-log data is plot ted, a comparison can be made between the seismic, drilling and well logging data in order to interpret, predict, identify and evaluate any abnormal formation pore pressures.

Direct Pressure Measuring Tests Actual bottom hole pressure measurements are really the only true quantitative tools for overpressure detection and evaluation. Measurements of actual bottom hole pressure are essential for scaling the pre-spud and during drilling indicators. These tests are essential to verify the data from other indicators.

Direct pressure measuring tests include:

• Kicks

• Formation Interval Tests

• Repeat Formation Tests

• DST

• Production Tests

Kicks are the least desirable of the pressure measurements. They are the most potentially dangerous and expensive of the various pressure measuring tests. However, if quickly and properly controlled, the data provided by a kick can be free and very informative.

FITs and RFTs are wireline formation tests. The FIT can collect only one sample whereas the RFT can make numerous measurements of formation pressure at various intervals. These are probably the cheapest and least hazardous means of obtaining formation pressures.

DSTs are probably the most difficult bottom hole pressure measuring tests to, not only run, but also to interpret. In a DST, drill pipe is run to the zone of interest and a packer is set above the zone in order to seal off the zone of interest. A pressure differential is placed on the formation by lowering the mud hydrostatic using air, oil or a water “cushion”. Influx of formation fluid at bottom hole pressure occurs, and this is collected and measured at the surface.

Production tests are a final method for actual measurement of bottom hole pressure. These tests are expensive and seldom utilized except to accurately evaluate reservoir characteristics for possible production.

Summary Based upon the mode of origin, the Pressure engineer chooses the drilling, mud and cuttings parameters that appear to be most relevant to the particular technique. For example, for overpressured zones that are compaction-related, the Dxc could be used in conjunction with other qualitative techniques. Should the cause of overpressure be temperature-related, particular emphasis would be placed on the flowline temperature. With a proper selection of overpressure detection techniques, the chances of detection of overpressure development are more than reasonably well assured.

It should be noted that none of the ROP-pore pressure prediction techniques (D exponent, Dc exponent, Sigmalog) presently available are equipped to consider all the numerous factors affecting the ROP.


Quantitative Pressure Evaluation

Introduction The only detection methods that can be used to evaluate pressure quantitatively are:

1. Formation Tests, which give a direct measurement of the pressure

2. Seismic interval velocities

3. Dxc, Sigmalog, Normalized ROP

4. Shale Density

5. Gas Shows

6. Kicks/Mud Losses: Mud Flow Measurements, Pit Levels

7. Wireline Logs: Resistivity/conductivity, Sonic, Density

Most methods of evaluation are based on the principle of comparing the undercompacted clays with a normal compaction state, which means that a normal compaction trend must be established.

Equivalent Depth Method

Applications This method is applied to the following:

• Interval velocities

• Dxc

• Shale Density

• Resistivity/Conductivity

• Sonic

• Density Log

• Any direct or indirect measurements of clay porosity

Principle The principle is that every point A in an undercompacted clay is associated with a normally compacted point B. the compaction at point a is identical at point B.

B

A

Log φ

Depth

ZA

ZB


The depth of point B (ZB) is called the equicvalent depth, or sometimes the isolation depth.

Using Terzaghi’s formula: S = σ + P. the matrix stress, σ transmitted by grain to grain contact is identical at A and B.

Knowing the overburden pressure Sb and the normal pore pressure at B (Pb), σb can be calculated: σb = Sb – Pb.

As σb = σa and knowing the overburden at A, Sa. The pressure at A can be calculated:

Pa = Sa - σb.

Then by eliminating σa and σb, the pore pressure at A can be calculated:

Pa = Pb + (Sa – Sb)

Example

A = 3500 m

B = 2500 m

Normal pore pressure gradient = 1.06

Overburden gradient at B = 2.20

Overburden gradient at A = 2.26

Calculation:

First calculate pore pressure at B: Pb = (ZB/10) x 1.06 = 265 kg/cm2

Then calculate the overburden pressure: Sb = (ZB/10) x 2.20 = 550 kg/cm2

Then calculate the overburden pressure at A: Sa = (ZA/10) x 2.26 = 791 kg/cm2

Then calculate the pore pressure at A: Pa = Pb + (Sa – Sb) = 506 kg/cm2

Therefore for the equilibrium density: deql = (Pa/ZA) x 10 = 1.45 gm/cm3

The formula to be used at the wellsite when the overburden gradient is known is:

Deqla = OBGa – ((ZB/ZA) x (OBGb – Deqlb)

Where,

Deqla = equilibrium density at A

Deqlb = equilibrium density at B

ZB = equivalent depth

ZA = depth of the undercompacted clay

OBGa = overburden gradient at A

OBGb = overburden gradient at B

If the overburden gradient is not available, an average overburden gradient may be used. The value normally taken is 2.31 (1 psi/ft), which corresponds to an average established in the Gulf Coast. Although this value produces a small error in onshore wells this should not be used in offshore wells if at all possible, particularly where the water is deep and the well is shallow.

When the normal pore pressure gradient is not known a value of 1.05 may be used.

The simplified formula using the constant gradients is:

Deqla = 2.31 – 1.26 (ZB/ZA)


Using this formula in the previous example we get an answer of 1.41

Establishing Isodensity Lines

1. Extend the normal compaction trend XY to the depth origin X

2. Choose a point B located on the normal compaction trend line

3. For a selected value of Deqla calculate depth A using the following formula derived from:

ZA = 1,26ZB / (2.31 – DeqlaA)

4. Position point A on the vertical from B, then draw a straight line XZ passing through A

The equivalent depth method may be used regardless of whether the porosity parameter concerned is represented arithmetically or logarithmically.

Ratio Method

Applications This method could be applied to the following methods:

• Dxc

• Shale Density

• Sonic Log

• Resistivity/Conductivity Log

• Density Log

Principle The difference between observed values for the compaction parameter and the normal parameter extrapolated to the same depth is proportional to the increase in pressure.

Depth

ZA

ZB B

A

X

Y Z


The equilibrium density is obtained using the following formula:

Deql = Deqln x (Dxcn / Dxco)

Deqln = normal equilibrium density

Dxcn = normal Dxc

Dxco = observed Dxc

Establishing Isodensity Lines

To establish isodensity lines:

1. Take a point (A) located on the normal compaction trend XY

2. Calculate the value of Dxc which would be observed at point A for a given density

3. Using this value (B) draw a straight line X’Y’ parallel to XY. This represents the gradient of the selected equilibrium density.

Example:

Dxcn = 1.80, Deqln = 1.05

Dxco = 1.80 x (1.50 / Deql)

To draw the isodensity line Deql = 1.20

Dxco = 1.80 x (1.50/1.20) = 1.58

The ratio method is easy and very widely used. However, because it is empirical, the results obtained are not always satisfactory. Adjustment of the calculations on the basis of direct

Dco Dcn

Normal trend Depth

Log Dxc

A B

X

Y Y’

X’

Depth


measurement data (obtained from RFT and Tests) can appreciably improve the results of the method. A correction coefficient (c) could be added:

Deql = c x Deqln x (Dxcn / Dxco)

Example:

Calculated Deql = 1.25

RFT Deql = 1.35

C = 1.35/1,25 = 1.08

This correction coefficient remains applicable as long as the origin and the causes maintaining the abnormal pressure remain constant for the unit in question.

Eaton Method

Application The Eaton Method could be applied to the following methods:

• Interval Velocities

• Dxc

• Resisitivity/Conductivity Log

• Sonic log

It may also be extended to:

• Shale Density

• Density Log

Principle The relationship between the observed parameter/normal parameter ratio and the formation pressure depends on changes in the overburden gradient.

These are the following formula:

Resistivity:

P = OBG – (OBG – Pn)(Rsh obs – Rsh normal)1.2

Conductivity:

P = OBG – (OBG – Pn)(C normal – C obs)1.2

Dxc:

P = OBG – (OBG – Pn)(Dxc obs – Dxc normal)1.2

∆t sonic:

P = OBG – (OBG – Pn)(∆t normal - ∆t obs)3

Where,

OBG = overburden gradient (psi/ft)

Pn = normal pore pressure gradient (psi/ft)

Rsh = Shale resistivity

Example: (resistivity)


OBG = 2.26

Pn = 1.07

Observed Rsh = 0.68 ohm.m

Normal Rsh = 3.50 ohm.m

P = 2.26 – (2.26-1.07) (0.68/3.5)1.2 = 2.00

Eaton’s method is the most widely used even though it requires knowledge of the local overburden gradient.

Establishing Isodensity Lines For The Dxc To establish the isodensity lines for Dxc do the following:

1. Determine the normal compaction trend line

2. Calculate the theoretical values of the observed Dxc for different values of the pressure gradient P using Eaton’s formula:

Dxc obs = (1.2((OBG-P)/(OBG-Pn))0.5) x Dxc normal

By repeating the process at several intervals of 100-500 m, a set of isodensity lines could be created.

Example: Drawing the 1.20isodensity line

Depth = 1000m

Dxc normal = 0.86

OBG = 1.95

Pn = 1.00

Dxc obs = (1.2 ((1.95-1.2)/(1.95-1.00))0.5) x 0.85 = 0.70

For depth 1500m

Dxc normal = 1.05

OBG = 2.04

Dxc obs = (1.2 ((2.04-1.2)/(2.04-1.00))0.5) x 1.05 = 0.88

For depth 2000m

Dxc normal = 1.30

OBG = 2.15

Dxc obs = (1.2 ((2.15-1.2)/(2.15-1.00))0.5) x 1.30 = 1.11

Comparison of Previous Methods According to Elf studies when formation pressures are low (<1.40) the Eaton and the ratio methods give the best results. For formation pressures > 1.40 the Equivalent Depth method is the most suitable.

It should be noted that the level of accuracy of the Equivalent Depth method depends directly on the value of the normal compaction trend. The error is greater the smaller the gradient of log Dxc against depth.


Sigmalog Evaluation

Normalized ROP Evaluation (Prentice)

Evaluation By Direct Observation Of The Differential Pressure Direct observation of factors associated with well equilibrium may provide more accurate and reliable information, and is generally the only means of detecting overpressure not directly associated with undercompaction.

Gas The usefulness of gas shows in qualitative evaluation is described in the section on Gas above. As long as mud weight is close to the equilibrium density, it is possible to monitor background gas, connection gas and the effect of mud weight adjustments on gas shows, so as to achieve satisfactory and continuous evaluation of formation pressure.

Mud Losses Lost circulation may arise for the following two reasons:

• Excessive filtration of mud into a very permeable formation subjected to high differential pressure

• Fracturing of weak horizons (or opening of pre-existing fractures) caused by excessive ∆P

Losses may occur while drilling or be caused by excessive pressure loss due to surging while tripping.

Observing the losses that occur while circulation is in progress, with the well stable under static conditions, provides an accurate picture of well equilibrium. Well balance depends as much on the ∆P as on the fracture pressure.

It is only safe to use formation pressure data inferred from a mud loss if the location of the zone concerned is accurately known. The loss rate depends not only on the ∆P but above all on the porosity and permeability of the loss zone, or the nature of the fracture system.

Kick A kick indicates that formation pressure is greater than the mud weight. Only bottomhole kicks should be taken into account for formation pressure evaluation. Kicks due to gas expansion at the surface are not a direct indication of bottomhole formation pressure.

The kick flow depends on ∆P, the porosity and permeability of the formation.

If a kick occurs it is necessary to shut-in the well, formation pressure can be deduced from the shut -in drill pipe pressure:

P = (MW x Depth x 0.0519) + SIDPP

abnormal subsurface pressure

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