Drilling Fluids Operations Manual

ARPO

ENI S.p.A. Agip Division

ORGANISING DEPARTMENT

TYPE OF ACTIVITY'

ISSUING DEPT.

DOC. TYPE

REFER TO SECTION N.

PAGE.

OF

STAP

P

1

M

1

155

6160

TITLE DRILLING FLUIDS OPERATIONS MANUAL

DISTRIBUTION LIST Eni - Agip Division Italian Districts Eni - Agip Division Affiliated Companies Eni - Agip Division Headquarter Drilling & Completion Units STAP Archive Eni - Agip Division Headquarter Subsurface Geology Units Eni - Agip Division Headquarter Reservoir Units Eni - Agip Division Headquarter Coordination Units for Italian Activities Eni - Agip Division Headquarter Coordination Units for Foreign Activities

NOTE: The present document is available in Eni Agip Intranet (http://wwwarpo.in.agip.it) and a CD-Rom version can also be distributed (requests will be addressed to STAP Dept. in Eni - Agip Division Headquarter) Date of issue:

f e d c b

Issued by

REVISIONS

28/06/99

G. Ferrari 28/06/99

C. Lanzetta 28/06/99

A. Galletta 28/06/99

PREP'D

CHK'D

APPR'D

The present document is CONFIDENTIAL and it is property of AGIP It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given

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REVISION STAP -P-1-M-6160

0

INDEX 1. MANUAL USER’S GUIDE

5

1.1 INTRODUCTION

5

1.2 GUIDE TO USING THE MANUAL

6

1.3 UPDATING, AMENDMENT, CONTROL & DEROGATION

8

2. GUIDE TO DRILLING FLUID PROGRAMMING

9

2.1 DEVELOPMENT OF THE DRILLING FLUID PROGRAMME

10

2.2 CHOICE OF DRILLING FLUIDS 2.2.1 Non-Circulating, Start-Up Drilling Fluids 2.2.2 Circulating, Start-Up Drilling Fluids 2 2.2.3 Drilling Formations With Gradients Less Than 1.0kg/cm /10m 2.2.4 Drilling Fluids For Non-Reactive Formations 2.2.5 Drilling Fluids For Reactive Formations o 2.2.6 Drilling Fluids For Temperatures Greater Than 200 C 2.2.7 Inhibitive And/Or Environmentally Friendly Speciality Fluids

11 11 11 11 11 12 12 13

2.3 CHARACTERISTICS OF THE FLUID SYSTEM

14

2.4 EXAMPLES OF DRILLING FLUID CHOICE 2.4.1 Concomitant Problems 2.4.2 Type Of Drilling Fluid Preferred

16 16 16

2.5 CHOICE OF THE FLUID SYSTEM (Dependent On Its Main Variables)

16

2.6 DRILLING FLUID CHARACTERISTIC PROGRAMMING

17

2.7 WATER-BASED FLUIDS 2.7.1 Optimum Values Of Marsh Viscosity, Solids And Gel 2.7.2 Optimum Values Of Plastic Viscosity And Yeld Point

18 18 19

3. FLUID CHARACTERISTICS

20

3.1 NON-INHIBITIVE WATER BASED FLUIDS

20

3.2 INHIBITED WATER-BASE FLUIDS

37

3.3 OIL BASED FLUID

50

3.4 INHIBITED AND/OR ENVIRONMENTAL FLUIDS

55

4. FLUID MAINTENANCE

72

4.1 WATER BASED FLUIDS MAINTENANCE 4.1.1 Analysing Flow Chart For Water Based Fluid Reports 4.1.2 Maintenance Problems 4.1.3 Chemical Treatment of Contaminents 4.1.4 H2S Scavengers 4.1.5 Poylmer Structures/Relationship

73 73 74 77 78 79

4.2 OIL BASED FLUIDS MAINTENANCE 4.2.1 Analysing Flow Chart For Oil Based Fluid Reports 4.2.2 Maintenance Problems

80 80 81

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5. SOLIDS CONTROL

0

84

5.1 SOLIDS REMOVAL EQUIPMENT SPECIFICATIONS

84

5.2 STATISTICAL DISTRIBUTION OF SOLIDS

84

5.3 EQUIPMENT PERFORMANCE

84

5.4 EQUIPMENT RECOMENDATIONS 5.4.1 Double Shale Shakers 5.4.2 Single Deck Shale Shakers

85 86 87

5.5 SCREEN SPECIFICATION 5.5.1 Nomenclature

88 88

5.6 CYCLONE SYSTEMS

89

5.7 CENTRIFUGE SYSTEMS 5.7.1 PrInciple Of Operation 5.7.2 Centrifuge Processing

90 90 91

6. TROUBLESHOOTING GUIDE

92

6.1 LOST CIRCULATION CONTROL TECHNIQUES

93

6.2 LOSSES IN VARIOUS FORMATION TYPES

94

6.3 CHOICE OF LCM SPOT PILLS 6.3.1 LCM Information 6.3.2 LCM Efficiency

94 95 95

6.4 TROUBLESHOOTING GUIDE 6.4.1 Loss Of Circulation With Water Based Fluids 6.4.2 Loss Of Circulation With Oil Based Fluids

96 96 98

7. STUCK PIPE TREATMENT/PREVENTITIVE ACTIONS 7.1 STUCK PIPE TREATMENT/PREVENTION

101 102

8. DRILLING FLUID TRADEMARK COMPARISONS

105

8.1 DRILLING FLUID PRODUCT TRADEMARKS 8.1.1 Weighting Materials 8.1.2 Viscosifiers 8.1.3 Thinners 8.1.4 Filtrate Reducers 8.1.5 Lubricants 8.1.6 Detergents/Emulsifiers/Surfactants 8.1.7 Stuckpipe Surfactants 8.1.8 Borehole Wall Coaters 8.1.9 Defoamers/Foamers 8.1.10 Corrosion Inhibitors 8.1.11 Bactericides 8.1.12 Lost Control Materials 8.1.13 Chemical Products 8.1.14 Oil Based Fluid Products 8.1.15 Base Liquids And Corrections

106 106 106 106 107 107 107 108 108 108 108 109 109 109 110 112

9. DRILLING FLUIDS APPLICATION GUIDE 9.1 APPLICATIONS GUIDE

113 114

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10. DRILLING FLUID ANALYSIS

0

132

10.1 DRILLING FLUIDS 10.1.1 Density (Fluid Weight) 10.1.2 Marsh Viscosity 10.1.3 Viscosity, Yield Point, Gel Strength 10.1.4 API Filtrate 10.1.5 HPHT Filtrate 10.1.6 Oil, Water, Solids Measurement

133 133 133 134 135 136 137

10.2 WATER-BASED FLUIDS 10.2.1 Sand Content Estimate 10.2.2 pH Measurment 10.2.3 Methylene Blue Capacity Determination 10.2.4 Chloride Content Determination 10.2.5 Calcium Hardness Determination 10.2.6 Calcium And Magnesium Determination 10.2.7 Alcalinity, Excess Lime, Pf, Mf, Pm Measurment 10.2.8 Excess Gypsum Measurment 10.2.9 Semiquantitative Determination Of Sulphurs (Hatch Test) 10.2.10 Fluid Corrosivity Analysis

138 138 139 140 141 142 143 144 145 146 147

10.3 OIL BASED FLUIDS 10.3.1 Electrical Stability Determination 10.3.2 Fluid Alkalinity Determination 10.3.3 Fluid Chloride Determination 10.3.4 Calcium Determination

148 148 149 150 151

APPENDIX A - DRILLING FLUID CODING SYSTEM

152

A.1.

CODE GROUPS

152

A.2.

EXAMPLE CODING

153

APPENDIX B - ABBREVIATIONS

154

B.1. FLUID CODE ABBREVIATIONS

154

B.2. OTHER ABBREVIATIONS

155

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1.

MANUAL USER’S GUIDE

1.1

INTRODUCTION

0

This manual is not a training document, but is intended to be instructional and aimed at engineers and technicians who are already familiar with drilling fluid technology. It is particularly intended to meet with Eni-Agip’s operational requirements. This manual addresses the Company’s fluid operators, drilling engineers and all those involved in the supervision of the work carried out by contractor companies and in the planning or evaluation of the drilling fluids to be employed. However, it does not aim to be a comprehensive all encompassing document giving information on the entire subject, but aims to provide sufficient information to support the company’s technicians in better use of fluid technology. Therefore, this manual does not instruct on how to prepare or maintain drilling fluids, but only to aid in these tasks by providing the information needed to evaluate the advantages and limitations of the various fluid systems, hence maximising drilling performance, reducing reservoir damage in an environmentally friendly and cost effective manner. This document does not describe the decision making process but summarises it through the use of flow charts and forms, organised in a logical sequence. The reader may select a single form or use the entire sequence in order to determine the best solution to their requirements. The method adopted herein, will be explained in the following ‘Guide to Using the Manual’. This document does not include standard industry calculations or charts relating to volumes and capacities or information relating to drilling fluids which are available in industry handbooks.

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GUIDE TO USING THE MANUAL This manual aims to: 1)

Help in the choice of the most applicable drilling fluids necessary to meet with requirements for a well in a targeted area (Refer to section 2) and specifically it’s sub-sections relating to the different types of drilling fluids available. The flowchart below shows the selection process to be followed.

GATHER

INFORMATION AS PER THE FLOW CHART IN SECTION 2.1 IDENTIFY

THE TYPE(S) OF FLUID AS PER THE CHARTS IN SECTION 2.2 VERIFY

THE FEASIBLE CHARACTERISTICS OF THE SYSTEM IN SECTION 2.3 CHECK

THE CHOICE MADE FROM THE DESCRIPTION OF FLUIDS IN SECTIONS 3.1, 3.2, 3.3 and 3.4

DEFINE

THE CHARACTERISTICS OF FLUIDS AS THE PER CHARTS IN SECTIONS 2.6, 2.7

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Provide practical guidelines for: •

Drilling fluid formulations: These are described in sections 3.1, 3.2, 3.3, 3.4 and relate to the description of those drilling fluids which are considered the most applicable and economic for use in various operating conditions. Particular operating conditions may entail modification to these fluid formulations, hence their characteristics, specifically the densities.

•

Fluid Maintenance: This references the most important aspects of the specific fluid systems described and not any procedures relating to general maintenance common to all fluid systems.

•

Contaminating Effects to Drilling Fluids: Other information on contanminants can be found in sections 4.1 ‘Maintenance of Water Based Fluids’ and 4.2 ‘Maintenance of Oil Based Fluids’.

•

Analysis of Daily Fluid Reports: Use the flow charts relating to the fluids described in sections 4.1.1 and 4.1.2 where drilling fluid maintenance problems are identified. These charts follow the general rules in problem solving summarised as follows in the analysis of daily fluid reports.

IS THERE A PROBLEM ?

YES/NO

IF YES, WHAT IS THE PROBLEM ?

ANSWER

WHAT HAS BEEN DONE TO SOLVE IT ?

EVALUATE

WHAT ELSE CAN BE MADE TO SOLVE IT WHICH HAS NOT BEEN MADE YET ?

TAKE ACTION

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3)

4)

5)

6)

1.3

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0

Provide information about solids removal equipment, which may aid in the choice of equipment type and the size. The solids removal equipment in the description of the fluid systems provides equipment recommend nations, see section 5. Describe problems relating to lost circulation and stuck pipe, section 6. Regarding lost circulation, a troubleshooting guide describes remedial actions for various types of losses, in addition to some information concerning lost control materials. For stuck pipe, recommendations on preventive measures are included and treatment to be undertaken. Provide information about drilling fluid products, section 8.1 ‘Comparable Charts of Competitive Drilling Fluid Product Trademark’ compares similar products and their functional performances and consequently the various products, at different concentrations. This indicates the different product concentrations and costs. Therefore technical and/or economical analysis of these different products should be carried out the concentrations necessary in similar operational conditions and results. Provide analysis procedures in section 10 ‘Drilling Fluid Analysis’ provides analysis procedures which complies with API RP 13B-1 regulations dated June 1, 1990. The procedures with state listed on order to simplify the execution of various analysis showing the results achieved the conversion factors.

UPDATING, AMENDMENT, CONTROL & DEROGATION This manual is a ‘live’ controlled document and, as such, it will only be amended and improved by the Corporate Company, in accordance with the development of Eni-Agip Division and Affiliates operational experience. Accordingly, it will be the responsibility of everyone concerned in the use and application of this manual to review the policies and related procedures on an ongoing basis. Locally dictated derogations from the manual shall be approved solely in writing by the Manager of the local Drilling and Completion Department (D&C Dept.) after the District/Affiliate Manager and the Corporate Drilling & Completion Standards Department in Eni-Agip Division Head Office have been advised in writing. The Corporate Drilling & Completion Standards Department will consider such approved derogations for future amendments and improvements of the manual, when the updating of the document will be advisable.

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GUIDE TO DRILLING FLUID PROGRAMMING This section is integrated with the following sub sections and covers all the various types of drilling fluids.

GATHER

INFORMATION AS PER FLOW CHART SECTION

IDENTIFY

THE TYPE(S) OF FLUID AS PER CHARTS AT SECTION

VERIFY

THE FEASIBILITY CHARACTERISTICS OF THE SYSTEM AT SECTION

CHECK

THE CHOICE MADE FROM THE DESCRIPTION OF FLUIDS IN DOCUMENTS

DEFINE

THE CHARACTERISTICS OF FLUIDS AS PER CHARTS

The Eni-Agip codes are fully described in Appendix A.

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2.1

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DEVELOPMENT OF THE DRILLING FLUID PROGRAMME

GEOGRAPHICAL LOCATION

GEOLOGICAL INFORMATION

DEPH LITHOLOGY CHEMICAL PROPERTIES PHYSICAL PROPERTIES MINERALOHY

ENVIROMENTAL PROTECTION

ON/OFF SHORE

LEGISLATION WASTE REMOVAL MODALITES DRILLING PROGRAMME GRADIENT DRILL TUBING PROFILES DEVIATION PROGRAM HYDRAULIC PROGRAM LENGTH

WASTE REMOVAL COSTS

TYPE OF PLANT

TARGET WELL DATA

LOGISTICS TYPE OF WATER

CHARACTERISTICS REQUIRED PHYSICAL CHAR. SOLIDS REMOVAL EQUIPMENT

CHARACTERISTICS REQUIRED

MIXING FACILITIES STORING AREAS SUPPLY

PHYSICAL/CHEMICAL CHARACTERISTICS

LAB TESTING INTERACTIONS FORMATION/FLUID

TYPE(S) OF FLUID FLOW LINES: MAIN IF REQUIRED AND/OR AVAILABLE

DRILLING FLUID PROGRAMME

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2.2

CHOICE OF DRILLING FLUIDS

2.2.1

Non-Circulating, Start-Up Drilling Fluids

Systems

Agip Code

Fresh Water

FW-GELI+FW

Seawater

2.2.2

11 OF 155

0

AVA

Bariod

Dowell

MI

BH Inteq

AVA Spud Mud

FW+Gel Pills

FW+Gel Pills

FW+Gel Pills

FW+Gel Pills

FW-GE+SW

SW Spud Mud

SW+H.VIS Pills

SW+H.VIS Pills

SW+H.VIS Pills

SW-GG

AVAGUM

LO-LOSS

SM(X)

LO-LOSS

LO-LOSS

SW+H.VIS Pills

Circulating, Start-Up Drilling Fluids

Fresh Water

FW-GE

AVAGEL

Spud Mud

Spud Mud

Spud Mud

Spud Mud

Seawater

SW-GE

AVAGEL

Prehydrated Gel

Prehydrated Gel

Prehydrated Gel

Prehydrated Gel

2.2.3

Drilling Formations With Gradients Less Than 1.0kg/cm2/10m

Aerated

FW/SW-AT

Foam Base

FW-SF

Mixed

AR-MM

Air/FoamBase

AR-SF

Air-Base

AR-AR

2.2.4

Drilling Fluids For Non-Reactive Formations 2

With Gradient Between 1.03 - 1.5kg/cm /10m BentoniteBase

FW/SWGE-PO

AVAGELPOL

Gel/Polymer

Gel/Polymer

Gel/Polymer

FW/SW-LS

AVAFLUID

Q-BROXIN

FCL Muds

Spersene

UNI-CAL

GELEX Systems

Low-Solid/ BENEX

Spersene /XP20

UNICAL/ LIGCO

Desco

Desco

FW-LW

AVABEX

X-TEND II

Gel/Polymer

2

With Gradient > 1.5kg/ cm /10m BentoniteBase

FW/SW-LSCL FW/SW-TA

AVA Fluid/LIG

Q-Broxin /CC16

FCL/CL

Desco

Desco

Desco o

With Gradient >1.5 High Temperature (+/- 150-200 C) BentoniteBase

Oil-Base

FW/SWCL-RX

AVAREX

FW/SWCL-PC

+POLICELL ACR

DS-IE

AVOIL

OC16/DUREN

FCL/CL/HITEMP

SPER/XP20/R ESINEX

+THERMACHECK

+POLYTEMP

+POLY RX

Invermul

Interdril

Versadril

LIGCO/CHEM TRO-X +PYROTROL Carbodril

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2.2.5

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0

Drilling Fluids For Reactive Formations

Systems

Agip Code

AVA

Bariod

Dowell

MI

BH Inteq

2

With Gradient Between 1.03 - 1.5kg/cm /10m Encapsulators

Inhibitors

FW-PK PAC Polymer

FLR Polymer Muds

Polypac Muds

MIL-PAC Muds

EZMUD

ID-Bond

Polyplus

New-Drill

K Chloride

K Chloride

K Chloride

Salt Saturated

Salt Saturated

Salt Saturated

Salt Saturated

AVAKLM

KLM

KLM

KLM

KLM

AVAFLUID/G YPS

GYP/QBROXIN

Gypsum Mud

GYP/SPERSE NE

Gypsum Mud

FW/SW-LI

AVAFLUID /LIME

Lime Muds

Lime Muds

Lime Muds

Lime Muds

DS-IE

AVOIL

Invermul

Interdril

Versadril

Carbodrill

FW/SW-PA

AVAPAC

FW/SW-PC

Polivis

FW/SW-KC

AVA-PC

POT Chloride

FW/SW-BR FW/SW-SS FW/SW-MR FW/SW-GY

Oil-Base

AVA-Polysalt

2

With Gradient >1.5kg/cm /10m Encapsulators

FW/SW-PC

Inhibitors

FW/SW-KBPC

POLVIS

EZ-Mud

ID-Bond

Polyplus

New-Drill

K/POLIVIS

K/EZ-MUD

K/ID-Bond

K/ Polyplus

K/ New-Drill

AVAKLM

KLM

KLM

KLM

KLM

AVAPOLYSA LT

Salt Saturated

Salt Saturated

Salt Saturated

Salt Saturated

FW/SW-GY

AVAFLUID/G YS

GYP/Q BROXIN

Gypsum Mud

Gyp/Spersene

Gypsum Mud

FW/SW-LI

AVAFLUID

Lime Muds

Lime Muds

Lime Muds

Lime Muds

Invermul

Interdril

Versadril

Carbotec

FW/SW-MR FW/SW-SS

/LIME Oil-Base

DS-IE

AVOIL

o

)

With Gradient >1.5 And High Temperature (150-200 C Oil-Base

2.2.6 Oil-Base

DS-IE

AVOIL

Invermul

Interdril

Versadril

Carbotec

Versadril

Carbotec

Drilling Fluids For Temperatures Greater Than 200oC DS-IE

AVOIL

Invermul

Interdril

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2.2.7

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Inhibitive And/Or Environmentally Friendly Speciality Fluids

Systems

Agip Code

AVA

Baroid

Dowell

Mi

B.H.Inteq

2

Formations With Gradient Between 1.03 - 1.5kg/cm /10m Inhibitors

FW/SW-K2

AVA-PC2

K Carbonate

K Carbonate

K Carbonate

K Carbonate

FW/SW-KA

AVA-PA

K Acetate

K Acetate

K Acetate

K Acetate

HF 100

Sansoil

Biodrill

Versaclean

FW/SW-GL Oil-Base

FW/SW-CT

AVA-CAT

CAT I

LT-IE

AVOIL-LT

Enviromul

Interdril Nt

M CAT

LT-IE-50

Baroid 50/50

Interdril 50/50

EB-IE

Petrofree

Carbodril Sea Carb.Sea 50/50

OF-IE

Novadriill

UT-IE

Ultidrill 2

Formations With Gradient>1.5kg/cm /10m Oil-Base

LT-IE

AVOIL-LT

Enviromul

Interdrill Nt

Versaclean

OF-IE

Carbotec Sea

Novadrill

UT-IE

Ultidrill o

Formations With Gradient>1.5 AND HIGH TEMPERATURE (150-200 C) Oil-Base

LT-IE

AVOIL-LT

Enviromul

Interdrill Nt

Versaclean

OF-IE

Carbodril Sea

Novadrill

UT-IE

Ultidrill o

Drilling Fluids For Temperature More Than 200 C BentoniteBase Polymer-Base Oil-Base

FW/SW-HT-GE

AVAGELTERM

Duratherm

Pyro-Drill

FW/SW-HT

AVATEX

Thermadril

Polytemp

Envirotherm

Pyro-Drill

LT-IE

AVOIL-LT

Enviromul

Interdril Nt

Versaclean

Carbotec Sea

2.3

X

X

X

BENTONITICO-CMC

X

X

X

FW SW-LS

LIGNOSOLFONATE

X

X

LOW SOLIDS WITH BENT.EXTENDER

X

FW SW-CL

CROMOLIGNIN

X

FW-PK

AGIPAK (KCMC)

X

FW SW-PA

PAC (DRISPAC)

X

FW SW-PC FW SW-KC

FW-LW

X X X

D1

B

MUD

T1

CUTTINGS

B

COSTS

lubricant properties

A

density

B

temperature

B

solids-removal eq.

convertible

B

re-use

logisti difference

B

B

B

B

B

B

B

B

B

A

M

T1

D1

B

B

B

B

B

B

A

B

B

M

B

T2

D4

B

B

B

M

M

B

B

M

B

A

A

T1

D1

B

B

B

B

B

B

A

B

B

B

M

T3

D4

B

B

B

M

X

M

B

B

B

M

A

A

T1

D1

B

B

B

B

X

X

M

B

B

M

M

A

A

T2

D1

B

M

B

B

PHPA

X

X

X

M

B

M

M

B

A

A

T2

D3

B

M

B

B

X

X

X

X

A

M M/B

M

A

B

A

T2

D3

B

A

M

A

POTASSIUM CARBONATE

X

X

A

M

A

A

B

A

T2

D3

B

A

B

B

FW-KA

POTASSIUM ACETATE

X

X

A

M M/B

M

A

B

A

T2

D3

B

A

B

B

FW SW-SS

SALT SATURATED

X

X

X

A

M

B

A

A

B

A

T2

D4

B

M

A

A

FW SW-GL

CLYCOL

X

X

X

M

B

B

A

A

M

A

T2

D3

A

A

B

B

FW SW-CT

CATIONIC

X

X

X

A

A

A

A

A

A

T2

D3

B

A

A

A

FW SW-MR

MOR-EX (KLM)

X

(X)

X

A

B

A

A

A

A

T2

D4

B

A

B

M

GYPSUM

X

(X)

A

M

A

M

B

M

T3

D4

B

B

B

M

FW SW-GY

(X)

X

B

B

= 100 °C MAX

D1

= 1.2 MAX

T2

= 150 °C MAX

D2

= 1.5 MAX

B

= LOW

T3

= 200 °C MAX

D3

= 1.8 MAX

T4

= 250 °C MAX

D4

= 2.1 MAX

D5

= 2.4 MAX

ENV.

= ENVIRONMENTALLY IMPACT

TEMPERATURE

DENSITY' Kg/l

14 OF 155

T1

= MEDIUM

PAGE

= HIGH

M

REVISION

A

0

POTASSIUM CHLORIDE

FW-K2

IDENTIFICATION CODE

GUAR GUM SUSPENSION

B

STAP -P-1-M-6160

SW-GG FW SW-GE-PO

maint. difference

X

LGS tolerance

X

formation inhibition

X

dispersed

non-dispersed

sea water

BENTONITE

LT oil

fresh water

FW SW-GE

diesel

SYSTEM

AGIP CODE

ARPO

alternative oil

OF THE FLUIDS SYSTEMS

cutting inhibition

CHARACTERISTICS


ENV.

CHARACTERISTICS OF THE SYSTEM

CHARACTERISTICS OF THE FLUID SYSTEM

The level of solids removal equipment as indicated in the ‘Description of Fluid Systems’ refers to the equipment recommended in section 5.

BASE FLUID

lubricant properties

COSTS

CUTTINGS

MUD

B

M

M

T2

D4

B

B

B

M

A

M

A

A

T4

D3

B

A

B

B

A

A

A

M

A

B

A

A

T4

D5

A

B

A

A

A

A

A

M

A

A

A

A

T4

D5

A

M

M

A

A

A

M

A

M

M

A

A

T2

D2

A

M

M

A

X

A

A

A

M

A

B

A

A

T2

D3

A

A

B

A

POLYOLEFINE I.E.

X

A

A

A

M

A

M

A

T3

D4

A

A

B

A

UT-IE

ULTRA LT OIL I.E.

X

A

A

A

M

A

M

A

A

T2

D4

A

A

B

A

DS-IE-100 LT-IE-100

100% DIESEL I.E.

A

A

A

M

A

A

A

A

T4

D5

A

A

A

A

A

A

A

M

A

A

A

A

T4

D5

A

A

A

A

DS-IE

DIESEL INVERT EMULSION

LT-IE

LOW TOXICITY OIL I.E.

X

LT-IE-50

E.I. 50/50

X

EB-IE

ESTER-BASE I.E.

OF-IE

non-dispersed

alternative oil

LT oil

sea water

diesel

fresh water

X

X

X

X X

100% LT OIL I.E.

A

density

convertible

M

B

X

X

LIME FOR T. MORE THAN 200 °C

temperature

logistic difference

A

B

X

FW SW-LI FW SW-HT

solids-removal eq.

maint. difference

B

B

SYSTEM

re-use

LGS tolerance

M

AGIP CODE

formation inhibition

cutting inhibition

X

OF THE FLUID SYSTEMS

IDENTIFICATION CODE

dispersed

CHARACTERISTICS

ARPO


ENV.


STAP -P-1-M-6160

.

0

= 1.5 MAX

T3

= 200 °C MAX

D3

= 1.8 MAX

T4

= 250 °C MAX

D4

= 2.1 MAX

D5

= 2.4 MAX

T2

= LOW

B

= ENVIRONMENTALLY IMPACT

DENSITY Kg/l

15 OF 155

D2

= MEDIUM

M

TEMPERATURE

PAGE

= 1.2 MAX

= 150 °C MAX

= 100 °C MAX

= HIGH

ENV.

D1

T1

A

REVISION

The level of solids removal equipment as indicated in the ‘Description of Fluid Systems’ refers to the equipment recommended in section 5.

BASE FLUID

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IDENTIFICATION CODE

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2.4

2.4.1

0

EXAMPLES OF DRILLING FLUID CHOICE (dependent on the drilling performance needs) Concomitant Problems o

High Deviation (>30 ) X

Very Reactive Formations High Differential Pressure

X

Risk Of Lost Circulation

X

X

High Density (>1.9 SG)

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X X

X X

High Temperature (>150 ) X

Risk Of Hydrated Gas

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X X

X

X

X

X

X

Type Of Drilling Fluid Preferred 1 1

Lignosulfonate Fluid

2 1

Inhibitive Fluids

1

2

Polymer-Base Fluids

1

1

1

1 1

2

3

2

3

2

3

1

2

1 2

1

Inhibition

System

Density Max. (kg/I)

Temperature o Max. ( C)

Maintenance Difficulty

Cost

None

FW-GE

1.2

100

Low

Low

FW-LS

2.2

170

Low

Low

FW-CMC

1.2

100

Low

Low

FW-PA

1.6+

150

Medium

Medium

FW-PC

1.8+

150

Medium

Medium

FW-PK

1.2

100

Low

Low

FW-LI

2.1

130

Medium

Low

FW/SW-GY

2.1

170

Medium

Low

FW/SW-KCPC

1.8+

150

High

High

FW-MR

2.1+

100

High

High

DS-IE

2.4

>250

Medium

Low/Medium

Inhibitive

3 2

CHOICE OF THE FLUID SYSTEM (Dependent On Its Main Variables)

Encapsulative

1

Vertical reading, i.e., high density, high temperature; 1st OBM, 2nd LS.

Order of preference: 1>2>3.

I N C R E A S E

X

X

Oil-Base Fluid (DS, LT, EB, PO)

2.5

X

Vertical reading, i.e., high density, high temperature; 1st OBM, 2nd LS.

Order of preference: 1>2>3.

2.4.2

16 OF 155

Note:

The systems examined above are only a portion of that available.

Note:

The high, medium, or low cost is evaluated with consideration of the inhibition grade.

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2.6

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0

DRILLING FLUID CHARACTERISTIC PROGRAMMING Characteristics

Surface Phases

Intermediate Phases

Final Phases

Main Problems

• Hole Cleaning • Losses

• Gradients • Reactivity

• Formation Damage

Density

Minimum to avoid losses.

More than pore and/or collapse gradients, less than fracture.

As low as possible compatibly with pore and/or collapse gradients, less than fracture gradient.

Plastic Viscosity

This value depends upon density and fluid type. Maintain density as low as possible (in both technical and economic terms).

Yield Point

Sufficiently high to clean the hole, but not so high to limit solids removal

Same parameters as initial phases

Same parameters as initial phases

(+/-6-10gr/100cmq).

(+/- 3-8gr/100cmq).

Sufficient to avoid settling without stressing the formation while tripping.

Sufficient to avoid settling without stressing the formation while tripping.

Carefully evaluate the formations and fluid density

Commonly low to limit seepage formation and damage.

(+/- 10-15gr/100cmq). Sufficiently high to suspend cuttings and yield point.

Gels

Formulate them to well conditions. Api Filtrate HP/HT Filtrate

Particular controls are not generally required (15-20cc/30’), estimate for each case.

(average values 4-10 cc/30’).

Cake

Suitable to support unconsolidated formations.

As low as possible.

Less damaging as possible.

Solids%

Dependent on the system chosen, optimise HGS, LGS and MBT. Each system has a different solids tolerance.

Dependent on the system chosen, optimise HGS, LGS and MBT. Each system has a different solids tolerance.

Use of non damaging weighting agents ( which can be acidfield) or brine is preferred. Maintain LGS values at minimum.

3

MBT (kg/m )

Dependent on the minimum value and/or system tolerance to the drilling fluid chosen.

pH

8
Chemical Characteristics

Dependent on the drilling fluid chosen.

Compatible to the fluids and shales of the reservoir.

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18 OF 155


2.7

WATER-BASED FLUIDS

2.7.1

Optimum Values Of Marsh Viscosity, Solids And Gel

0

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2.7.2

19 OF 155

Optimum Values Of Plastic Viscosity And Yeld Point

0

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20 OF 155


3.

FLUID CHARACTERISTICS

3.1

NON-INHIBITIVE WATER BASED FLUIDS

0

This section contains descriptions of the various water based drilling fluids, their applications and limitations. The Eni-Agip codes, abbreviations and symbols used in this section are listed in Appendix A and Appendix B.

ARPO

IDENTIFICATION CODE

PAGE



0

DESCRIPTION OF THE SYSTEM

AGIP CODE

BENTONITE BASED FLUID

FW-GE

ENV.

Cuttings

Mud

A

Cost

B

Lubricant Properties

Convertible

B

Density

Logistic Difference

B

Temperature

Mainten. Difference

B

Solids-removal Eq.

LGS Tolerance

B

Re-use

Formation Inhibition

X

X

Cutting Inhibition

Dispersed

Non-dispersed

LT Oil

Alternative Oil


Diesel

Sea Water

BASE FLUID

Fresh Water

21 OF 155

B

T1

D1

B

B

B

B

APPLICATION - Drilling start-up; - Viscose pills; A clay base should be provided to more complex polymer-base fluid; - After prehydrating, sea water can be added; - Specific treatments may adapt characteristics to the needs; - Easily convertible to more complex systems.

LIMITATIONS - Highly sensitve to chemical contaminants; - Low solids tolerance; - Unadequate characteristics for situations other than drilling start-up.

15

20

9.5

FORMULATION

PRODUCTION FRESH WATER BENTONITE (OCMA) CAUSTIC SODA

MIXING TIME:

+/- 25 m 3 /hr

320

kg-l/m 3

40-70 1-2

50

Electrical stability (volt)

3

30

O/W ratio

10

MBT(Kg/m3 equiv.)

10

Ca (gr/l)

60

NaCl (gr/l)

1.15

Mf

8.5

Pf

12

Pm

API Filtrate (cc/30')

6

pH

Gel 10'(gr/100cm2)

1

Sand (% in vol)

Gel 10" (gr/100cm 2)

5

Water (% in vol.)

Yield point (gr/100cm2 )

6

Oil (% in vol.)

Plastic visc. (cps)

40

Solids (% in vol.)

Funnel visc. (sec/qt)

1.3

API HTHP (cc/30')

Density (SG)

CHARACTERISTICS OF THE DRILLING FLUID

ARPO

IDENTIFICATION CODE

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22 OF 155


0

MAINTENANCE:

SAND GROUNDS

SHALES

GYPSUM/ANHYDRITE

SALT

+

=/+

+

+

=

+

=/--

+

+

+

=/+ +/--

+

+

+

+/--

+

+

+

+

+

+

+

CO 2

--

H S 2

--

+

+

%Sand

NaCl

Ca

MBT

Solids

Mf

Pf / Pm

=/+

+/--

CEMENT

pH

Filtrate

Gels

Yield

PV

CONTAMINANTS

Density

- Maintain an adequate solids percentage; - Use water and bentonite to control viscosity and/or vary pH.

+

--

=/--

--

=/--

--

+

+

-SO - DILUTION 4 + - Na CARBONATE - CONVERT TO FW-LS - CONVERT TO FW-GY +

+

--

--

--

+

--

--

--

- DESANDERS

- CENTRIFUGE - DILUTION - CONVERT TO FW-LS

+

+

REMEDIALS

+

- DILUTION, CMC - CONVERT TO FW -SS - DILUTION - Na BICARBONATE

- DEGAS - ALTERNATE TREATMENT WITH NaOH and Ca(OH)2

STINKING SMELL GREEN OR BLACK COLOUR

- PREVENTIVE TREATMENT WITH SCAVENGER. - HYDROGEN PEROXIDE + NaOH. - DEGAS

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IDENTIFICATION CODE

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0

AGIP CODE

DESCRIPTION OF THE SYSTEM GUAR-GUM SUSPENSION

SW-GG

ENV.

Cuttings

Mud

B

B

Electrical Stability (volt)

NaCl (gr/l)

B

O/W Ratio

D1

Cost

Density

T1


Temperature

X

X

Mf

Solids-removal Eq.

Re-use

Convertible

Logistic Difference

Maint. Difference

LGS Tollerance


Cutting Inhibition

Dispersed

Non-dispersed

Alternative Oil


LT Oil

Diesel

Sea Water

BASE FLUID

Fresh Water

23 OF 155

DESCRIPTION AND APPLICATION - Drilling start-up - Viscose pills in sea water or in presence of electorlytes; - Can be used as Bentonite extender (in low concentrations); - Reduced logistical problems in drlling start-up.

ADVANTAGES AND LIMITATIONS - Fresh water is needed for hydration; - Low cost; - Low concentration usage; - Fermention; - Non resistant to high temperatures; - Suitable for viscose pills only.f

FORMULATION

MIXING TIME:

7

PRODUCT

kg-l/m 3

SEA WATER GUAR GUM BACTERICIDE

10 as needed

+/- 30 m 3 /hr

MBT(kg/m3 equiv.)

Ca (gr/l)

Pf

Pm

pH

NC

Sand (% in vol)


15

Water (% in vol.)

Gel 10'(gr/100cm2)

15

Oil (% in vol.)

Gel 10" (gr/100cm2)

30

Solids (% in vol.)

Yield Point (gr/100cm2)

20

API HTHP (cc/30')

Plastic Visc. (cps)

1.03 100+

Density (SG)

Funnel Visc. (sec/qt)


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24 OF 155


0

PREPARATION - Avoid adding NaOH to the system; - Use a bactericideif not used immediately; - For hydrations, stir at high speed for approx. 1hr; - 'Fish eyes' can be easily observed.

ARPO

IDENTIFICATION CODE

PAGE



0


AGIP CODE

BENTONITE-AND CMC-BASE FLUID

FW-GE-PO

ENV.

Mud

B

B

B


B

Cuttings

D1

Excess Lime (kg/m3)

T1

Cost

B


A

Calcium (gr/l)

B

Density

Convertible

B

NaCl (gr/l)

Logistic Difference

B

Temperature

Maint. Difference

B

Solids-removal Eq.

LGS Tolerance

B

Re-use


X

Cutting Inhibition

Dispersed

Non-dispersed

Alternative Oil


LT Oil

Sea Water X

Diesel

Fresh Water

BASE FLUID

X

25 OF 155

DESCRIPTION AND APPLICATION - Drilling start-up when FW-GE characteristics are not sufficient; - Drilling non reactive formations with gradient <1.1 kg/cm2.

ADVANTAGES AND LIMITATIONS - Easy maintenance and low cost; - Highly sensitive to chemical contaminants; - Low solids tolerance.

15

4

15

2

9.5

60

FORMULATION

MIXING TIME:

PRODUCT

kg-l/m 3

FRESH/SALT WATER BENTONITE CAUSTIC SODA CMC HV CMC LV

20 - 60 1-3 0-6 2 - 10

+/- 25 m 3 /hr

MBT(kg/m3 equiv.)

15

Mf

80

Pf

1.15

Pm

20

pH 8.5

Sand (% in vol)

10

Water (% in vol.)

8

Oil (% in vol.)


2

Solids (% in vol.)

Gel 10'(gr/100cm2)

4

API HTHP (cc/30')

Gel 10" (gr/100cm 2)

5

Plastic Visc. (cps)

40


1.03

Density (SG)

Yield Point (gr/100cm 2)


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26 OF 155


0

MAINTENANCE: To control RHEOLOGY: - Increase: Bentonite, CMC HV; - Decrease: Solids-Removal, Dilution, Lignosulfonates.

+

=/+ +/-+/--

SALT CEMENT

CO 2

--

H2 S

--

+

+

=/+ =/--

--

--

+

+

=/--

--

+

+

+

+

+

+

+

+

+

+

+

=/--

+

-SO4 - DILUTION + - Na CARBONATE - CONVERT TO FW-LS - CONVERT TO FW-GY +

+

--

--

--

+

--

--

--

- DESANDERS - CENTRIFUGE - DILUTION - CONVERT TO FW LS

+

+

+

REMEDIALS

%Sand

+/--

NaCl

=

Ca

GYPSUM/ANHYDRITE

MBT

+

Solids

+

Mf

+

Pf / Pm

SHALES

pH

=/+

Filtrate

+

Gels

PV

SAND GROUNDS

CONTAMINANTS

Yield

Density

To control FILTRATE: - CMC LV and/or Bentonite.

+

- DILUTION, CMC - CONVERTIRE IN FW SS - DILUTION - Na BICARBONATE - DEGAS

STINCKING SMELL GREEN OR BLACK COLOUR

- PREVENTIVE TREATMENT WITH SCAVENGER. - HYDROGEN PEROXIDE + NaOH - DEGAS

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IDENTIFICATION CODE

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0

AGIP CODE

DESCRIPTION OF THE SYSTEM LOW-SOLIDS FLUID WITH BENTONITE EXTENDER

D1

B

B

B

Mud

Cost

T1


A

Cuttings

ENV.

Density

A

Temperature

B

Solids-removal Eq.

M

Re-use

LGS Tolerance B

Convertible

B

Logistic Difference

M


Cutting Inhibition

Dispersed

X

Maint. Diference

X

Non-dispersed

Alternative Oil

LT Oil

Diesel

Sea Water

FW-LW


BASE FLUID

Fresh Water

27 OF 155

B

DESCRIPTION AND APPLICATION - Low density and high viscocity with a reduced solids-contents; - Reduced transportation problems; - Optimum for drilling start-up or when high mixing time is required.

ADVANTAGES AND LIMITATIONS - Sensitive to chemical contaminants; - Sensitive to chlorides; - Low solids tolerance.

3

15

6

FORMULATION

PRODUCT

9.5

8

MIXING TIME:

m3 /h

kg-l/m 3

30

BENT. EXTENDER

0,12

NaOH/KOH

1-1,2

(CMC LV)

2-10

: 50

0.1

MAX MAX

FRESH WATER BENTONITE

Electrical Stability. (volt)

O/W Ratio

MBT(kg/m 3equiv.)

Ca (gr/l)

NaCl (gr/l)

Mf

Pf

Pm

pH

5

Sand (% in vol)

Gel 10'(gr/100cm 2)

2

Water (% in vol.)

Gel 10" (gr/100cm 2)

8

Oil (% in vol.)


5

Solids (% in vol.)

Plastic Visc. (cps)

45

API HTHP (cc/30')


1.03


Density (SG)


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28 OF 155


0

MAINTENANCE

CaSO4

=

-

-

-

+

=/-

SOLIDS

+

+

+

+

+

+

EXCESS POLYMER

=

-

-

-

-

-

% Sand

=/-

NaCl

+

Ca

+

MBT

+

Solids

Filtrate

+

Mf

Gels

Pf / Pm

Yield

+/-

CONTAMINANTS

pH

PV

Density

- Prehydrate bentonite before adding extencer; - Extender should be prehydrated before adding to the active system; - Addition ratio is1 kg of extender every 250 kg of bentonite; - Control solids as per range indicated; - Efficiency of shale shakers and cyclones is important; - High quantity of extender is an energic encapsulating agent.

REMEDIAL

SALT, SALT WATER

=

+

=

+

+

CONVERT TO SW-PO

SODA ASH + EXTENDER

ADD EXTENDER, DILUTE

ADD. BENTONITE

ARPO

IDENTIFICATION CODE

PAGE



0


AGIP CODE FW/SW-LS

LIGNOSULPHONATE-BASE FLUIDS

ENV.

DESCRIPTION

Mud

M

Cuttings

Convertible

B

Cost

Logistic Tolerance

B


Maint. Tolerance

A

Density

LGS Tolerance

B

Temperature


B

Solids-removal Eq.

Cutting Inhibition

X

Re-use

Dispersed

Non-dispersed

Alternative Oil


LTOil

Sea Water X

Diesel

Fresh Water

BASE FLUID

X

29 OF 155

B

T2

D4

B

B

B

M

- Most versatile fluid. Ideal for exploration wells; - High solids-tolerance. Easy maintenance; - High tolerance to chemical contaminants; - Convertible to Lime or Gypsum-based fluids.

ADVANTAGES AND LIMITATIONS - Environmental impact concerns; - Lignosulphonates are uneffective in salt saturated fluids; - Optimum pH is 10, this value helps shale dispersion; - Lignosulphonate stabilises the collidal dispersion of shale in water reducing the effectiveness of any encapsulators.

FORMULATION

7 60

PRODUCT

0.5

20

3

0.7

70

kg-l/m 3

MIXING TIME:

+/- 20 m 3 /hr + weighting time

20 - 70 10 - 30 1-4 2-10 / 10 - 20 as needed


1

O/W Ratio

9.5 10.5

FRESH (SALT) WATER BENTONITE FCL NaOH CMC LV / LIGNIN BARITE

MBT(kg/m3 equiv.)

Ca (gr/l)

NaCl (gr/l)

40

Mf

10

Pf

2

Pm

10

15

pH

5

2

Sand (% in vol)


1

12

Water (% in vol.)

Gel 10'(gr/100cm2 )

2

45

Oil (% in vol.)

Gel 10" (gr/100cm2 )

5

60

Solids (% in vol.)

Yield Point (gr/100cm2 )

38

2.1

API HTHP (cc/30')


1.1

Plastic Visc. (cps)

Density (SG)


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30 OF 155


0

MAINTENANCE:

+

+

+

+

=/-

+

=/-

-

=/-

+

-

-

=/+

CO2

-

+

+

+

=/+

-

-

+

CEMENT

=

+/-

+

+

+

+

+

=/-

REMEDIAL

- SOLIDS CONTROL - TREATMENT WITH FCL+SODA

+

+

- FCL + SODA ASH - ADD CMC LV - CONVERT TO FW-GY

+

SALT

% Sand

+/-

-

NaCl

=

=/-

Ca

GYPSUM/ANHYDRITE

=/-

MBT

+

Solids

+

Mf

+

Pf / Pm

Gels

+

pH

Yield

SHALE

CONTAMINANTS

Filtrate

PV

Density

- Dependent on the solids percentage; - Thanks to the system flexibility characteristics may be adapted according to the needs by simply adding additives; - For high temperature and/or high density, use lignin as an alternative to CMC to control filtrate.

-FCL + SODA ASH -CMC LV -CONVERT TO SS

- FCL + C.SODA and/or LIME

+/=

-PRETR. WITH NaHCO3 - FCL+CMC

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IDENTIFICATION CODE

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AGIP CODE

(CHROME)-LIGNIN-BASE FLUIDS

FW/SW-CL

ENV.

Mud

B

Cuttings

Convertible

B

Cost

Logistic Difference

B


Maint. Difference

A

Density

LGS Tolerance

B

Temperature


B

Solids-removal Eq.

Cutting Inhibition

X

Re-use

Dispersed

Alternative Oil

Non-dispersed


LT Oil

Sea Water

Diesel

Fresh Water

(X)

0


BASE FLUID

X

31 OF 155

M

T3

D4

B

B

B

M

DESCRIPTION AND APPLICATION - Development of Lignosulphonate-based fluids at high temperatures: To aid filtrate control add chrome Lignin which integrates the thinning effect of Lignosulphonate.

ADVANTAGES AND LIMITATIONS - Versatile and economical system; - High solids tolerance; - Cr-Lignin is a less effective scavenger than lignosulphonate. Its effectivness is further reduced in sea water and becomes completely uneffective in presence of calcium; - Environmental impact concerns.

Mf

Ca (gr/l)

MBT(kg/m 3equiv.)

8

9.5

1

0.3

0.5

0.2

60

2.1

60

40

8

1

10

2

10

40

11

3

0.7

1.5

MAX

10

FORMULATION

MIXING TIME:

3 m /h

PRODUCT

kg-l/m 3

FRESH WATER BENTONITE FCL CL NaOH POLYMERS (CMC, PAC) BARITE

20-70 10-30 10-30 0.5-5 0-10 as needed

20 + WEIGHTING TIME


Pf

30

O/W Ratio

Solids (% in vol.)

10

NaCl (gr/l)

API HTHP (cc/30')

4

Pm

Gel 10'(gr/100cm 2)

1

pH

Gel 10" (gr/100cm 2)

5

Sand (% in vol)

2 Yield Point (gr/100cm )

8

Water (% in vol.)

Plastic Visc. (cps)

40

Oil (% in vol.)


1.08


Density (SG)

CHARACTERISTICS OF DRILLING FLUIDS

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0

MAINTENANCE - High solids tolerance; - Up to 150°C, deflocculant effect is due to FCL; over this temperature CL is most commonly employed; - Alkalinity control is highly important to guarantee Cr-Lignin solubility; - Dump if contamination from carbonates or bicarbonates is present.

- RHEOLOGY

- Decrease: add FCL/CL/ Soda, dilute only in case of excess solids; - Increase: add prehydrated and FCL protected Bentonite carefully. Evaluate the addition of polyacrylates.

- FILTRATE

SHALE

+

+

+

+

-

-

-

CEMENT

=

+/-

+

+

+

+

+

CaSO4

=

+/-

+

+

+

+/-

=

=/+

=/+

+/-

+

+

+

-

-

-

CARBONATES/ BICARBONATES

=

+

+

+

=/-

+/-

+

TEMPERATURE

+

+

+

+

SALT

=/-

+

+

% Sand

NaCl

Ca

MBT

Solids

Mf

Pf / Pm

pH

Filtrate

Gels

Yield

CONTAMINANTS

PV

Density

- Maintain a reduced quantity of Bentonite, add CL, and HPHT polymers.

REMEDIAL

- CENTRIFUGE - +FCL + CL + NaOH - DILUTION =/+

- + NaHCO3 O Na2CO3 - + FCL + CL

+

- + Na2SO4 E/0 NaOH - + FCL + CL - CONVER.IN FW-GY +

+/-

- + FCL + CL - CONVER.IN FW-SS - FOR T. >150° C UTILIZZARE DS-IE - + LIME AND/OR C. SODA

- + FCL + CL - + DEFLOC. AT HT

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IDENTIFICATION CODE

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0


AGIP CODE

P.A.C.- BASE FLUIDS (DRISPAC)

ENV.

B

Mud


Density D4

Cuttings

T2

Cost

A

Temperature

A

Solids-removal Eq.

M

Re-use

B

Convertible

Logistic Difference

B

Maint. Diffrence


M

LGS Tolerance

X

Cutting Inhibition

Dispersed

Non-dispersed

Alternative Oil

LT Oil

Sea Water

Diesel

Fresh Water

X

FW/SW-PA


BASE FLUID

X

33 OF 155

M

B

B

DESCRIPTION AND APPLICATION - Encapsulating system, optimum base for inhibitive polymer systems; - High concentrations may limit cutting dispersion; - Same application as FW-PO, but has a better efficiency at high concentrations of monovalent salts.

ADVANTAGES AND LIMITATIONS - Encapsulating system which needs the addition of an inhibitive salt for inhibition; - High sensitvity to contaminations from polyvalent salts; - Low solids tolerance.

16

9.5

MAX 20

FORMULATION

Solids (% in vol.)

PRODUCT FRESH/SALT WATER BENTONITE P.A.C.(REGULAR) P.A.C.LV NaOH BARITE

MIXING TIME:

3 m /h

25 + WEIGHTING TIME

kg-l/m 3

20-40 2-5 0-5 1,0-1,5 as needed


2

20

O/W Ratio

15

MBT(kg/m3 equiv.)

5

Ca (gr/l)

10

NaCl (gr/l)

20

Mf

60

1.5

Pf

0.4

Pm

8.5

pH

6

Sand (% in vol)

8

Water (% in vol.)


10

Oil (% in vol.)

Gel 10'(gr/100cm2 )

3

API HTHP (cc/30')

Gel 10" (gr/100cm 2)

6

Plastic Visc. (cps) 10


1.05 45

Density (SG)


CHARACTERISTICS OF THE DRILLING FLUIDS

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0

MAINTENANCE - Mainly encapsulating, this system needs an adequate concentration of polymer (>3 kg/m3) to limit cutting dispersion and high increase of viscosity; - Easily convertible to a Potassium-base system, both Polymer-base and dispersed; - If a density increase above optimum range is desired, convert the system to a more solids-tolerant one.

- RHEOLOGY

- Decrease: Deflocculate using a short chain polymer (i.e.: short chain CMC LV, PHPA); Dilute; add CL and/or FCL. - FILTRATE

SHALE

+

+

+

+

-

-

-

CEMENT

=

+/-

+

+

+

+

+

CaSO4

=

+/-

+

+

+

-

=

=/+

=/+

+/-

+

+

+

-

-

-

SALT

+

+

% Sand

NaCl

Ca

MBT

Solids

Mf

Pf / Pm

pH

Filtrate

Gels

Yield

PV

CONTAMINANTS

Density

- Use PAC Regular/LV and/or CMC LV dependent on rheology desired. High salt content fluids can result economical if employed with starches.

REMEDIAL

- DILUTION - CONV. TO A MORE INHIBITIVE SYSTEM +

- PRETREAT WITH SODIUM BICARBONATE

+

- ADD. SODA ASH. - CONV IN FW/SW GY - ADD FCL +

- CONTAMINANT IS DEPENDENT ON OBM - CONV. TO FW/SW-SS

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0

AGIP CODE

DESCRIPTION OF THE SYSTEM PHPA-BASE FLUIDS

ENV.

Cuttings

Mud

B

M

B

B

O/W Ratio

D3


T2

Cost

A

Density

A

Temperature

M

Solids-removal Eq.

M

Re-use

M

Convertible

Logistic Difference

B

Maint. Difference


M

LGS Tolerance

X

Cutting Inhibition

Dispersed

Non-dispersed

Alternative Oil

LT Oil

Sea Water

Diesel

Fresh Water

X

FW/SW-PC


BASE FLUID

X

35 OF 155

DESCRIPTION AND APPLICATION - Pre-soluble polymers are required to viscosify and encapsulating cuttings; - High solids-tolerance; - Optimum base for a KCI-base fluid;

ADVANTAGES AND LIMITATIONS - Encapsulating system which needs the addition of an inhibitive salt for inhibition; - High sensitivity to contaminations from polyvalent salts; - Low solids tolerance.

FORMULATION

PRODUCT FRESH/SALT WATER BENTONITE PHPA CMC LV (CL) NaOH/KOH BARITE

MIXING TIME:

m3/h

25 + WEIGHTING TIME

MBT(kg/m3equiv.)

MAX

20

kg-l/m3

30 5 0-7 (10) 0.1-0.5 as nedeed


Ca (gr/l)

10.5

NaCl (gr/l)

2

50

Mf

20

0.4

Pf

5

8.5

Pm

15

27

pH

30

Sand (% in vol)

60

1.8

Water (% in vol.)

8

Oil (% in vol.)

15

Solids (% in vol.)

2

API HTHP (cc/30')

5


Gel 10'(gr/100cm2)

10

Plastic Visc. (cps)

1.03 45

Density (SG)

Gel 10" (gr/100cm2)




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0

MAINTENANCE

- Encapsulating system: An adequate concentration of polymer (3>kg/M3) is needed to limit cutting dispersion and high increase of viscosity; - Easily convertible to a potassium-base system; - Polymer may be added wherever but not through the hopper to avoid foam formation; - Can tolerate up to 170°C by using additives.

- RHEOLOGY

- Decrease: Deflocculate using a short chain polymer (i.e.: short chain CMC LV, PHPA); Dilute; If a more energic action is needed, them add CL and/or FCL.

FILTRATE

SHALE

+

+

+

+

+/-

-

-

+

CEMENT

=

+/-

+

+

+

+

+

CaSO4

=

+/-

+

+

+

-

=

=/+

SALT

=/+

+/-

+

+

+

-

-

-

+

% Sand

NaCl

Ca

MBT

Solids

Mf

Pf / Pm

pH

Filtrate

Gels

Yield

PV

CONTAMINANTS

Density

- Use the most adequate a filtrate reducer according to the usage: (temperature, density, salinity).

REMEDIAL

- ADD PHPA - ADD. PHPA LMW. -INCREASE INHIBITION +

- PRETREAT WITH NaHCO3

+

- ADD. Na2CO3 - CONV IN FW/SW GY - ADD FCL +

- CONTAMINANT IS DEPENDENT ON MBT - CONV. TO FW/SW-SS

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3.2

37 OF 155

0

INHIBITED WATER-BASE FLUIDS • This section contains descriptions of the various inhibited water based drilling fluids, their applications and limitations. • Fluid formation herein described, relating to drilling fluids, are the most simple and economical. Particular operating conditions may greatly modify them, so characteristics are reffered to the density indicated. • Suggestions relating to fluid maintenance only refer to the most important aspect of the system described and do not include those relating to the general maintenance which are common to all systems. • Containment effects refer to the fluid type. Other information on contamination can be found in section 4.1 ’Water Based Fluid Maintenance’.

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0

AGIP CODE


FW/SW-SS

SALT SATURATED FLUID

B

CUTTINGS

D4


T2

COSTO

A

Density

B

Temperature

A

Solid-removal eq.

A

Re-use

Logistic Difference

B

Convertible

Maint. Difference

M

LGS Tolerance

A


Cutting Inhibition

Dispersed

Non-Dispersed

Alternative Oil

X

X

M

A

MUD

ENV.

CHARACTERISTICS OF THE FLUID

LT Oil

Diesel

Sea Water

Fresh Water

BASE FLUID

X

38 OF 155

A

DESCRIPTION AND APPLICATION - Conditioned with NaCl, generally saturated; - Mainly used to drill salt formations. More rarely as an inhibitive fluid in shale formations.; - Viscosified salt solutions are employed as W.O. fluid.

ADVANTAGES AND LIMITATIONS - Lower cost and east availability of NaCl; - Na+ has an inhibition effect only in high concentrations. In low concentrations it helps shale dispersion; - Salt saturated fluid is a special discarding fluid; - High salt content will affect the product performance. Dispersants, i.e. FCL, are low-effective. Dilution is required tp maintain the system.

FORMULATION

15

2

8.5

320

1

38

9.5

320

PRODUCT

15 +WEIGHTING TIME

Kg-l/m 3 40-60 3-6 10-20 350 (3-6) as needed

10 10

Electrical stability (volt)

O/W ratio

MBT(Kg/m 3equiv.)

Ca (gr/l)

NaCl (gr/l)

Mf

Pf

Pm

5

BENTONITE PREIDRATATA SODA CAUSTICA AMIDO SALE (PAC REG, LOVIS) BARITE 3 MIXING TIME: m /h

pH

Sand (% in vol)

Water (% in vol.)

2

Oil (% in vol.)

10

Solids (% in vol.)

50

API HTHP (cc/30')

2.1 80

10

API filtrate (cc/30')

0

Gel 10'(gr/100cm 2)

Gel 10" (gr/100cm 2)

4

Plastic visc. (cps) 10

1.2

Funnel visc. (sec/qt) 38

Density (SG)

Yield point (gr/100cm 2)


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MAINTENANCE - Traditionally maintained with dilution; - In absence of Mg++ salts, keep Pf>1; - System maintenance may result more complex in drilling complex salt formations (i.e. zechstein). In this case contact expert technicians.

RHEOLOGY

- Prior to dilution, try to use small concentrations of short chain polymer (i.e. CMC LV), or FCL (prehydrated in fresh water) ; - Rheology is generally maintained by adding prehydrated protected Bentonite (with a polymer or Lignosulphate) and starch; If needed use a Bio-polymer.

FILTRATE

-

-

CEMENT

=

+/-

+/-

+/-

+

+

+

Ca++

=

+/-

+/=

+/=

+/=

-/=

Mg++

=

+

+

+

-

-

HIGH TEMPERATURES

+

+

+

-

+

REMEDIAL

- CENTRIFUGE - DILUTE

+


+

- USE PRODUCT TOLERANT TO Ca ++ - AVOID DIRECT ADDITION OF ALKALINE AGENTS - IF DUE TO COMPLEX SALTS pH 8 IS MAX WITH MgO. DO NOT ADD ALKALINE AGENTS IN CIRCULATION.

-

-

+

% Sand

=/-

Cl

Pf / Pm

+

Ca

pH

+

MBT

Gels

+

Solids

Yield

+

Mf

PV

SHALE

CONTAMINANTS

Filtrate

Density

- Up to approx. 100 °C Temperature, use starch; For hgiher temperatures, PAC and/or CMC; for temperatures more than 140 °C, estimate the use of oil-based fluid.

+

- USE PAC - SUBSTITUTE WITH OBM.

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0

AGIP CODE

DESCRIPTION OF THE SYSTEM AGIPAK (KCMC)-BASE FLUID

FW-PK

ENV.

B

MUD

D1


T1

CUTTINGS

A

COSTO

A

Density

M

Temperature

B

Solid-removal eq.

B

Re-use

Maint. Difference

B

Convertible

LGS Tolerance

M

Logistic Difference


X

Cutting Inhibition

Dispersed

Non-Dispersed


Alternative Oil

LT Oil

Diesel

Sea Water

Fresh Water

BASE FLUID

X

40 OF 155

B

B

B

DESCRIPTION AND APPLICATION - A certain inhibition grade is given to the system by replacing the sodium base with the potassium one; - Same applications as FW-PO; - May be used as a dispersed polymer and potassium-base system.

ADVANTAGES AND LIMITATIONS - Slightly encapsulating and inhibitive system; - Can only be used in fresh water, as salt water affects the potassium-base effect; - Low-solid tolerance.

FORMULATION

PRODUCT FRESH WATER BENTONITE KCMC / AGIPAC HV KCMC / AGIPAK LV KOH

3 MIXING TIME: m /h

25

Kg-l/m 3

20-60 2-6 2-10 2-4

Electrical stability. (volt)

9.5

20 _. . 60

O/W ratio

15

MBT(Kg/m3equiv.)

2

Ca (gr/l)

15

NaCl (gr/l)

3

Mf

15

Pf

15

Pm

1.15 80

pH 8.5

Sand (% in vol)

5

Water (% in vol.)

10

Oil (% in vol.)

8

Solids (% in vol.)


2

API HTHP (cc/30')

Gel 10'(gr/100cm 2)

4

Plastic visc. (cps) 5

Funnel visc. (sec/qt)

1.03 40

Density (SG)

Gel 10" (gr/100cm 2)

Yield point (gr/100cm2)


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MAINTENANCE - Low-solids tolerance; - Good operating performance of the solids-removal equipment is needed to limit dilutions; - Easily convertible to a dispersed potassium and polymer base system.

RHEOLOGY

- Decrease: dilution, KCMC-LV has a light deflocculating effect; - Increase: addition of KCMC-HV.

FILTRATE

SHALE

+

+

+

+

-

-

-

CEMENT

=

+/-

+

+

+

+

+

CaSO4

=

+/-

+

+

+

-

=

=/+

=/+

+/-

+

+

+

-

-

-

SALT

=/-

+

+

% Sand

NaCl

Ca

MBT

Solids

Mf

Pf / Pm

pH

Filtrate

Gels

Yield

PV

CONTAMINANTS

Density

- Maintain a minimum quantity of bentonite, add KCMC-LV.

REMEDIAL

- Dilute - Add K+ - Add FCL E/O CL +

-Pretreat with KHCO3

+

- Add K2CO3 - + KCMC-LV - Convert to FW-GY +

- Convert to SW-PO - Convert to FW-SS

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IDENTIFICATION CODE

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0

AGIP CODE

DESCRIPTION OF THE SYSTEM POTASSIUM CHLORIDE- BASE FLUID

FW/SW-KC

B

A

B

O/W Ratio

Mud

D3

Cost

T2

MBT(kg/m3 equiv.)

A


Density

M

Temperature

M

Re-Use

A

Solid-Removal Eq.

B/M

Convertible

Formation Inhibition M

Logistic Difference

Cutting Inhibition A

Maint. Difference

dispersed (X)

LGS Tolerance

Non-Dispersed

Alternative Oil

X

Cuttings

ENV.


LT Oil

Sea Water X

Diesel

Fresh Water

BASE FLUID

X

42 OF 155

M

DESCRIPTION AND APPLICATION - Conditioned with KCI, which is added preferably to polymer and non-dispersed; - Mainly employed in drilling shales like gumbo; - Drilling formations which, when hydrated have swelling and sloughing tendencies.

ADVANTAGES AND LIMITATIONS - KCl is an available and low-cost salt; - Inhibitive ion concentrations can be easily adapted to the formation reactivity; - K+concentration should be constantly monitored ; - High salt concentration may create disposal problems; - K+destabilises high caolinitecontent formations.

1.05 THE CHARACTERISTICS ARE THOSE TYPICAL OF THE BASE SYSTEM EMPLOYED. 1.8

FORMULATION

PRODUCT

kg-l/m 3

- The formulations are those typical of the base systems employed. - Product concentrations are traditionally higher. - A biopolymer is used as a base viscosifier to provide the system with adequate suspending characteristics.

MIXING TIME:

3 m /h

25 + WEIGHTING TIME


Calcium (gr/l)

NaCl (gr/l)

Mf

Pf

Pm

pH

Sand (% in vol.)

Water (% in vol.)

Oil (% in vol.)

Solids (% in vol.)

API HTHP (cc/30')


Gel 10' (gr/100cm2)

Gel 10" (gr/100cm2 )


Plastic Visc. (cps)

Funnel V isc. (sec/qt)

Density (SG)


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MAINTENANCE - Adequate concentration of KCI must be maintained and monitored through laboratory tests, as well as by observing the cuttings over the shale shakers; - Fluid maintenance is that of the system to which KCI is added; - System may be optimised by replacing the soda-base products with potassium-base ones; - In sea water higher concentrations of KCI are required.

RHEOLOGY AND FILTRATE

- Refer to the base-system used.

Shale

+

+

+

+

+/-

-

-

Cement

=

+/-

+

+

+

+

+

CaSO4

=

+/-

+/=

+/=

+/=

-/=

Salt

=/+

+/-

+/-

+/-

=

-

-

+

-

_

+

% Sand

Cl

Ca

MBT

Solids

Mf

Pf / Pm

pH

Filtrate

Gels

Yield

CONTAMINANTS

PV

Density

NOTE: KCl-BASE SYSTEM, ESPECIALLY IF POLYMERIC, TRADITIONALLY HAS HIGH RATES OF CORROSION.

REMEDIAL

- Add. K+ - Increase concentration (K+)

+

- Pretreat with KHCO3

+

- Use products tolerant Ca++

+

- Generally minimum contamination - Increase K+ - Convert to SS

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IDENTIFICATION CODE

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0

AGIP CODE


FW/SW-GY

GYPSUM-BASE FLUIDS

ENV.

B

MUD

D4

CUTTING

T3

COSTO

M

Lubricant properties

Density

B

Temperature

B

Solid-removal eq.

M

Re-use

Llogistic difference

A

Convertible

Maint. difference

B

LGS tolerance

A

X

Formation inhibition

Cutting inhibition

Dispersed

Non-dispersed

Alternative oil


LT oil

Sea water (X)

Diesel

Fresh water

BASE FLUID

X

44 OF 155

B

B

M

DESCRIPTION AND APPLICATION - Used for drilling reactive shales and massive formations of CaSO4: - Gypsum is used as a Ca++ source; - Dispersed, Lignosulphonate base system; - The system may be more inhibitive if used in fresh water.

ADAVANTAGES AND LIMITATIONS - High solids and good cutting inhibition; - Can be weighted up to elevated values; - Can also be used at high temperatures; - Low cost; - Effectiveness can be enhanced by using KOH or Ca(OH)2 as alkaline agent; - Gelation problems may occur to high solids content fluid at high temperatures.

1

5

8

5

9.5

2.1 60

45

8

1

15

2

35

10.5

FORMULATION

PRODUCT FRESH/SALT WATER BENTONITE ALCALINE AGENT FC-LIGNOSOLFONATE GYPSUM CMC-LV/LIGNITE BARITE

MIXING TIME

m3/h

20 + WEIGHTING TIME

15

10

0.5

0.6

30

20

kg-l/m

3

50 4 6-12 10-20 3-7 as needed


70

NaCl (gr/l)

1.2

Mf

0.2

Pf

Excess lime (kg/m3)

3

MBT(kg/m 3 equiv.)

10

Ca (gr/l)

1.1 40

Pm

pH

Sand (% in vol)

Water (% in vol.)

Oil (% in vol.)

Solids (% in vol.)

API HTHP (cc/30')


Gel 10'(gr/100cm 2)

Gel 10" (gr/100cm 2)


Plastic Visc. (cps)


Density (SG)


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0

MAINTENANCE - Maintain excess Gypsum ranging from 10 to 20 kg/m3, regulate soluble Ca++ by varying pH from 9 to 10.5. When pH is low, Ca++ is more soluble, and inhibition and maintenance difficulty become higher.

RHEOLOGY

- Use FCL as a thinning agent. If Ca++ is high, gelation problems may occur, especially with high-solids content and temperatures near the system limit (150 °C).

FILTRATE

SHALE

+

CEMENT

SALT/SALTED WATER

HIGH TEMPERATURE

+

+

+

+

=/-

-

-

=

+/-

+/-

+

+

+

-

+/-

+/-

+/-

+

-

-

=/+

+

+

+

-

-

+

% Sand

Cl

Ca

MBT

Solids

Mf

Pf / Pm

pH

Filtrate

Gels

Yield

CONTAMINANTS

PV

Density

- CMC LV is an optimum filtrate reducer. The concentration of soluble Ca++ affects the quantity of filtrate reducer needed; - For elevated temperatures use lignite to control the filtrate.

REMEDIAL

- INCREASE CaSO4 EXCESS - DECREASE MBT

- ADD. FCL - DECREASE pH WITH NaHCO3 +

- MODERATE CONTAMINATION - ADD FCL E CMC-LV - CONVERT TO FW-SS - DECREASE MBT. - DECREASE EXCESS GYPSUM - ADD LIGNIN

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IDENTIFICATION CODE

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0


AGIP CODE

LIME-BASE FLUIDS

FW/SW-LI

D4

B

B

B

Mud

T2

Cost

M


Density

M

Temperature

B

Solids-removal Eq.

M

Re-use

Logistic Difference

A

Convertible

Maint. Difference

B

LGS Tolerance

Cutting Inhibition M


Dispersed

Non-dispersed

Alternative Oil

X

Cutting

ENV.


LT Oil

Sea Water X

Diesel

Fresh Water

BASE FLUID

X

46 OF 155

M

DESCRIPTION AND APPLICATION - Used for drilling reactive shale formations, even at high temperatures; - Lime is used as the source of Ca++; - Dispersed, lignosulphonate-base system; - Two basic formulations: Low-Lime content and high-Lime content, varying from 5 to 20 kg/m3 of excess Lime respectively.

ADVANTAGES AND LIMITATIONS - High-solids tolerance and medium cutting inhibition; - Can be weighted up to high values; - Fairly good resistance to chemical contaminants; - Low cost; - Reduced calcium inhibitive effect due to the pH dispersing action; - Gelation problems may occur near temperature limit (130 °C).

65

55

10

1

15

2

40

12.5 20

FORMULATION

PRODUCT WATER BENTONITE ALCALE FC-LIGNOSOLFONATE LIME STARCH/CMC-LV BARITE

MIXING TIME: m3/h

20 + WEIGHTING TIME

0,1

70

5

5

0,4

20

23

NaCl (gr/l)

2

Mf

8

kg-l/m 3 70-120 3-8 6-12 8-30 20/7 as needed


2.15

Excess Lime (kg/m3)

12

MBT(kg/m3 equiv.)

5

Ca (gr/l)

pH

10

Pf


3

Pm

Gel 10'(gr/100cm 2)

1

Sand (% in vol)

Gel 10" (gr/100cm2)

4

Water (% in vol.)


8

Oil (% in vol.)

Plastic Visc. (cps)

38

Solids (% in vol.)


1.1

API HTHP (cc/30')

Density (SG)

CHARACTERISTICS OF THE DRILLING FLUIDS

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MAINTENANCE - Excess lime to be used depends on the formation reactivity; - The relationship betwen Pm/Pf with Pm>3Pf is vital as it provides exact indication of excess lime.

RHEOLOGY

- Increase: Prehydrated, lignosulphonate protected bentonite; - Decrease: Maintain excess lime within optimum values, add lignosulphonate, dilute.

FILTRATE

SHALE

+

CEMENT

SALT/SALT WATER

=/-

=

-

=

=

=

=

+/=

+

+/-

+/-

+/-

+

-

+

+

+

-

-

+

+

+

-

-/+

-

+

+

% Sand

Cl

Ca

MBT

Solids

Mf

Pf / Pm

pH

Filtrate

+

=

+

Gels

+

HIGH TEMPERATURE

GYPSUM

Yield

CONTAMINANTS

PV

Density

- CMC LV is an optimum filtrate reducer. The concentration of soluble Ca++ affects the quantity of filtrate reducer needed; - For elevated temperatures use lignite to control the filtrate.

REMEDIAL

- INCREASE EXCESS Ca(OH)2 - REDUCE MBT

-/=

=/+

- MODERATE CONTAM.

+

- MODERATE CONTAM. - ADD FCL AND STARCH - CONVERT TO FW-SS - REDUCE MBT. - RED. Pm AND Pf. - ADD. CMC LV AND LIGNIN

+

- :ADD. NaOH - COVERT TO FW-GY

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IDENTIFICATION CODE

PAGE



AGIP CODE

MOR-REX-BASE FLUID (KLM)

FW/SW-MR

ENV.

D4

B

Mud

T1

Cuttings

A

Cost

B


A

Density

A

Temperature

Logistic Difference

A

Solids-removal Eq.

Maint. Difference

B

Re-use

LGS Tolerance

A

Convertible


X

(X)

Cutting Inhibition

Dispersed

Non-dispersed

Alternative Oil


LT oil

Diesel

Sea Water

Fresh Water

0


BASE FLUID

X

48 OF 155

A

B

M

DESCRIPTION AND APPLICATION - Used for drilling reactive shale formations, even at high temperatures; - Calcium and Potassium are added as KOH and Ca(OH)2, while Morex as a deflocculant and calcium chelant polymer; - Optimum application is in freshwater fluids with high ROP and density, but not too high temperatures.

ADVANTAGES AND LIMITATIONS - High solids tolerance and ;ood cutting inhibition; - Can be weighted up to high values; - Complex system, expert technicians are needed for maintenance; - Several products are needed for its formulation and maintenance, this may create supply problems; - Gelation problems may occur in high solids content fluids near temperature limit (130 °C).

Ca (gr/l)

MBT(kg/m3equiv.)

Excess Lime (kg/m3) 10

2.1 55

50

8

3

15

6

35

12.5 15

2-3

2-4

0.8

MAX

15

FORMULATION

PRODUCT FRESH/SALT WATER PREHYDRATED BENTONITE (BIOPOLYMER) MOR-REX KOH LIME MOD. STARCHES/LIGNITE BARITE

MIXING TIME:

3 m /h

15 + WEIGHTING TIME

kg-l/m 3 40 (1-3) 6-12 3 12-17 10-15 as needed


Mf

60

NaCl (gr/l)

Pf

0.4

Pm

2-4

pH

2-3

Sand (% in vol)

12.5 15

Water (% in vol.)

5

Oil (% in vol.)

10

Solids (% in vol.)

2

API HTHP (cc/30')

Gel 10'(gr/100cm2)

1


Gel 10" (gr/100cm 2)

4



1.1 40

Density (SG)



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0

MAINTENANCE

- System with floculation controlled by the balance between two salts and a polymer: Highly important to maintain the balance between Pf, Pm and Morex; - Always add Lime and Morex simultaneously in a ratio of 4/2 and 3/2 dependent on the characteristics desired and temperature.

RHEOLOGY

- Flocculation control is due to the ratio Lime/Morex. Do not use dispersers; - Keep MBT below 10%; For high densities and temperatures > 135 °C, do not exceed 4-6%.

FILTRATE

SHALE

+

CEMENT

=

CaSO4

SALT

HIGH TEMPERATURE

+/-

+

% Sand

Cl

Ca

+

=/-

-

-

+

+

+

+

+

+

- ADD. LIME + MOR-REX + WATER + LIGNITE + +KOH.

+

+

+

-

-/+

+

- IF Ca++ > 1200 ppm ADD. K2CO3 - CONV. TO FW-GY

+

+

+

-

-

+

+

-

-

+

REMEDIAL

+

+

+

MBT

Solids

Mf

Pf / Pm

pH

Filtrate

Gels

Yield

CONTAMINANT

PV

Density

- Use starch as main filtrate reducer up to a temperature of 100 °C, for higher temperatures use starch and lignite in a ratio of 2/1 and 1/1; - Do not add alkaline agent to starch simultaneously as it may cause an increase of viscosity. Pre-solubilised lignite may be convienvent.

- Ca++ AND MOR-REX - DECREASE MBT

+

+

- CONV. TO FW-SS

- DECREASE MBT. - ADD. LIGNITE FOR FILTRATE.

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3.3

50 OF 155

0

OIL BASED FLUID This section contains descriptions of the oil based fluids systems, their applications and limitations.

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AGIP CODE

DIESEL INVERT EMULSION FLUID

DS-IE

ENV.

T4


Density D3

A

Mud

M

Cuttings

A

Cost

B

Temperature

A

Solids-removal Eq.

M

Re-use

A

Convertible

Logistic Difference

A

Maint. Difference

A

LGS Tolerance

X


Cutting Inhibition

X

Dispersed

Non-dispersed

Alternative Oil


LT Oil

Diesel

Sea Water

0


BASE FLUID

Fresh Water

51 OF 155

M

A

A

DESCRIPTION AND APPLICATION - Water emulsion in Oil with Oil as the filtrate; - Used for drilling shales, high temperatures, salt formations, deviated wells, water-damaging reservoir, completion fluid; - High density drilling fluids used when fluid recovery and re-use is advantageous.

ADVANTAGES AND LIMITATIONS - The emulsion has a nonionic continuous phase and does not interact with shale layers and the most common chemical contaminants; - Due to high environmental restrictions, the zero charge is needed; - Compared to other drilling fluids or zero discharge areas, it has the advantage of a low dilution ratio and the possibility to be re-used; - Lost circulation control, and Gas kick detection and maintenance may create some problems.


API HTHP (cc/30')

Solids (% in vol.)

Oil (% in vol.)

Water (% in vol.)

CaCl2 (%)

O/W Ratio

Excess Lime (kg/m3)

5

0

10

8

64

28

3

30

70/30

6

2.2

60

42

8

1.5

6

0

3

40

54

6

8

30

90/10

13

FORMULAtion

PRODUCT DIESEL EMULSIFIER/S LIME FILTRATE REDUCER (IF REQUIRED) BRINE (20-30% CaCl2) VISCOSIFIER WETTING AGENT (IF REQUIRED) BARITE

MIXING TIME:

m3/h

15 + WEIGHTING TIME

kg-l/m 3 FORMULATIONS AND QUANTITIES DEPEND ON DENSITY, OIL/WATER RATIO AND SERVICE COMPANY'S FORMULATIONS. FOLLOW THE INSTRUCTION IN THE SPECIFIC MANUAL.


Gel 10'(gr/100cm2 )

2

Mf

Gel 10" (gr/100cm2 )

5

Pf


15

Pom (cc H2SO4 N/10)

Plastic Visc. (cps)

40

pH


1.2

Sand (% in vol)

Density (SG)

CHARACTERISTICS OF THE DRILLING FLUID @ 120 °F

600 2000

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0

MAINTENANCE - An Oil-base fluid is traditionally easy to maintain. Pay attention to record dilutions and product quantities required in order to keep correct concentrations; - To avoid problems, constantly monitor any modifications of the characteristics, especially the electrical stability and HPHT filtrate. If any modifications, determine the possible causes and take prompt remedial actions.

RHEOLOGY

- Should be determined at a temperature of 120 or 150oF. Do not use marsh viscosity for maintenance; - Water is the principle viscosifier of Oil-base fluids. Its percent will vary depending on the characteristics required. Other viscosifiers enhance yield point and Gels. Viscosity is also given by solids, thus it is essential to decrease the water content in the fluid by increasing density.

FILTRATE

SOLIDS

+

+

+

++

=/-

=

WATER

-/+

+

+

+

+

-

+/-

+/-

+

CaCl2 > 35%

-

-

-

-

Cuttings

Aspect

Wetting

Water

CaCl2

EL. STAB.

0/W

POM

F. HPHT

Gels

Yield

CONTAMINANTS

PV

Density

-The main filtrate reducer is given by the quality of emulsion. Other filtrate reducers may be needed for high temperatures or for very low HPHT filtrate values.

REMEDIALS

(?)

(PLASTIC) - ADD.WETTING AGENT - DILUTE

(+)

(PLAST.)

- IF O/W OK, + EMULSION. IF O/W K.O., + OLIO X OK

(PLAST.)

- LIGHT CONTAM. - CONV. TO DS/LT-IE

=/+

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53 OF 155


0

)

AGIP CODE


DS-IE-RF

DIESEL INVERT EMULSION, FILTRATE RELAXED FLUID

ENV.

M

D3


Density

Temperature T4

A

Mud

A

Cuttings

B

Solid-removal Eq.

A

Re-use

M

Cost

A

Convertible

A

Logistic Difference

A

Maint. Difference


X

LGS Tolerance

Cutting Inhibition

X

Dispersed

Non-dispersed

Alternative Oil


LT Oil

Diesel

Sea Water

Fresh Water

BASE FLUID

M

A

A

DESCRIPTION AND APPLICATION - Water emulsion in Oil with Oil as the filtrate - Same applications as the conventional Oil-base fluid. Thanks to its characteristics of high filtrate it helps improve penetration rates in permeable formations.

ADVANTAGES AND LIMITATIONS - Same advantages as a conventional Oil-base fluid with higher penetration rates; - Due to a minor emulsion concentration, the range of temperature is limited to max 350 °F; - Same environmental restrictions as DS-IE.


API HTHP (cc/30')

Solids (% in vol.)

Oil (% in vol.)

Water (% in vol.)

CaCl2 (%)

O/W Ratio

Excess Lime (kg/m3)

5

2

15

8

64

28

3

30

80/20

6

2.2

60

42

8

1.5

6

8

20

40

54

6

8

30

90/10

13

FORMULATION

PRODUCT DIESEL EMULSIFIER/S LIME FILTRATE REDUCER (IF REQUESTED) BRINE (20-30% CaCl2) VISCOSIFIER WETTING AGENT (IF REQUIRED) BARITE

MIXING TIME:

m3/h

15 + WEIGHTING TIME

kg-l/m 3 FORMULATIONS AND QUANTITIES DEPENDS ON DENSITY, WATER/OIL RATIO AND ON THE SERVICE COMPANY'S FORMULATIONS. FOLLOW THE INSTRUCTIONS IN THE SPECIFIC MANUAL.

Electrical Stability. (volt)

Gel 10'(gr/100cm2 )

2

Mf

Gel 10" (gr/100cm2 )

5

Pf


15

Pom (cc H2SO4 N/10)

Plastic Visc. (cps)

40

pH


1.2

Sand (% in vol)

Density (SG)


600 1000

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0


AGIP CODE

100% DIESEL INVERT EMULSION FLUID

DS/LT-IE-100

ENV.

A

Mud

D5

Cuttings

T4

Cost

A


Density

A

Temperature

A

Re-use

A

Convertible

M

Solids-removal Eq.

A

Logistic Difference

A

Maint. Difference

A

LGS Tolerance


X

Cutting Inhibition

Dispersed

Non-dispersed

Alternative Oil


LT Oil

Diesel

Sea Water

Fresh Water

BASE FLUID

X

54 OF 155

A

A

A

DESCRIPTION AND APPLICATION - 100% Diesel or low toxiticity Oil, Oil-base fluid; - A small quantity of emulsifier helps tolerate up to 10% water invasion; - Non-damaging Oil-base fluid system, purposely designed for coring and drilling Oil mineralised formation.

ADVANTAGES AND LIMITATIONS - The lack of water and energic emulsifiers limits damages to the Oil-mineralised formation; - Easily convertible to a simple Oil-base fluid or to a packer-fluid; - Purposely prepared, it is not possible to recover the original oil-based fluid, because of the high concentrations of surfanctants; - If prepared with Diesel it shows the same environmental restrictions as DS-IE.

0

FORMULATION

PRODUCT

3 m /h

100/0

kg-l/m3 FORMULATIONS AND QUANTITIES DEPEND ON DENSITY, AND SERVICE COMPANY'S FORMULATIONS. FOLLOW THE INSTRUCTIONS ON THE SPECIFIC MANUAL.

20 + WEIGHTING TIME


Excess Lime (kg/m3)

O/W Ratio

CaCl2 (%)

Mf

Pf

0

DIESEL/LT OIL EMULSIFIER/S LIME FILTRATE REDUCER WETTING AGENT VISCOSIFIER BARITE / CaCO3

MIXING TIME:

Pom (cc H2SO4 N/10)

82

pH

18

Sand (% in vol)

10

Water (% in vol.)

3

Oil (% in vol.)

2 Gel 10'(gr/100cm )

2

Solids (% in vol.)

Gel 10" (gr/100cm2 )

5

API HTHP (cc/30')


12


Plastic Visc. (cps)

1.4


Density (SG)


2000+

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3.4

55 OF 155

0

INHIBITED AND/OR ENVIRONMENTAL FLUIDS This section contains descriptions of inhibited and environmentally friendly fluid systems, their applications and limitations.

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AGIP CODE

POTASSIUM CARBONATE-BASE FLUID

FW-K2

ENV.

Mud

D3

B

B

0

30

B

Cost

Cuttings


A

O/W Ratio

T2

MBT(kg/m 3equiv.)

A

Ca (gr/l)

B

Density

A

Temperature

A

Solids-removal Eq.

Convertible

B

Re-use

Logistic Difference

M

Maint. Difference

A


Cutting Inhibition

Dispersed

X

LGS Tolerance

X

Non-dispersed

LT Oil

Alternative Oil


Diesel

Sea Water

0


BASE FLUID

Fresh Water

56 OF 155

DESCRIPTION AND APPLICATION - Conditioned with non-dispersed K2CO3 which has been added to KCMC and KPAC; - Used for drilling reactive shales; - Drilling formations which, when hydrated, have sloughing and/or swelling tendencies; - Can be used as a completion fluid or as a no-solids drilling fluid up to a density of 1,58 sg.

ADVANTAGES AND LIMITATIONS - Non-corrosive; - No environmental limitations as per KCl; - At >100 °C CO2 is freed; - Can interfere with the cement plug; - If used as a W.O. fluid, then avoid using in presence of Lime waters; - K+ has a destabilising effect on caolinic formations.

12

FORMULATION

25

11.5

PRODUCT FRESH WATER BENTONITE (K)PAC (K)CMC K2CO3 BARITE (BIOPOLYMER)

MIXING TIME:

3 m /h

20 + WEIGHTING TIME

MAX kg-l/m 3 40 4-6 5-7 20-30 as needed as needed


2

NaCl (gr/l)

8

Mf

36

10.5

Pf

50

0

Pm

1.8

6

pH

4

Sand (% in vol)

1

Water (% in vol.)

Gel 10'(gr/100cm 2)

4

Oil (% in vol.)

Gel 10" (gr/100cm 2)

8

Solids (% in vol.)

Plastic Visc. (cps)

40

API HTHP (cc/30')


1.1


Density (SG)



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MAINTENANCE

- Encapsulating system: An adequate concentration of polymer (3>kg/M3) is needed to limit cutting dispersion and high increase of viscosity; - Easily convertible to a potassium-base system; - Polymer may be added wherever but not through the hopper to avoid foam formation; - Can tolerate up to 170°C by using additives.

- RHEOLOGY

- Decrease: Deflocculate using a short chain polymer (i.e.: short chain CMC LV, PHPA); Dilute; If a more energic action is needed, them add CL and/or FCL.

FILTRATE

SHALE

+

+

+

+

+/-

-

-

+

CEMENT

=

+/-

+

+

+

+

+

CaSO4

=

+/-

+

+

+

-

=

=/+

SALT

=/+

+/-

+

+

+

-

-

-

+

% Sand

NaCl

Ca

MBT

Solids

Mf

Pf / Pm

pH

Filtrate

Gels

Yield

PV

CONTAMINANTS

Density

- Use the most adequate a filtrate reducer according to the usage: (temperature, density, salinity).

REMEDIAL

- ADD PHPA - ADD. PHPA LMW. - INCREASE INHIBITION +


+

- ADD. Na2CO3 - CONV IN FW/SW GY - ADD FCL +

- CONTAMINANT IS DEPENDENT ON MBT - CONV. TO FW/SW-SS

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0


AGIP CODE FW-KA

POTASSIUM ACETATE-BASE FLUID

ENV.

B

Mud

T3

Cutings

A

A

B

M

O/W Ratio

M

Cost

M

MBT(kg/m 3equiv.)

A


Logistic Difference

M

Density

Maint. Difference

M

Temperature

LGS Tolerance

A

Solids-removal Eq.


(X)

Re-use

Cutting Inhibition

X

Convertible

Dispersed

X

Non-dispersed

Alternative Oil


LT Oil

Diesel

Sea Water

BASE FLUID

Fresh Water

58 OF 155

DESCRIPTION AND APPLICATION - Conditioned with K-Acetate, preferably to polymers and non-dispersed; - K can be also added to high density and HT systems; - Safe alternative to KCI in environmental sensitive areas; - Same applications as KCl.

ADVANTAGES AND LIMITATIONS - KAC is a high cost salt (5-6 times KCl); - Less corrosive than KCl; - Disposal difficulties due to a high COD; - Same K+ concentrations as KCI addition of +KAC (+30%) is required.

1.05

THE CHARACTERISTICS ARE TRADITIONALLY THOSE OF THE BASE SYSTEM USED.

2.0

Pf AND Pm EVALUATIONS ALTERED BY ACETATE.

FORMULATION

kg-l/m 3

PRODUCT

- FORMULATIONS ARE TRADITIONALLY THOSE OF THE BASE SYSTEMS USED; - PRODUCT CONCENTRATIONS ARE GENERALLY HIGH; - A BIOPOLYMER IS OFTEN USED AS A VISCOSIFIER TO PROVIDE THE SYSTEM WITH ADEQUATE SUSPENDING CHARACTERISTICS. MIXING TIME:

3 m /h

25 + WEIGHTING TIME


Ca (gr/l)

NaCl (gr/l)

Mf

Pf

Pm

pH

Sand (% in vol)

Water (% in vol.)

Oil (% in vol.)

Solids (% in vol.)

API HTHP (cc/30')


Gel 10'(gr/100cm2 )

Gel 10" (gr/100cm 2)


Plastic Visc. (cps)


Density (SG)

CHARACTERISTICS OF THE FLUIDS

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MAINTENANCE - More than other K+ base system, it is particulary designed for use in dispersed high density and/or high temperature fluids; - Estimate the the cuttings over shale shakers and adapt K+ concentrations.

- RHEOLOGY AND FILTRATE

-

-

CEMENT

CaSO4

NaCl/SALT WATER

HIGH TEMPERATURES

+/-

+/-

+

+

+

+

+/-

+/-

+

+

=/-

+/-

+/-

+/-

+

-

+

+

+

-

+

+

REMEDIAL ACTIONS

- Increase K+ concentration. - Deflocculate or disperse. - Dilute. +

- Pretreat with KHCO3

+

- Add K2CO3 - Use polymers resistant to CA++. +

-

% SAND

=/-

NaCl

Pf / Pm

+

Ca

pH

+

MBT

FILTRATE

+

SOLIDS

GELS

+

Mf

YIELD

SHALE

PV

CONTAMINANTS

DENSITY

- Controlled as per the base fluid system used.

- Adapt K+. - Convert to KCl. - Convert to FW/SW-SS - Reduce MBT, - Disperse with CL/FCL

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AGIP CODE

HIGH TEMPERATURE (> 200 °C) WATER-BASE FLUIDS

FW/SW-HT

ENV.

Density D3

Mud

T4

Cutting

A

Cost

A

Temperature

M

Solids-removal Eq.

M


B

Re-use

B

Convertible


B

Logistic Difference

Cutting Inhibition

X

Maint. Tolerance

Dispersed

X

LGS Tolerance

Non-Dispersed

Alternative Oil


LT Oil

Sea Water

Diesel

Fresh Water

X

0


BASE FLUID

X

60 OF 155

B

AA

B

B

DESCRIPTION AND APPLICATION - Designed for elevate temperatures and/or geothermic wells; alternative to DS-IE. - The basic formulation depends on the use of bentonite and a deflocculant polymer (SSMA) suitable for elevate temperatures; - Lower costs and difficulties to control filtrate compared to systems employing sepiolite and/or polymer as viscosifiers.

ADVANTAGES AND LIMITATIONS - Safe alternative to Oil-base fluids in environmental sensitive areas; - Lower maintenance costs compared to HT water-base formulations; - Can also be employed in salt saturated fluids, and in presence of biavelent ions.

12

2

10

30

10.5

0.7

30

FORMULATION

PRODUCT WATER BENTONITE (no peptine added) NaOH SSMA POL. LIGNITE HT POLYMER MIXTURE BARITE

MIXING TIME:

m3/h

20 + WEIGHTING TIME

kg-l/m 3 30-35 3-4 1-2 10-30 1-5 as needed


1

Excess Lime (kg/m3)

8

MBT(kg/m 3equiv.)

55

Ca (gr/l)

1.8 50

NaCl (gr/l)

30

Mf

0.3

Pf

9.5

Pm

5

pH

30

Sand (% in vol)

API HTHP (cc/30')

10

Water (% in vol.)


5

Oil (% in vol.)

Gel 10'(gr/100cm 2)

1

Solids (% in vol.)

Gel 10" (gr/100cm 2)

4



1.1 38

Density (SG)



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0

MAINTENANCE - Solids control is highly important, therefore always monitor solids percentage, reactivity, and size by means of adequate analyses; - Verify rheology at 120 °F; - Maintain the fluid chemical parameters within the values. At high temperature all reactions may result accelerated.

RHEOLOGY

- Increase: Prehydrated and SSMA protected bentonite; - Decrease: Dilution.

FILTRATE

SOLIDS

+

CEMENT

=

SALT/SALT WATER +/-

HIGH TEMPERATURE

+

+

+

=/-

=

-

=

=

+

+

+

+/-

+/-

+

+

+

+/=

-

+

+/-

REMEDIAL

- DILUTE

=/+

+

% Sand

Cl

Ca

MBT +/-

- CONTAMINATION DEP. ON POLYMERS USED - ADD. Na2CO3

+

-

-

Solids

Mf

Pf / Pm

pH

Filtrate

Gels

Yield

CONTAMINANTS

PV

Density

- Filtrate reducers must be chosen according to temperature and ionic environment, such as: Chromelignin, HT polymer mixture (i.e. Resinex), polyacrylates and polyacriyamides. In case of high concentrations of bivalent ions, use copolymers based on amps.

+

- LIGHT CONTAMINATION - CONV. TO DS/LT-IE

- REDUCE MBT - REDUCE Pf AND Mf TO VALUES EQUIVALENT TO OH- IN THE FLUID.

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0

AGIP CODE

DESCRIPTION OF THE SYSTEM CATION-BASE FLUID

FW/SW-CT ENV.

D3

Mud

T2

Cutting

A

Cost

Re-use

Convertible

Logistic Difference A


A

Density

A

Maint. Tolerance

LGS Tolerance

Formation Inhibition M

Temperature

A

Solids-removal Eq.

X

X

Cutting Inhibition

Dispersed

Non-dispersed

Alternative Oil


LT Oil

Diesel

Sea Water

Fresh Water

BASE FLUID

X

62 OF 155

B

AA

A

A

DESCRIPTION AND APPLICATION - Fluid with cationic polymers which, thanks to their positive charge, are inhibitive and flocculant; - It inhibits the reactive shales without using an inhibitive salt.

ADVANTAGES AND LIMITATIONS - Inhibition is due to the absorption of polymers on the shale surface; - Cationic polymers, though toxic, have fewer environmental restrictions than conventional water-base fluids; - Cationic polymers are not compatible with conventional anionic polymers. Therefore, maintain some anion concentrations (Cl-, from NaCl or KC) in the fluid in order to overcome incompatibility. Always verify incompatibility.

40

10

2

10

3

12

30

FORMULATION

MIXING TIME:

PRODUCT VISCOSIFIER ALKALINITY AGENT CATIONIC POLYMER FILTRATE REDUCER DEFLOCCULANT WAIGHTING INHIBITIVE SALT 3 m /h 15 + WEIGHTING TIME

MAX


60

O/W Ratio

1.8

9

MBT(kg/m3equiv.)

10

Ca (gr/l)

Solids (% in vol.)

30

NaCl (gr/l)

API HTHP (cc/30')

7

Mf


2

Pf

Gel 10'(gr/100cm 2)

1

Pm

Gel 10" (gr/100cm 2)

2

pH


10

Sand (% in vol)

Plastic Visc. (cps)

45

Water (% in vol.)


1.1

Oil (% in vol.)

Density (SG)


(50) (MIN.) ()FOR SOME FORMULATION ONLY kg-l/m3 FORMULATIONS ARE STRICTLY DEPENDENT ON THE CATIONIC POLYMERS CHOSEN. EACH COMPANY HAS A SPECIFIC FORMULATION.

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0

MAINTENANCE - Tolerance between cationic and conventional (anionic) polymers should be verified. Tolerance is traditionally possible for formulations with a certain content of chloride ion; - Never use lignosulphonates or other anionic polymers, even in presence of chlorides. Do not increase pH above 9.5 value.

RHEOLOGY

- System maintenance may be difficult due to the poor availability of compatible products with cationic polymers; - Generally a biopolymer and/or HEC is used as a viscosifier; - Solids control is highly important.

FILTRATE

SHALE

+

CEMENT

=

+

+

+

=/-

-

-

+

+

+

+

+

+

CaSO4

SALT/SALT WATER +/-

HIGH TEMPERATURE

+

+

+

-

-

+

REMEDIAL

- ADD.CATIONIC POLYMER - DILUTE +

- ADD. CH3COOH - ADD. NaHCO3

+

- NO CONTAMINATION

+

+

%Sand

Cl

Ca

MBT

Solids

Mf

Pf / Pm

pH

Filtrate

Gels

Yield

CONTAMINANTS

PV

Density

- The most used filtrate reducers are: Modificated starches, kaolinte, prehydrated and PVA (Polyvinil alcohol) protected bentonite; - PAC can be employed in presence of electrolytes.

- NO CONTAMINATION

- REDUCE MBT. - DEFLOCCULATE

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0


CODICE AGIP

GLYCOL-BASE FLUID

FW/SW-GL

ENV.

Cutting

Mud

T2

Cost

A


M

Density

Logistic Difference A

Temperature

Maint. Tolerance A

Solids-removal Eq.

LGS Tolerance B

Re-use

Formation Inhibition B

Convertible

Cutting Inhibition

X

X

M

Dispersed

Non-dispersed

Alternative Oil


LT Oil

Diesel

Sea Water

Fresh Water

BASE FLUID

X

64 OF 155

D2

M

A

B

B

DESCRIPTION AND APPLICATION - Polymer-base fluid conditioned with glycol which may contain inhibitive ions; - Designed as an environmentally safe alternative to conventional oil-base fluid and as a shale formation inhibitor; - May help with problems relating to the formation of 'Hydrated gases'. N.B. This system is being developed.

ADVANTAGES AND LIMITATIONS - In product usage percentages of 3-5%. It behaves as a lubricant, in percentages varying from 10 to 40%. It is comparable to FW-KC for its inhibition characteristics; - Very high costs, considering low solids tolerance; - Not a competitive alternative to oil-base fluid, and even when OBM cannot be employed, preferably estimate to use other systems before choosing the glycol-base fluid.

1.1

CHARACTERISTICS, ESPECIALLY THE PV, ARE DEPENDENT ON THE % OF GLYCOL AND BASE SYSTEM USED (TRADITIONALLY PHPA).

1.8 FORMULATION

PRODUCT BENTONITE CAUSTIC SODA PHPA and/or PAC GLYCOL MODIFIED STARCH and/or Na POLYACRYLATES BIOPOLYMER BARITE

MIXING TIME: m3/h

20 + WEIGHTING TIME

kg-l/m 3 10-30 3 8/3 10-400 6/2 2 as needed


O/W Ratio

MBT(g/m3 equiv.)

Ca (gr/l)

NaCl (gr/l)

Mf

Pf

Pm

pH

Sand (% in vol)

Water (% in vol.)

Oil (% in vol.)

Solids (% in vol.)

API HTHP (cc/30')


Gel 10'(gr/100cm2 )

Gel 10" (gr/100cm2 )


Plastic Visc. (cps)


Density (SG)

CHARACTERISTICS OF THE FLUID

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MAINTENANCE - Fluid maintenance is that of the base system used; - Determination of glycol content may result difficult; - If glycol percentage increases, Then PV increases dramatically, thus limiting the solids content allowed in the system (density and LGS limits).

RHEOLOGY

- Prior to dilution, try to use small concentrations of short-chain polymer (i.e. CMC LV), or chrome-free lignosulphonate.

FILTRAT

- Use starch up to approx. 100 oC, for higher temperatures PAC and/or CMC for temperatures more than 140-150 oC, Napolyacrylate is recommended.

SHALE

+

CEMENT

+

=/-

-

-

=

+

+

+

+

+

CaSO4

=

+

+

+

SALT/SALT. WATER

+/-

+/-

+/-

+

-

-

+

+

+

-

-

+

+

REMEDIAL

- DEFLOCCULATE - DILUTE

+


+

- USE PRODUCT TOLERANT Ca++ - ADD. Na2CO3 +

+

%Sand

Cl

Ca

MBT

Solids

Mf

Pf / Pm

pH

Filtrate

+

HIGH TEMPERATURE

+

Gels

Yield

CONTAMINANTS

PV

Density

N.B.This system is being developed. The information given is general and subject to modification.

- CONTAMINATION DEPEND ON BMT, AND POLYMER TYPE.

- USE HT BASE SYSTEM - REDUCE MBT.

ARPO

IDENTIFICATION CODE

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0


AGIP CODE

LOW TOXICITY OIL, INVERT EMULSION DRILLING FLUID

LT-IE

A

A

M

A

B

A

M

T4

D3

A

M

M

Mud

Cost


Density

Temperature

Solids-removal Eq.

Re-use

Convertible

Logistic Difference

Maint. Tolerance

LGS Tolerance


Cutting Inhibition

Dispersed

Non-dispersed

LT Oil

Alternative Oil

A

X

Cuttings

ENV.


Diesel

Sea Water

BASE FLUID

Fresh Water

66 OF 155

A

DESCRIPTION AND APPLICATION - Exactly the same as DS-IE, except for the mineral oil base fluid which is low-aromatic, hydrocarbon content, and low toxiticity.

ADVANTAGES AND LIMITATIONS - May be more advantageous than DS-IE if used in some areas where off-shore discharge is allowed for the max percentage of cuttings from traditional oil-base fluids; - In areas where disposal percentage is near zero or 'zero', LT oil-base fluid is not convenient; - Higher product concentrations compared to DS-IE.

1.5

6

0

3

40

54

6

FORMULATION

Oil (% in vol.)

PRODUCT LOW-AROMATIC CONTENT MINERAL OIL EMULSIFIER/S LIME FILTRATE REDUCER (if required) BRINE (20-30% CaCl2) VISCOSIFIER WETTING AGENT (if required) BARITE

MIXING TIME:

3 m /h

15 + WEIGHTING TIME

10

30

70/30

6

90/10

kg-l/m 3 FORMULATION AND QUANTITIES DEPEND ON DENSITY, WATER/OIL RATIO, AND SERVICE COMPANY'S FORMULATIONS IN THE SPECIFIC MANUAL.

13


8

Excess Lime (kg/m3)

42

30

O/W Ratio

60

CaCl2 (%)

2.2

3

Mf

28

Pf

64

Pom (cc H2SO4 N/10)

8

pH

10

Sand (% in vol)

0

Water (% in vol.)

5

Solids (% in vol.)

4

API HTHP (cc/30')

2 Gel 10'(gr/100cm )

5


Gel 10" (gr/100cm 2)

15

Plastic Visc. (cps)

40


1.2

Density (SG)



600 1500

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67 OF 155


0

MAINTENANCE

SOLIDS

+

+

+

++

=/-

(?)

=

(PLAST.)

Aspect

Cuttings

Wetting

Water

CaCl2

El. Stab.

0/W

POM

HPHT F.

Gels

Yield

CONTAMINANTS

PV

Density

- Refer to DS-IE for maintenance procedures; - Control if oil percentage of cuttings from oil-base fluid is within the values to allow the discharge. Take all actions to maintain this percentage low; - Optimise solids-removal equipment; - Maintain the lowest oil/water ratio, compatible to the characteristics required.

REMEDIAL

- ADD. WETTING AGENT - DILUTE

WATER

-/+

+

+

+

+

-

-

-

-

(+)

(PLAST.) -IF O/W IS OK, THAN RESTORE ADDITIVE PERCENTAGE -IF O/W IS NOT OK THAN ADD LT OIL+ ADDIT. %

OIL

-

-

-

-

-

=

+

-

-IF O/W IS OK, THEN RESTORE ADDITIVE PERCENTAGE

-

- IF O/W IS NOT OK THEN ADD WATER + ADDIT.%

CaCl2 > 35%

+/-

+/-

+

-

+

-

-

(+)

(PLAST.) - ADD. FRESH WATER - ADD. WETTING AGENT

HIGH TEMPERATURE

-

-

=

-

- ADDEMULSIFIERS - ADD FILTRATE REDUCERS

ARPO

IDENTIFICATION CODE

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0


AGIP CODE

50/50 O/W INVERT EMULSION DRILLING FLUID

LT-IE-50

ENV.

A

X

A

A

M

M

M

A

A

T2

D2

A

M

M

Mud

Cuttings

Cost


Density

Temperature

Solids-removal Eq.

Re-use

Convertible

Logistic Difference

Maint. Tolerance

LGS Tolerance


Cutting Inhibition

Dispersed

Non-dispersed

Alternative Oil


LT Oil

Diesel

Sea Water

BASE FLUID

Fresh Water

68 OF 155

A

DESCRIPTION AND APPLICATION - LT-IE fluid, purposely designed with a high water content to reduce cuttings from oil-base fluids and discharge them offshore within the limits allowed; - Used in off-shore areas where discharge of fluid is allowed with +/- 10% residual oil.

ADVANTAGES AND LIMITATIONS - Easier control of low-residual oil from cuttings compared to conventional LT-IE ; - Highest inhibition grade of any water-base fluid ; - Difficult maintenance as it is not possible to decrease density above 1.4 - 1.5 values when solids tolerance is low; - Unstable to high temperatures.

FORMULATION

PRODUCT LOW AROMATIC CONTENT, MINERAL OIL EMULSIFIER/S LIME BRINE (20-25% CaCl2) VISCOSIFIER BARITE

MIXING TIME:

3 m /h

15 + WEIGHTING TIME

20

2.5

25

50/50


25

1

Excess Lime (kg/m3)

10

O/W Ratio

0

CaCl2 (%)

40

Mf

40

Pf

20

Pom (cc H2SO4 N/10)

8

pH

8

0

Sand (% in vol)

15

Water (% in vol.)

50

Oil (% in vol.)

80

Solids (% in vol.)

10

API HTHP (cc/30')

Gel 10'(gr/100cm2 )

4


Gel 10" (gr/100cm2 )

10



1.45 +/-

Density (SG)


CHARACTERISTICS OF THE DRILLING FLUID @ 120°F

4 10

kg-l/m3 FORMULATIONS AND QUANTITIES DEPEND ON DENSITY, WATER/OIL RATIO, AND SERVICE COMPANY'S FORMULATIONS. REFER TO INSTRUCTION IN THE SPECIFIC MANUAL.

+/500

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69 OF 155


0

MAINTENANCE - Generally maintained as an oil-base fluid; - Unstable due to the high water percentage and more difficult to maintain than a conventional oil-base fluid; - Low electrical stability. Emulsion quality is evaluated from HPHT filtrate by verifying the absence of water.

RHEOLOGY

- Very high rheology; - High viscosity may allow a high percentage of residual fluid, and oil from cuttings. To reduce viscosity, increase the O/W ratio. However, this may also increase oil from cuttings, find a right balance between the two factors.

FILTRATE

SOLIDS

+

+

+

++

=/-

-/+

+

+

+

+

-

Aspect

Cuttings

REMEDIAL

(PLAST.) - ADD. WETTING AGENT

= (?)

WATER

Wetting

Water

CaCl2

EL. Stab.

0/W

POM

F. HPHT

Gels

Yield

CONTAMINANTS

PV

Density

- HPHT filtrate provides stability to the system. Its maintenance is highly important. Avoid overtreatment with emulsifiers or filtrate reducers for excessive viscosity.

-

-

-

(+)

- DILUTE

(PLAST.) -IF O/W RATIO IS OK, THEN RESTORE ADDITIVE%.

-IF THE O/W IS NOT OK, THEN ADD LT OIL + ADDITIVE%.

OIL

-

-

-

-

-

=

+

-

-

- IF O/W IS OK, THEN RESTORE ADDITIVE %.

-IF THE O/W IS NOT OK, THEN ADD WATER + ADDITIVE %.

ARPO

IDENTIFICATION CODE

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0


AGIP CODE

INVERT EMULSION, ESTER-BASE FLUID

EB-IE ENV.

Mud

D3

Cuttings

T2

Cost

M


A

Density

B

Temperature

A

Solid-removal Eq.

M

Re-use

Logistic Difference

A

Convertible

Maint Diffrence

A

LGS Tolerance

A

X


Cutting Inhibition

Dispersed

Non-dispersed

Alternative Oil


LT Oil

Diesel

Sea Water

BASE FLUID

Fresh Water

70 OF 155

A

AA

B

A

DESCRIPTION AND APPLICATION - Ester-base emulsion; - Thanks to no-aromatic content and biodegradability, cuttings can be discharged as per water-base fluids; - In off-shore areas where discharge of cuttings from oil-base fluids is restricted as well as for the high costs on-shore transportations, it is a valid alternative to water-base fluids.

ADVANTAGES AND LIMITATIONS - All advantages of an oil-base fluid but lower environmental restrictions; - Can be used up to 150 °C and a max density of 1,8 kg/l; - High cost.

FORMULATION

MIXING TIME:

15

0


Excess Lime (kg/m3)

O/W Ratio

CaCl2 (%)

Mf

Pf

Pom (cc H2SO4 N/10) 1

2

80

pH

Sand (% in vol)

Water (% in vol.)

10

Oil (% in vol.)

2 Gel 10'(gr/100cm )

2

Solids (% in vol.)

2 Gel 10" (gr/100cm )

13

+/1.5

API HTHP (cc/30')


35


Plastic Visc. (cps)


Density (SG)


4

600

8

1000

80/20 5

2 PRODUCT

ESTER WATER EMULSIFIER FILTRATE REDUCER (if required) LIME VISCOSIFIER THINNER/S CaCl2 BARITE 3 m /h 15 + WEIGHTING TIME

25 kg-l/m 3 613 148 25 25 6 6 6 65 c.n.

ARPO

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0

AGIP CODE


PO-IE

INVERT EMULSION, POLIOLEFINE-BASE FLUID

ENV.

M

A

B

A

A

T3

D4

A

Cost


Density

Temperature

Solids-removal Eq.

Re-use

Convertible

Logistic Difference

Maint. Tolerance

LGS Tolerance A

AA

Mud

A

Cuttings

A

X


Cutting Inhibition

Dispersed

LT Oil

Alternative Oil

Non-dispersed


Diesel

Sea Water

BASE FLUID

Fresh Water

71 OF 155

B

A

DESCRIPTION AND APPLICATION - Polyolefine-base emulsion; - Thanks to no-aromatic-content and biodegradability, cuttings can be disposed of 'zero' discharge; - In off-shore areas where discharge of cuttings from oil-base fluids is restricted as well as for the high costs on-shore transportations, it is a valid alternative to water-base fluids.

ADVANTAGES AND LIMITATIONS - All advantages of an oil-base fluid but lower environmental restrictions; - Better compatility to rubber parts compared to DS/LT-IE; - Can be used up to 180 °C an max density of approx. 2.2 kg/l; - High cost; - H igher viscosity than a conventional DS/LT-IE.

70/30

70

+/600

FORMULATION

PRODUCT POLIOLEFINE BRINE (CaCl2)) EMULSIFIER WETTING AGENT LIME VISCOSIFIER FILTRATE REDUCER BARITE

MIXING TIME:


25

Excess Lime (kg/m3)

O/W Ratio

Mf

Pf

Pom (cc H2SO4 N/10)

pH

Sand (% in vol)

Water (% in vol.)

1

5

CaCl2 (%)

0

Oil (% in vol.)

5

Solids (% in vol.)

2

API HTHP (cc/30')

Gel 10'(gr/100cm2 )

5


Gel 10" (gr/100cm2)

30


1.32 +/-

Plastic Visc. (cps)


Density(SG)


m3/h

Kg-l/m3 580 275 15 6 17 6 AS NEEDED AS NEEDED

15 + WEIGHTING TIME

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4.

72 OF 155

0

FLUID MAINTENANCE In this section are flow charts related to the reading of water based fluid daily drilling reports. These charts are should be read according to the general decision process as follows:

IS THERE A PROBLEM ?

YES/NO

IF YES, WHAT IS THE PROBLEM ?

ANSWER

WHAT HAS BEEN DONE TO SOLVE IT ?

EVALUATE

WHAT ELSE CAN BE MADE TO SOLVE IT WHICH HAS NOT BEEN MADE YET ?

TAKE ACTION

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4.1

WATER BASED FLUIDS MAINTENANCE

4.1.1

Analysing Flow Chart For Water Based Fluid Reports

0

GELS

PROGRESSIVE (es.: 1/15)

FLAT (es.: 2/4) and/or as per Programme

FLASH ( es.: 6/12)

ESTIMATE: YIELD POINT + PV DENSITY % SOLIDS LGS/HGS MBT

FILTRATE =/-

FILTRATE +

CAKE =/-

CAKE +

SOLIDS CONTAMINATION EXCESS VISCOSIFIER

CHEMICAL CONTAMINATION

ESTIMATE: ESTIMATE:

Solids Removal Equipment and notes on Dilution

pH PM,PF,MF ClCa++ Mg++ etc.... - READ COMMENTS - ANALIZE WELL PROBLEMS - MATERIALS USED - ANALIZE ANY VARATIONS OF CHARACTERISTICS WITHIN 24 HOURS.

Note:

Inadequate characteristics may cause well problems. It is important to understand what and how many variations are needed to solve any problems occur . LEGEND: ( + increase; - decrease; = unchanged.)

YIELD

+

+

+

GELS +

+

+

FILTRATE +

+

+

pH/Pf +

SOLIDS (+)

IONS Cl

Ca SO4

OH

Ca

REMEDIAL ACTIONS

NaCl, FORMATION: SALT DOME, SALT LEVELS, FORMATION OR MAKE-UP WATER.

GYPSUM/ANHYDRIDE

DILUTE WITH FRESH WATER. USE THINNERS AND FILTRATE REDUCER FOR SALINE ENVIRONMENT. CONVERT TO SALT FLUID OR SALT SATURATED FLUID. ESTIMATE TO DUMP IF CONTAMINATION IS LIMITED TO A PILL.

PRETREAT/TREAT WITH SODIUM CARBONATE IF REDUCED QUANTITIES; CONVERT TO A FLUID TOLERANT OF GYPSUM: FW-GY, FW-SS, DS-IE.

USE DESANDERS OR CENTRIFUGE TO REMOVE CONTAMINANT PARTICLES; ADD DEFLOCCULANTS AND FILTRATE REDUCERS. DILUTE; DUMP THE CONTAMINATED PILL, IF FLOCCULATION CANNOT BE CONTROLLED. CONVERT TO LIME FLUID. IN SOME CASES (i.e. CaCl2 SOLUTIONS AND POLYMERS) USES ACIDS SUCH AS HCl. SODIUM CARBONATE CAN ALSO BE USED, BUT REMOVES CALCIUM AND NOT OH-.

CEMENT AND/OR LIME PRETREAT OR TREAT WITH BICARBONATE; CONTAMINATED BARITE POLYMER-BASE FLUIDS NEED PRETREATMENT. MONITOR EXCESS LIME TO CONTROL CONTAMINATION REMOVAL, DO NOT RELY ONLY ON Ca++.

CAUSE

STAP -P-1-M-6160

HIGH VISCOSITY WITH OR WITHOUT PIT VOLUME INCREASE.

HIGH VISCOSITY WITH PROGRESSIVE INCREASE.

HIGH VISCOSITY WITH FLOCCULATED FLUID. POLYMER-BASE FLUIDS MAY HAVE A STRONG VISCOSITY.

EFFECT ON FLUID

OTHER

PV

DENSITY

4.1.2

MAINTENANCE PROBLEMS OF WATER-BASE FLUIDS

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IDENTIFICATION CODE PAGE

74 OF 155

REVISION

0

Maintenance Problems

HIGH VISCOSITY, PARTICULARLY YIELD AND GELS AT 10". UNEFCETVE TREATMENTS.

VISCOSITY INCREASE WITH/WITHOUT VOLUME INCREASE. DIFFICULTY TO MAINTAIN pH.

EFFECT ON FLUID

YIELD

+

+

GELS +

+

FILTRATE +

pH/Pf =/+

-/-

IONS Cl

Mg MgCl2, FROM FORMATION: WATER WITH MgCl2 COMPLEX SALTS, SEA WATER.

CAUSE

Mf+ FORMATION CO2: THERMAL DEGRADATION OF POLYMERS: CONTAMINATED BARITE, OVERTRATMENT WITH BICARBONATE OR CARBONATE, NaCO3 ADDED BENTONITE.

OTHER

SOLIDS

PV

DENSITY

REMEDIAL

STAP -P-1-M-6160

ATTENTION: DUMP ALL CONTAMINANTS THOROUGHLY, AS SMALL CONCENTRATION MAY CREATE PROBLEM TO FLUID MAINTENANCE, AVOID OVERTREATING WITH SEQUESTRING ION (Ca++). PAY ATTENTION TO HIGH TEMPERATURE, HIGH DENSITY AND/OR POLYMER-BASE FLUID.

CONTAMINATION DIFFICULT TO RECOGNIZE, ESPECIALLY IN COLORED FILTRATES. INCREASE pH WITH NaOH, IF CONTAMINATION IS DUE TO HCO3 AND Ca++ IS PRESENT THE FLUID; USE Ca(OH)2, IF Ca++ IS NOT PRESENT OR USE CaSO4 IF pH INCREASE IS NOT DESIRED; USE cACl2 FOR BRINE OR CHLORIDE CONTENT FLUIDS.

TREAT WITH CAUSTIC SODA FOR LIGHT CONTAMINATION AND MAINTAIN pH >/= 10. CONVERT TO A FLUID TOLERANT OF MAGNESIUM (SALT SATURATED, LOW pH, MIXED SALT SATURATED OR OIL-BASE FLUID) IF CONTAMINATION IS SEVERE. ATTENTION: CONTINUED ADDITIONS OF Mg(OH)2 TO THE SYSTEM WILL RESULT IN A GREAT VISCOSITY INCREASE.


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IDENTIFICATION CODE PAGE

0 75 OF 155

REVISION

=/ +

=/ +

VISCOSITY INCREASE (DESITY INCREASE FOR UNWEIGHTED FLUIDS)

DENSITY

VISCOSITY INCREASE (DESITY INCREASE FOR UNWEIGHTED FLUIDS)

DIFFICULTY TO CONTINUE DRILLING AFTER TRIPPING, DIFFICULTY TO RUN TOOLS IN HOLE, HIGHLY GELATINIZED BOTTOM PILL.

STINKING WELL VISCOSITY INCREASE.

EFFECT ON FLUID

PV

+

+

FILTRATE -

+

+

pH/Pf -/-

-

SOLIDS

MBT CLAY GROUNDS

INERT SOLIDS

HIGH TEMPERATURE

SOLIDS-REMOVAL EQUIPMENT, DILUTION AND/OR INHIBITION NOT ADEQUATE TO FROMATION OR PENETRATION RATES. REMEDIAL ACTION: AS PER SOLIDS-CONTROL, MOREOVE IT IS IMPORTANT TO PROVIDE OR ADEQUATE FLUID INHIBITION.

SOLIDS-REMOVAL EQUIPMENT, DILUTION ANS/OR INHIBTION NOT ADEQUATE TO PENTRATION RATES, REMEDIAL ACTIONS a) ADEQUATE ABOVE PARAMETERS; b) USE A SOLIDS-TOLERANT FLUID; c) REDUCE PENETRATION RATES.

REDUCE DILL SOLIDS CONCENTRATION; INCREASE DISPERSER CONCENTRATION; USE FILTRATE REDUCERS ADEQUATE TO TEMPERATURE, BY KEEPING HPHT FILTRATE AT VALUES SUFFICIENT TO PREVENT FLUID DEHYDRATION WHILE TRIPPING. DISPLACING A PRETREATED FLUID PILL IN THE OPEN HOLE MAY RESULT CONVENIENT.

H2S FROM FROMATION IF FROM FROMATION,TREAT WITH SCAVENGERS;IN RISKY THERMAL OR BACTERIAL AREAS PRETREAT AND/OR MAINTAIN ALKALINITY. IF FROM THE THERMAL DEGRADATION, REPLACE PRODUCTS. DEGRADATION IF FROM BACTERIAL DEGRADATION, PRETREAT WITH BACTERICIDE.

STAP -P-1-M-6160

+

+

IONS s--

REMEDIAL

IDENTIFICATION CODE

+

=

+

GELS +

CAUSE


+

+

+

YIELD

+

OTHER


ARPO PAGE

76 OF 155

REVISION

0

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IDENTIFICATION CODE

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4.1.3

77 OF 155

0

Chemical Treatment of Contaminents

Contaminants

Gypsum Or Anhydrite

Cement/Lime Hard Water

H2S

Contaminant Ion

Corrective Scavengers

3

Quantitative (kg/M ) To Remove 1gr/L Of Contaminant Ion

• Soda Ash (Na2CO3)

2.64

• SAPP (Na2H2P207)

2.77

• Sodium Bicarbonate (Na2CO3)

2.09

Calcium (Ca++) + Hydroxil (OH-)

• SAPP

2.77

• Sodium Bicarbonate

2.09

Magnesium (Mg++)

• A) NaOH and increase Ph To 10.5

3.3

Calcium (Ca++)

• B) Soda Ash

2.65

S--

Maintain Ph Above 10.5

Calcium (Ca++)

• Zinc Oxide (Zn0) • Zinc Carbonate (ZnCO3)

Refer to indication given for each product.

• Chelate Zinc • Ironite Sponge (Fe304) Carbon Dioxide (CO2)

Carbonates (CO3--)

• Gypsum (CaSO4)

Bicarbonates (HCO3-) • Lime (CaOH2) • Lime

2.85 1.23 1.21

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IDENTIFICATION CODE

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4.1.4

78 OF 155

0

H2S Scavengers

Product Description Fe based H2S Scavenger

Zinc Carbonate

*Zinc Chelate (liquid)

AVA

Bariod

Dowell

MI

BH Inteq

Ironite Sponge

Ironite Sponge

Ironite Sponge

Ironite Sponge

Ironite Sponge

1.35gr/1grH2S

1.35gr/1grH2S

1.35gr/1grH2S

1.35gr/1grH2S

1.35gr/1grH2S

Pre-treatment 3 30kg/m





Zinc Carbonate

Zinc Carbonate

Zinc Carbonate

Zinc Carbonate

Mil-Gard

5gr/1grH2S

5gr/1grH2S

4gr/1grH2S

5gr/1grH2S

6gr/1grH2S

Pre-treatment 3 5-8kg/m





Coat-RD

IDZAC L

SV-120

20gr/1grH2S

13gr/1grH2S

13gr/1grH2S




IDZAC L

Fer-Ox

*Zinc Chelate (powder)

Zinc Oxide (Polvere)

Zinc Mixture

Milgard R

8gr/1grH2S

19gr/1grH2S



Oxide Zinc

Sulf-X

2.3gr/1grH2S

2.3gr/1grH2S



No-Sulf Pre-treatment 3 5-15kg/m

Oil Dispersant Scavenger

SOS 200 14gr/1grH2S Pre-treatment 3 6-12kg/m

Note:

1ppm = 1mgr/1,000gr: 1gr/1,000kg. etc. Treatment is referred to H2S determined in drilling fluid (not to ppm but to detector). * for non-viscofied fluids.

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4.1.5

79 OF 155

0

Poylmer Structures/Relationship

POLYMERS: STRUCTURE/FUNCTION RELATIONSHIP FUNCTION

MAIN CHARACTERISTICS

VISCOSITY

HIGH MOLECULAR WEIGHT

VISCOSITY AND THIXOTROPY

HIGH MOLECULAR WEIGHT AND MIXED STRUCTURE OR CROSS-LINKING

VISCOSITY IN BRINE SOLUTIONS

HIGH MOLECULAR WEIGHT, NON IONIC OR ANIONIC, CAN BE EASILY REPLACED

DEFLOCCULANT, DISPERSER,

LOW MOLECULAR WEIGHT WITH ALCALINEpH, NEGATIVE CHARGE

FLOCCULANT

HIGH MOLECULAR WEIGHT WITH IONIC CHARGES ABSORBABLE FROM SHALES

SURFANCTANT

LYOPHIL OR HYDROPHIL GROUP IN THE SAME MOLECULE

FILTRATE REDUCER

COLLOIDAL PARTICLE FORMATION AND/OR SOLIDS BRIDGING ACTION

P

GUAR GUM

DEFLOCCULAN.

RID. FILTRATO

S

FLOCCULANTI

STARCH

TYPE OF POLYMER

EXTENDER

VISCOSIZZANTI

FUNZIONI RACCOMENDED TREATMENT 3 Kg/m

LIMITATIONS NOTES

10-20

TEMP. MAX 12O °C ,+ BATTERICIDA

P

10

TEMP MAX 100 °C + BATTERICIDA

BIOPOLYMERS

P

1.5-6

pH< 10.5

CMC HV

P

S

1.5-6

Ca++ < 1200 ppm

P

1.5-6

Ca++ < 1200 ppm

3-4

TEMP.. MAX 95 °C

S

1.5-6

Ca++ < 2000 ppm

P

1.0-6

Ca++ < 2000 ppm

0.7-4.5

Ca++< 400 ppm

P

0.6-4.5

Ca++ < 400 ppm

P

0.7-6

Ca++ < 400 ppm

0.14-0.9

Ca++ < 400 ppm

3-9

DEFLOCCULANT FOR T. UP 260 °C

CMC LV HEC

P

PAC REGULAR

S

PAC LOVIS

S

PHPA

P

P

P

P

PHPA LMW POLYACRYLATES VAMA SSMA

P P

S S

P

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4.2

OIL BASED FLUIDS MAINTENANCE

4.2.1

Analysing Flow Chart For Oil Based Fluid Reports

0

WELL PROBLEMS

MAINTENANCE PROBLEMS

VARIATION OF CHARACTERISTICS

NOTES ON SOLIDS TREATMENTS

ADDITIVES USED TO MAINTAIN CHARACTERISTICS

The stability of oil based fluid characteristics does not allow the same evaluation of contaminants carried out on water based fluids. Problems are dealt with through a comparison of the characteristics by recording changes on a consumption basis, as for example: dry and fragile cuttings, salinity fall and/or excessive additions of CaCl2 to maintain salinity, water content increase and/or additions of oils and emulsifiers to maintain W/O ratio at correct levels which may indicate an excessive salinity. However, evaluation is simplified by the limited amount of problems encountered.

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4.2.2

81 OF 155

0

Maintenance Problems

Effect On Fluid • Dull, grainy appearance of fluid.

Problems Low emulsion stability

• High HP/HT filtrate fluid with water.

1) Low emulsifier content. 2) Super-saturated with CaCl2.

• Barite settling • Blinding of shaker screens. • Extreme cases can cause water wetting of solids.

• Flocculation of barite on sand-content test.

Cause

Water wetting of solids.

Remedial Actions 1) Add emulsifier with lime. 2) Dilute with fresh water if needed. Add secondary emulsifier.

3) Water flows.

3) Add emulsifiers and lime if needed recover o/w ratio.

4) Fluid from mud plant or wrong make up.

4) Maximise agitation. Check electrolytes content, the higher the contents, the harder the emulsifier is to form

1) Inadequate emulsifiers.

1) Add secondary emulsifier for water wetting of solids or wetting agents.

2) Water-base fluid contamination.

2) As indicated in point 1.

3) Super-saturated with CaCl2.

3) Dilute with fresh water and add secondary emulsifier.

1) Low emulsifier content.

1) Add emulsifier and lime.

• Low ES. Fill on bottomhole.

2) Low concentration of filtrate reducer.

• Sloughing shale.

3) High bottom hole temperature

2) Add adequate filtrate reducer. 3) Increase concentration of emulsifier if a relaxed filtrate system, convert to a conventional system.

• Sticky cuttings on the shaker screens. • Blinding of the shaker screens. • Barite settling. • Dull, grainy appearance of fluid. • Low electrical stability. • Free water in HP/HT filtrate. • High HP/HT filtrate with water.

High filtrate

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IDENTIFICATION CODE

PAGE



Effect On Fluid • High PV, high yp, increase of solids and/or water.

Problems High viscosity

Cause 1) High solid percentage

2) Water contamination 3) Overtreatment with emulsifiers, especially primary emulsifier. • Fill at drill pipe change and after tripping; torque and drag

Sloughing Shales

• Increase of cuttings over shakers

1) Drilling underbalance. 2) Excessive filtrate.

3) Activity too low.

4) Inadequate hole cleaning. • Low YP and gels, barite settling in the viscometer cup.

82 OF 155

Barite settling

1) Poor oil wetting of barite. 2) Too low gels.

0

Remedial Actions 1) Dilute with oil; optimise solids-removal equipment; add emulsifiers. 2) Add emulsifiers. 3) Dilute with oil.

1) Increase fluid weight. 2) Increase emulsifier content, add filtrate reducers. 3) Increase CaCl2 contents to match formation activity. 4) Add viscosifiers.

1) Add secondary emulsifier and/or wetting agent; slow addition of barite. 2) Add most adequate viscosifier.

• Pit volume decrease. • Return losses.

Lost Circulation

1) Hydrostatic pressure is more than formation pressure.

1) Add mica or granulars. Never add fibrous or synthetic materials (i.e. Nylon).

• Problem of mixing fluid.

Low settling of barite. Very thin fluid with no yield or gels. Dull, grainy fluid.

1) Inadequate shear. 2) Very cold. 3) Poor wetting of barite.

1) Maximise shear. 2) Lengthen mixing time. 3) Slow addition of barite. If not sufficient increase percentage of secondary emulsifier. 1. Dilute with fresh water. Once emulsion is formed, adjust CaCl2 if needed.

4) CaCI2 >350,000 ppm.

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Effect On Fluid

83 OF 155

0

Problems

Cause

Remedial Actions

• Soft cuttings, blinding tendencies of shaker screens. Decrease of water content.

Too low activity can result in hole instability.

1) Too low concentration of CaCl2.

1) Allow concentration to balance by itself if not severe, report CaCl2 in percentage. Report where water migration stops as the balance point. Recover the correct o/w ratio with the above percentage.

• Dry and fragile cuttings fall of salinity and/or excessive additions of CaCI2 to maintain salinity, water content increase or several additions of oil to keep O/W ratio.

Too high activity. Embrittlement of cuttings helps the build up of fine solids. Formation can be weakened.

1) Excessive concentration of CaCI2.

1) Allow concentration to balance by itself if not severe, add oil and surfactants until balance point has been reached.

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5.

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0

SOLIDS CONTROL This section provides information relating to solids removal equipment aiding to the selection of choice and size of equipment required.

5.1

SOLIDS REMOVAL EQUIPMENT SPECIFICATIONS Hole Diameter

Max. ROP

26" 1 17 /2" 1 12 /4" 1 8 /2”

+/- 30m/hr +/- 30m/hr +/- 30m/hr +/- 15m/hr

5.2

Feed Rate Of Fluid To Be Processed +/- 4500ltr/min +/- 3800ltr/min +/- 3000ltr/min +/- 1500ltr/min

Drilled Solids Of Fluid To Be Processed 25-40t/hr 12-30t/hr 5-12t/hr 0.5-1t/hr

STATISTICAL DISTRIBUTION OF SOLIDS

% Solids 100 CENTRIFUGE 80

CYCLONES SHALE SHAKERS

60

40

20 Total solids

Drill solids

Barite

0% 0

25

50

75

100

125

150

175

200

225

250

275

Solids Size (Micron)

Figure 5.A - Statistical Distribution Of Solids 5.3

EQUIPMENT PERFORMANCE Centrifuge

D-Silter

Feature

Barite Recovery Centrifuge

High Volume

High Speed

Usage

Barite Recovery, LGS Removal

Large Volumes

Liquid Phase Recovery

G’

500-700

+/- 800

2100-3000

Cut Point Microns

6-10 per LGS, 4-7 per HGS

5-7

2-5

Feed Rates l/min

40-80

380-750

150-300

RPM

1600-1800

1900-2200

2500-3300

Cone Feed Rate Size (per unit l/min) 2”

60-80

4”

180-340

D-Sander Cone Feed Rate Size (per unit l/min) 5” 300 6” 370 8” 500 10” 1900 12”

1900

Shale Shaker Screen Mesh 20 x 20 30 x 30 30 x 40 40 x 36

Cut Point Microns 465 541 381 300

Processed Volume (l/min) 3800 3600 3400 3000

50 x 50 60 x 60 80 x 60 100x100 120x120 150x150

279 234 178 140 117 104

2800 2650 2300 1500 950 750

200x200

74

450

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0

EQUIPMENT RECOMENDATIONS SOLIDS-REMOVAL EQUIPMENT FROM WELL

SCALPING SHALE SHAKERS

HIGH PERFORMANCE SHALE SHAKERS (PREMIUM)

D-GASER

D-SANDER

D-SILTER (MUD CLEANER)

MAIN

CENTRIFUGE/S

ALTERNATIVE

POLYMER-BASE FLUIDS WITH INHIBITIVE SALTS

LOW DENSITY OIL-BASEFLUIDS

HIGH DENSITY OIL-BASE FLUIDS

x*

x*

x *

x *

x *

(x)

x

x

x

x

x

x

x

x

x

x

x

D-SANDER

x

x

x

x

D-SILTER

x x

x

x

x

x

SOLIDS-REMOVAL RECOMMENDED EQUIPMENT PER FLUID TYPE

STANDARD SHALE SHAKERS PREMIUM SHALE SHAKERS D-GASER

MUD CLEANER

x (*)

(x)

HIGH DENSITY WATER-BASE MUD (> 1,3 )

POLYMER FLUIDS

LOW GRAVITY WATER-BASE FLUIDS (<1.3 s.g.)

5.4

85 OF 155

x

x

CENTRIFUGES: -BARITE RECOVERY

x

- HIGH SPEED

*

()

SCALPING SHALE SHEKERS NOT OBLIGATORY

x x

- HIGH VOLUME

(x)

x

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5.4.1

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0

Double Shale Shakers

COARSE SCREEN

COARSE SCREEN

BACKFLOW PLATE

FINE SCREEN

Figure 5.B - No Backflow Plated Shale Shaker Description: Two-layer screen shale shaker with a course upper screen and a fine lower screen.

FINE SCREEN

Figure 5.C - Backflow Plated Shale Shaker Description: Two-layer screen shale shaker with an inclined plate located between them which allows fluid to flow back to the beginning of the fine lower screen.

Advantages: Simple and economical to use and maintain coarse screen removes most of the cuttings, thus limiting the wearing out of the fine screens. Limitations: Fluid losses from the lower screen. Wet cuttings due to the short stay on screens.

Advantages: Same as the no-backflow plated shale shaker with better use of the lower finer screen. Cuttings removed by the fine lower screen are drier than those of the no-backflow plated shale shaker system. Fairly good performance with reduced sizes Limitations:

Recommended for: • •

Marginal well plants, with low cost water base fluids and lower costs of waste discharge. Same as scalping shale shaker used in single deck, high performance configurations.

Replacement of the lower screens may be difficult. Cuttings are not as dry of a single deck shale shaker integrated with a scalping shale shaker. Recommended for: •

As a primary shale shaker, especially for water based fluids and noncascading plants (scalping, single deck, premium shale shaker).

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5.4.2

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0

Single Deck Shale Shakers

COARSE SCREEN

FINE SCREEN

Figure 5.E - Underflow Screens

Figure 5.D - Multiple Screens Description: Single deck, linear shaker with two more screens of different weave placed sequentially from the finer to the coarser. The screens can be positioned forwards or backwards.

Description: Single deck, single screen with the initial section completely underflowed by fluid. Screen vibration allows cuttings to overflow up the final inclined section. Advantages:

Advantages: Efficient and especially reliable with cuttings from hard formations or oil based fluids. If used properly, cuttings discarded are dry.

Designed to obtain very dry cuttings. 8-30 sized screens are installed when it is used as a scalping shaker. Limitations:

Limitations: All cuttings are processed by the fine screen which wears out more often, especially if cuttings are plastic (drilled clays with water based fluid). This problem can be solved by using a another shale shaker placed in front in sequence acting as a scalping shale shaker.

Is solely a speciality shale shaker to reduce residual oil, from cuttings. If used with water based fluids and plastic formations, the screens can be easily plugged. Recommended for: •

Recommended for: • •

Use as a primary shale shaker for oil based fluids. With the use of very fine screens their efficiency can be exploited by using a bank of shale shakers sufficient for the capacity required. This processes the volume of fluid an efficient cost.

Exclusive use with oil based fluids and when cutting discharge is allowed with an oil residue percentage which can be achievable.

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5.5

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0

SCREEN SPECIFICATION

Type Of Screen

Mesh Per Inch

Wire Diameter (ins)

Mesh Opening (Microns)

Flow Area (%)

1905 X1905 838 X838 381 X 81 178 X 78 117 X 17 105 X 5 74 X 4

56.3 43.6 36.0 31.4 30.9 37.9 33.6

762 X 3362 465 X 89 310 X 910 190 X 1037 200 X 406 457 X 140

45.7 39.1 36.8 34.0 31.1 35.6

Square Mesh Screens S10 S20 S40 S80 S120 S150 S200

10 X 10 20 X 20 40 X 40 80 X 80 120 X 120 150 X 150 200 X 200

0.025 0.017 0.010 0.0055 0.0037 0.0026 0.0021 Rectangular Mesh Screens

B20 B40 B60 B80 B100 B120

5.5.1

8 X 20 20 X 30 20 X 40 20 X 60 40 X 60 40 X 80

0.032/0.02 0.015/0.015 0.014 0.013/0.009 0.009 0.0075

Nomenclature Derrick

Description

Panel

Nomenclature SWG PWP GBG Pyramid

Screen

Example:

GBG HP 200 - Multiple, high performance screen mounted on a non-rigid support. 200 indicates that the equivalent mesh size does not correspond exactly to mesh number.

Derrick Description

Example:

DC DF DX HP SCGR

3 layered, derrick standard screens, non-repairable. 3 layered screens mounted on a rigid support, repairable with fitted plugs or silicon. The support takes up 35% of the flow area. 3 layered screens bonded to a non-rigid support, temporarily repairable. The support takes up 10% of the flow area. Corrugated screens on a rigid support gives approx. a 50% increase in flow area. Coarse mesh screens. Fine mesh screens. Extra fine mesh screens High performance screens. Rectangular mesh screens

BLS BXL S B

Nomenclature 3 layered screens with plastic strips between the coarse screen and the others. 3 layered screens mounted on a plastic grid. Square meshed screens. Rectangular meshed screens.

The letter designation is followed by a number which, as in ‘BLS’, ‘BXL’ and ‘S’ screens, indicates the mesh number. For ‘B’ designation, it is the sum of the mesh in both directions.

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5.6

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0

CYCLONE SYSTEMS

EFFICIENCY GRADE (%)

VISCOSITY/CYCLOPE PERFORMANCE (4") PV 6 cps, YP 1 gr/100cm2 100 PV 25 cps, YP 5 gr/100cm2 80 60 40 20 0

0

10

20

30

40

50

60

70

80

90

SOLIDS SIZE (MICRON)

Figure 5.F - Typical Viscosity/Cyclone Performance (4”) Equipment Desander Desilter Mud-Cleaner

Treatment Capacity Required 1.25 (Max. Perf. Q) 1.5 (Max. Perf Q) 1.5 (Max. Perf. Q)

Weight Difference Entrance/Discharge 0.3-0.6kg/l 0.3-0.4kg/l 0.3-0.4kg/l

Feed Pressure 30-45psi 30-45psi 30-45psi

Volume Discharged From Equipment 3 +/- 1.5m /h 3 +/- 3.5m h 3 +/- 1m /h

SPRAY DISCHARGE

DROP DISCHARGE

NO DISCHARGE

EXCESSIVE OPENING

PROPER FUNCTIONING

EXCESSIVE CLOSING

Figure 5.G - Calibration Of Water Discharge Cyclones

'B'

'B'

'A' SPRAY DISCHARGE

'C'

AIR CONE PROPER FUNCTIONING

WASHING AWAY -CONE HOLED IN "A" - PARTIALLY PLUGGED CONE IN "B" - TOO HIGH IN "C".

FLOOD - CONE OR COLLECTOR PLUGGED IN "B".

Figure 5.H - Typical Cyclone Malfunctions

DRY DISCHARGE - HIGH SOLIDS PERCENTAGE - CLOSED DISCHARGE.

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5.7

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0

CENTRIFUGE SYSTEMS

DECANTATION OF SOLIDS (POND)

DEHYDRATION OF SOLIDS (BEACH)

LIQUID DISCHARGE

SOLIDS DISCHARGE

ROTATING BOWL

FEED PIPE

SCROLL

SOLIDS DISCHARGE

OVERFLOW PORTS

FLUID FEED

Figure 5.I - Centrifuge Operating Principle

5.7.1

PrInciple Of Operation a) b) c) d)

Fluid to be processed is delivered to the centrifuge through the feed pipe. The rotating bowl creates a very high centrifugal force which increases the gravitational separation effects of the of fluids and solids. The solids being heavier gather on the drum walls and when build up are moved by the scroll to the solids discharge port. The liquids move through the unit to the liquid discharge port nozzles.

The liquids decanting effect and solids dehydration depends on the following: • •

‘g’ centrifugal force. Settling time of the solids on the drum.

Increasing

Feed Rate/H

‘G’

Micron Solids

Solids Fluid %

Feed Capacity

+

=

+

+

RPM

=

+

-

-

RPM Difference Between Rotor/Scroll

=

=

=

+

Height Of Underflow Ports

=

=

+

+

Table 5.A- Effects Of Variables

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5.7.2

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0

Centrifuge Processing

FLUID TO BE PROCESSED

LGS DISCHARGE

LGS DISCHARGE

PROCESSED FLUID

Figure 5.J - Unweighted Fluid-Parallel Processing

HIGH "G"

LOW "G" FLUID TO BE PROCESSED

BARITE RECOVERY

LGS DISCHARGE

PROCESSED FLUID

Figure 5.K - Weighted Fluid-Sequential Processing

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6.

92 OF 155

0

TROUBLESHOOTING GUIDE This section is a troubleshooting guide which addresses loss of circulation, describing remedial actions to be taken for the various types of losses and includes some information on the use of LCM and the appropriate procedures.

HIGH VISCOSITY FLUID

HIGH VISCOSITY FLUID AND HIGH GELS

FRACTURES

AERETED FLUIDS STIFF-FOAM

HIGH/VERY HIGH FILTRATION MIXTURE

DOBC

IDENTIFICATION CODE


HIGH FILTRATION MIXTURE

FLUID THINNING AND/OR UNWEIGHTING

HIGH DENSITY FLUIDS

STAP -P-1-M-6160

DOBC

DOB


SET TIME LOW LOADING

LOW DENSITY FLUIDS

HYDRAULICALLY-INDUCED FRACTURES



DOBC

GEL CEMENT DOBC

SPOT PILL WITH LCM

- HIGH FILTRATION FLUID

CEMENT + GELSONITE

GEL-CEMENT SLURRIES


SPOT PILLS WITH LCM

CEMENT/GEL CEMENT SLURRIES

CAVERNS

FRACTURES

FRACTURES

TOTAL


- LCM IN CIRCULATION

HIGHLY PERMEABLE

SURFACE AREAS

ALMOST TOTAL more than 50%

6.1

SEEPAGE LOSS less than 50%

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0

LOST CIRCULATION CONTROL TECHNIQUES

Figure 6.A - Lost Circulation Control Flow Chart

93 OF 155

REVISION

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6.2

94 OF 155

0

LOSSES IN VARIOUS FORMATION TYPES

Loss Determination In Various Formation Types Unconsolidated Formations

Sands, gravel beds, etc.

Gradual increase in loss which may develop and increase with penetration. If permeability is less than 4/5 darcy, the loss is maybe due to formation fracture.

Natural Fractures

Every type of elastic rock.

Gradual increase in losses which may develop and increase with penetration

Cavernous Or Macrovugular Formations

Limestones, dolomites, reef, volcanic rocks.

Sudden and severe, to complete loss, of returns. The bit may fall from a few centimetres to some metres at the moment of loss. Perforations may be 'disturbed' before the losses.

Induced Fractures

May occur to all formations.

Sudden and sever to complete losses.

It is likely to occur to preferred plans of fractures.

Fluids with density more than 1.3 SG may help create fractures. Fracture may occur during, or subsequent, to rough drilling. If it occurs in one single well and does not occur to the nearby wells, fracture may be the cause

6.3

CHOICE OF LCM SPOT PILLS

RESULTS GOOD IF USED WITH...

CEMENT

GOOD

NO GOOD

NONE

"PLASTIC" PLUGS

PERLITE

GRANULAR

(COTTON) FLAKE

FIBROUS

CELLOPHANE

MICA MACROFRACTURES/CARSIMS

FRACTURES

GRAVEL

SAND

Figure 6.B - LCM Spot Pill Selection Chart

PORES

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6.3.1

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0

LCM Information

Materials

Type

Granulometry (mm)

Seepage Loss

Partial Loss

CaCO3

Granular

50% @ +/- 0.05

X

CaCO3

Granular

CaCO3

Can Be Acidised

Can Be Used In OBM

X

X

X

50% @ +/- 0.1

X

X

X

Granular

50% @ +/- 0.6 a3

X

X

X

Fine Nuts

Granular

0.16 - 0.5

X

X

Medium Nuts

Granular

0.5 - 1.6

X

X

Coarse Nuts

Granular

1.6 - 5

X

Fine Mica

Lamellar

2-3

X

X

Coarse Mica

Lamellar

4-6

X

X

X

Vegetal Fibres

Fibrous

5 - 15

X

X

Cellophane

Lamellar

10 - 20

X

X

X

X

X X X

LCM Efficiency

Kg/m3 OF LCM

6.3.2

Total Loss

60

60

50

50

40

40

30

30

20

20

10

10

0

0 0

1

2

3

4

5

FRACTURE WIDTH (mm) FIBROUS LAMELLAR GRANULAR

Figure 6.C - Fracture Dependent Efficiency Of LCM

6

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6.4

TROUBLESHOOTING GUIDE

6.4.1

Loss Of Circulation With Water Based Fluids Treatment

Formulation

0

Operational Remarks Allow 4-8 hours set time. Plan further action to be taken.

Stand-By/Set Time High Viscosity Fluids

Add contaminants (lime, salt, etc.) to circulating fluids (lime, salt, etc.) by increasing viscosity and filtrate.

Viscosity at +/- 100sec.

LCM In Circulation

Approximately:

Shale shakers max., 10-12 mesh.

High Filtration Fluids

• • • • • •

Bentonite 5% Caustic Soda/Lime 10% Diatomite 10% Filtrate 30-50 cc 3 Volume, from 15 to 80 m of high filtration fluid conditioned with 68% of LCM adequate for loss.

Do not use with unstable formations.

• • • • • • •

Attapulgite 3-6% (bentonite 1.5-6%) Lime 0.15% Diatomite 15% *Mica 1-1.5% *Granular 1-2.5% *Fibrous 0.3-1% *(chosen dependent on loss).

RIH or EDP on top loss, squeeze with low pressure (starting with +/50psi @ 150ltr/min). Do not exceed fracture pressure and maintain for 6-8hrs.

• • • • • •

Same application procedure as high filtration slurries with o temperature >60 C. It may develop mechanical resistance.

Spot Pills With LCM

High Filtration Mixtures (200-400cc API)

Very High Filtration Slurries (>600cc API)

Fine mica 2% Fine granulars 2%

Diatomite 30% Lime 15% Attapulgite 0-4% *Granular 1-2.5% *Fibrous 1% *Lamellar 1% *(chosen dependent on loss)

Displace loss zone if there is excessive solids loading in the annulus. Squeeze slowly with a low pressure (50psi). Displace by means of bit with no nozzle or with nozzles >14/32".

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Treatment Diaseal M (Filtrate >1000cc API)

Cement Gilsonite

0

Formulation

Operational Remarks

Formulation for the preparation of 3 1m final Diaseal M Density Diaseal kg/l sacks 1.08 6 1.45 5 1.80 4 2.15 3

GEL Cement (Prehydrated Bentonite)

97 OF 155

Barite t 0 0.2 1.0 1.5

Same application procedure as high filtration slurries.

Water 3 m 0.9 0.8 0.7 0.6 A higher slurry must be prepared. The percentages Density indicated, provide mechanical resistance. Formation of slurries with higher percentages of kg/l Bentonite may improve LCM 1.9 characteristics while decreasing 1.6 mechanical resistance

Formula for preparing slurries ('G' cement) Bent

Water

% 0 2 3 4

weight% 44 84 104 112

Slurry Yield l/100kg 75.7 116.5 136.9 157.25

1.51 1.45

Good mechanical resistance associated with material control action of gilsonite. As for Density cement plugs, it is advisable to drill the loss zone and carry out kg/l the remedial procedure when 1.9 finished. 1.51 WOC for at least 8hrs.

Formulation for preparing slurries ('G' cement) Bent

Water

% 0 50 100 200

weight% 44 61 78 112

Slurry Yield l/100kg 75.7 139.5 203.9 330.25

1.37 1.25

DOBC Squeeze (Diesel Oil Bentonite)

Materials required for final vol. 1 3 m 3 • Diesel 0.72m • Cement 450kg • Bentonite 450kg

Apply DOBC/DOB squeeze procedure. RIH or EDP on top of loss zone. Plastic plug volume to equal, or be greater than, the hole below the loss zone first and second plug, both 3 about 1m diesel.

DOB Squeeze

Materials required for final vol. 3 1m 3 • Diesel 0.70m • Bentonite 800kg

When plug exits drill string, close annular preventer and pump fluids into annulus while displacing the plug from the DP. Drillpipe/ annulus ratio is 2:1, about 600 l/min from drillpie and 300 l/min from annulus. After displacing half the plug, reduce pump rate by half. After displacing 3/4 of the plug, attempt a 'hesitation squeeze pressure' with 100-500psi. Underdisplace plug by one barrel, POOH, allow 8-10hrs set time.

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6.4.2

98 OF 155

0

Loss Of Circulation With Oil Based Fluids Treatment

Formulation

Additions Of Colloid

Reduce HP/HT filtrate with asphalt filtration control additives. Add CaCO3 to +/- 5-15 microns.

Spot Pills With LCM

Volume, from 5 to 10m , added with LCM adequate for the loss and compatibility with the oil based fluid with a percentage varying from 5 to 10%.

Diaseal M (Filtrate >1000 cc API)

Plastic Plug With Organophil Clay

3

Operational Remarks Seepage loss is commonly due to low colloid contents of oil based.

Displace loss zone if there is excessive solids loading in the annulus, squeeze slowly with low pressure (50psi). Displace by means of bit with no nozzles or with nozzles >14/32". Formulation for preparing final Spot pill volume is double3 the hole 3 volume and at least 1.5m . To vol. 1m of Diaseal M 3 avoid contamination 3-4m , Density Diaseal Barite Water separating pills are advisable after 3 kg/l sacks t m and before. 1.08 5 0.2 0.9 Final pressure should be equivalent 1.45 4 0.7 0.8 to the max. density. 1.80 3 1.1 0.7 If the pill viscosity is too high, add 2.15 2 1.6 0.6 wetting agent. LCM may be added. Formulation for preparing final Spot pill volume should be double 3 the hole volume or at least 1.5m . vol. 1m3 3 To avoid contamination, 3-4m , Density 1.2 1.45 2.15(kg/l) separating pills in front and behind Water 0.67 0.72 0.54 (m3) are advisable. FCL 9 7 7 (kg) Final pressure should be equivalent NaOH 4 4 4 to the max. density. Org.clay 550 712 285 (kg) If the pill viscosity is too high, add a Barite 1540 (kg) wetting agent. LCM may be added.

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REVISION

Treatment Fresh Water Barite Plug

99 OF 155

STAP -P-1-M-6160

0

Formulation

Operational Remarks

• Determine the height of the plug, commonly 130-150m is Density 2.16 2.4 2.64(kg/l) sufficient. Water 0.64 0.57 0.5 (m3) • Choose the desired density, the SAPP 2 2 2 (kg) lower the density, the faster the NaOH 0.7 0.7 0.7 (kg) setting time. *(FCL) (6) (6) (6) *(NaOH)(1.4) (1.4) (1.4) • Calculate the plug volume by Barite 1530 1850 2155 adding 10 barrels. • Calculate the amount of * as alternative to SAPP and materials required. Soda. • Evaluate displacement • Mix with cement unit. • Use bit with nozzles. • Under displace leaving two barrels. • Pull out above plug and Circulate as long as you can, in order to allow plug to settle. Note: • The use of fresh water is advisable, as sea water does not allow a proper settling. • Maintain mix water pH at 8-10. Formulation for preparing 1m3

• For preparing a pumpable fluid, follow the indications herein given using galena. Oil Based Fluid Barite Plug

3

Formulation for preparing 1m Density Oil EZ MUL Water Barite

Water Based Fluid With Galena

2.4 0.51 20 27 1930

2.64 kg/l 0.49 (m3) 17 (kg) 26 (L) 2530 (kg)

Formulation for preparing 1m3 Density Water Bent Na2CO3 SAPP Galena Barite

2.88 0.58 23 4 2 1325 955

3.36 0.51 8 5 2 1995 838

3.84 kg/l 0.51 (m3) 5 (kg) 5.7 (kg) 5.7 (kg) 3320 (kg) ....... (kg)

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Treatment Oil Based Fluid With Galena

100 OF 155

0

Formulation

Operational Remarks 3

Formulation for preparing 1m Base Fluid (Invermul) Oil 0.85 (m3) Water 0.15 (m3) Driltreat 35 (kg) Suspentone 52 (kg) Gelitone II 10 (kg) Duratone HT 35 (kg)

Formulation for preparing 1m3 Density Base Fluid Driltreat

3.36 0.59

3.6 0.55

4.32 kg/l 0.43 (m3)

---

---

14 (kg)

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0

STUCK PIPE TREATMENT/PREVENTITIVE ACTIONS This section gives recommendations on preventive measures to avoid stuck pipe in addition to appropriate treatments to solve the problem.

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0

STUCK PIPE TREATMENT/PREVENTION

STUCK PIPE PARAMETERS

YES

DIFFRENTIAL PRESSURE

NO

NO

OUT OF HOLE

DOWN IN HOLE

STUCKPIPE TYPE

ROTATING

FREE DRILLSTRING

CIRCOLATION

7.1

102 OF 155

CAUSE

TREATMENT/PREVENTIVE ACTIONS

NO - HIGHLY PERMEABLE FORMATIONS - EXCESSIVE CAKE - DRILL STRING JAMMED - DEPLETED LEVELS.

TREATMENT - WORK DRILL STRING UP AND DOWN CLAY-BASE WATER FLUIDS:

EZ SPOT FORMULATION FOR PREPARING 1 m3 DENSITY Kg/l EZ SPOT GASOLIO ACQUA BARITE

0,9

1,2

1,44

1,68

1,92

2,16

80 650 270 --

80 580 260 396

80 540 220 710

80 490 210 995

80 510 110 1310

80 440 100 1620

IF NEEDED ADD 1% SURFANCTANT (i.e. PRESANTIL)

- DENSITY UP TO 1.35 Kg/l, USE DIESEL OR LT OIL CONDITIONED WITH SURFANCTANT (PIPELAX, OR PRESANTIL ETC..); - DENSITY MORE THAN 1.35 Kg/l, PREPARE A SPOT PILL WITH WEIGHTED OIL (EZ-SPOT, PRESANTIL W, ORGANOPHIL CLAY PILLS, ETC...);

POLYMER-BASE FLUIDS: - IN ORDER TO DISGRAGATE THE CAKE, USE SOLUTIONS OF CaCl2 AND/OR NaOH (pH>12);

ORGANOPHIL CLAY PILLS FOR PREPARING 1 m3 DENSITY Kg/l

1,4

1,5

1,6

DIESEL ORGANOPHIL CLAY BARITE SURFANCTANT (i.e. PRESANTIL)

790 70 640 30

770 50 780 30

740 45 900 30

OIL-BASE FLUIDS: - MECHANICAL RELATED TREATMENT. IF POSSIBLE, LOWER THE FLUID GRADIENT BY UNWEIGHTING THE FLUID OR DECREASING THE HYDROSTATIC LOAD BY MEANS OF UNWEIGHET PILLS OR OPEN HOLE PACKER AND A VALVE TESTER.

OPERATIONAL REMARKS MINIMUM VOLUME= 2.3 TIME DC-HOLE VOLUME (Vi)

PREVENTIVE ACTIONS: DISPLACEMENT PROCEDURE: - DISPLACE 1ST SEPARATING PILL + 1.3 Vi; - ALLOW 40-60 MINUTES SET TIME; - DISPLACE 1/2 Vi.

- MINIMIZE THE FLUID WEIGHT AT THE LOWEST VALUE ALLOWED; - REDUCED SURFACE CONTACT BETWEEN DRILLPIPE AND FORMATION (SPIRAL DC, HIGHLY STABILIZED DRILL STRING ASSEMBLY, etc.); - MAINTAIN THE CAKE THICKNESS BY ADEQUATE FILTRATE AND SOLIDS PERCENTAGE.

- ALLOW 2-3 HOURS SET TIME.

- REPEAT TREATMENT IF NEEDED; - MAX NUMBER OF TREATMENTS ALLOWED = 4 (STATISTICAL FIGURE).

N.B.REDUCED STUCKPIPE BROBLEMS WITH: OIL-BASE FLUIDS, BUT INCREASED TREATMENT DIFFICULTIES IN DISGREGATING CAKE.

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0


CIRCOLATION

ROTATING

DOWN IN HOLE

OUT OF HOLE

FREE DRILL STRING

COLLAPSING NO

NO

NO

NO

STUCK PIPE TYPE

CAUSE

- SHALE SWELLING; - STRESSED BRITTLE SHALES; - UNSUFFICIENT FLUID WEIGHT; - FLUID AND/OR DRILL STRING MECHANICAL EFFECT.


TREATMENT - RE-ESTABLISH CIRCULATION WITH PRESSURE PEAKS AND DRILL STRING MOVEMENTS. CAUTION SHOULD BE EXERCISED TO AVOID FRACTURES TO THE FORMATION BELOW THE STUCK POINT; - ONCE CIRCULATION IS RE-ESTABLISHED, PUMP VISCOUS PILLS BY WORKING DRILL STRING UP/DOWN; - DOG LEGS CANNOT BE USED; - IF CIRCULATION CANNOT BE RE-ESTABLISHED, THEN UTILIZE WASHING PIPES. PREVENTIVE ACTIONS - REDUCE FILTRATE; - ADD ASPHALT COATERS; - REDUCE TURBOLENT FLOW AGAINST WALLS; - EMPLOY FORMATION INHIBITION FLUIDS; - INCREASE INITIAL GELS WHILE DECREASING FINAL ONES; - SLOWLY INCREASE DENSITY. IF INSTABILITY IS NOT DUE TO OVERPRESSURE, THE BENEFICIAL EFFECT WILL BE TEMPORARY.

COLLAPSING NO DUE TO ACCUMULATION OF CUTTINGS

NO

NO

- POOR HOLE CLEANING - LOADING/RHEOLOGY NOT ADEQUATE PENETRATION RATES: - IT MAY OCCUR IN HIGH ANGLE HOLES (35-60 DEGREES).

TREATMENTS AS A COLLAPSING PREVENTIVE ACTIONS - UTILIZE HIGH FEED RATES; - MAINTAIN ADEQUATE RHEOLOGY, ESPECIALLY FOR HIGH ANGLE HOLES WHERE VISCOSITY SHOULD BE LOW ENOUGH AND SHARE SPEEDS SHOULD BE EQUIVALENT TO THE ANNULUS BY MAINTAING FAST/FLAT GELS IN ORDER TO LIMIT CUTTING SETTLING AT THE MOMENT OF CIRCULATION ARREST. BY MEANS OF EXAMPLE: LOW READINGS AT 100 RPM; HIGH READINGS AT 6 AND 3 RPM AND GELS AT 10". - EVALUATE SOLIDS-REMOVAL GRADE IN ORDER TO DEFINE THE CORRECT VALUES OF READING. THEREFORE, ANALIZE SOLIDS RECOVERY ON THE SURFACE DEPENDENTKY ON HOLE VOLUME, BY CONSIDERING THE DIFFICULTIES ENCOUNTERED WHILE TRIPPING AS THE INDEX OF CUTTING QUANTITY INTO THE BOREHOLE.

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104 OF 155


0


KEY SEAT

OUT OF HOLE

DOWN IN HOLE

ROTATING

STUCK PIPE TYPE

CIRCOLATION

FREE DRILL STRING

CAUSES

YES YES (YES) NO - INCLINATION VARIATIONS; - DEVIATED WELLS; - SLOW ROP.


TREATMENT - WORK DRILL STRING UP AND DOWN; - DISPLACE A PILL: A) FLUID CONDITIONED WITH 5-6% LUBRICANT OR 10-20% EXAUST OIL OR DIESEL. B) ACID PILL IF CARBONATE FORMATION.

PREVENTIVE ACTIONS - RE-RUN WITH KEY SEAT WIPER OR UNDERGAUGE STABILIZER ON THE TOP DC. - RE-RUM DOWN IN HOLE WHERE THE KEY SEAT IS PRESUMABLY LOCATED; - ADD LUBRICANTS TO THE FLUIDS. DOG LEGGING

YES YES

NO

NO - SUDDEN VARIATIONS OF INCLINATION; - TRIPPING DOWN IN HOLE WITH A MORE RIGID DRILL STRING.

TREATMENT - AS PER KEY SEATING PREVENTIVE ACTIONS: - SLOWLY RUN IN HOLE AVOIDING WEIGHT LOSS OF DRILL STRING. RE-RUN IF NEEDED; - ADD LUBRICANT TO THE FLUID.

UNDEGAGE HOLE

YES NO

NO

NO

- UNDERGAGE DRILL STRING

INTERVENTO - AS PER KEY SEATING PREVENTIVE ACTIONS: - CHECK STABILIZER BIT DIAMETER; - RE-RUN THE DRILLING ZONE.

(YES) NO

NO

NO

- TOO THICK CAKE

TREATMENT - WORK DRILL STRING UP/DOWN; - RE-ESTABLISH CIRCULATION - USE AN ANTI-STUCK PIPE PILL IN ORDER TO DESGREGATE THE CAKE, IN ADDITION TO LUBRICANTS.

PREVENTIVE ACTIONS - CONTROL CAKE THICKNESS AND QUALITY. (YES) NO

NO

NO

- PLASTIC DEFORMATION OF SALINE FORMATIONS OR GUMBO SHALES.

TREATMENT - WORK DRILL STRING UP/DOWN; - RE-ESTABLISH CIRCULATION; - USE ANTI-STUCK PIPE PILL IN ORDER TO DISGREGATE THE CAKE, IN ADDITION TO LUBRICANT.

PREVENTIVE ACTIONS - MAINTAIN AN ADEQUATE FLUID WEIGHT.

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8.

105 OF 155

0

DRILLING FLUID TRADEMARK COMPARISONS Comparison of similar products and functional performances are compared in this section. This comparison evaluates the various products with the differing concentrations required against their relevant costs. Technical and/or economical analyses of all differing products should be carried out with the concentrations required in similar operational conditions and results.

ARPO

IDENTIFICATION CODE

PAGE



8.1

Code

8.1.1

106 OF 155

0

DRILLING FLUID PRODUCT TRADEMARKS

Description

AVA

Bariod

Dowell

Baroid

Barite

MI

BH Inteq

M-I Bar

Mil-Bar

Weighting Materials

0101

Barite

0105

Siderite

Barite

0107

Calcium Carbonate

AVACARB

Baracarb

Ca Carbonate

Lo-Wate

WO 30

0108

Ematite

AVAEMATITE

Barodense

Id-Wate

Fer-Ox

Mil-Dense

8.1.2

Viscosifiers

Baraweight

Siderite

0201

Bentonite

AVAGEL

Aquagel

Bentonite

M-I Gel

Mil-Gel

0203

Attapulgite

Dolsal B

Zeogel

Salt Gel

Salt Gel

Salt Water Gel

0204

Sepiolite

Dolsal

Geltemp

Durogel

0413

HEC

Natrasol 250

Baravis

Idhec

HEC

WO 21

0415

Biopolymers Biopolymers PUR

Visco XC 84

Barazan

Idvis

XC-Polymer

XC Polymer

0420

Bentonite Extender

AVABEX

X-Tend II

DV 68

Gelex

Benex

0423

PHPA HM Weight

Polivis

EZ-Mud

Id-Bond

Poly-Plus

New Drill

AVAFLUID G71

Q-Broxin

FCL

Spersene

Uni-Cal

AVAFLUID-NP

Q-B II

Chrome-Free LS

Spersene CF

Uni-Cal CF

CC 16

Caustilig

Ligcon Ligco

8.1.3

Flo-Vis

Thinners

0501

Fe-Cr Lignosulfonate

0502

Modified Lignite

0503

Cr-Free Lignite

0506

Caustic Lignite

0507

Lignite

AVATHIN

Carbonox

Tannathin

0508

Potassium Lignite

AVAK-LIG

K-Lig

K-17

0509

Cr Lignite

AVALIG

0510

Phosphates

AVASAPP

Barafos

0511

Tannins

AVARED

Quebracho

0512

Cr Tannins

Desco

Desco

Cr-Free Tannins

Desco-CF

0424

PHPA LMW

Polifluid

0513

HT Deflocculants

AVAZER-5000

Ca Modified LS

Thermathin

Chrome Lignite

XP-20

STP

Phos/SAPP

STP

Quebracho Desco

ID Thin 500

Desco

Desco

Desco CF

Desco CF

Tackle

New-Thin Mil-Temp

Lignox

Rheomate

Aquathinz

ARPO

IDENTIFICATION CODE

PAGE



Code

8.1.4

Description

107 OF 155

AVA

Bariod

0

Dowell

MI

BH Inteq

CMC

CMC

Filtrate Reducers

0401

Technic CMC HV/LV

CMC

Cellex

CMC

0403

Semipurif. CMC HV/LV

CMC-S

CMC S

CMC S

0405

Purified CMC HV/LV

CMC-P

CMC P

CMC P

Driscose

0407

K-CMC LV/HV

Agipak

K-PAC R/LV

Agipak

0409

Purified PAC R/LV

Visco 83

PAC

IDF-FLR

Polypac

Drispac

0411

Semi Purified PAC R/LV

Policell

Barpol

IDPAC

0416

Na Polyacrylates

Policell ACR

Polyac

Polytemp

SP 101

New-Trol

0418

Pregelat. Starches

Victogel AF

Impermex

IDFLO LT

MY-LO-Gel

Milstarch

0417

Non-Ferm. Starches

Victosal

0419

HT Starches

AVATEMP

Milpac

Flo-Trol Dextrid

IDFLO

Polysal

IDFLO HTR

Thermpac UL

Permalose HT

Burastar 0421

AVAREX

Baranex

IDF HI-Temp

Resinex

Filtrex

Envir. Friendly Lubricant.

Ecolube

Tork Trim II

Idlube

Lube 167

Mil-Lube

0303

EP Lubricants

AVALUB EP

EP Mudlube

0302

Various Lubricants

AVA GreenLube

Lubrabeads

8.1.5 0301

8.1.6

HT Polyster Mixture

Lubricants

Stick Less

Lube 100 Easy Drill

EP Lube

Lubrifilm

Graphite

Walnut Shells

Detergents/Emulsifiers/Surfactants

0307

Detergents

AVADETER

Condet

Drilling Deter.

DD

MD

0308

Non-ionic Emulsifiers

TCS 30

Aktaflo E

IDMULL 80

DME

DME

0309

non-ionic Surfactant.

AVAENION

Aktaflo S

Hymul

DMS

DMS

Salinex

Atlosol

Anionic Surfactant

Trimulso Clay Seal

ARPO

IDENTIFICATION CODE

PAGE



Code

8.1.7

108 OF 155

Description

AVA

0

Bariod

Dowell

MI

BH Inteq

Pipe-Lax

Mil-Free

Stuckpipe Surfactants

0310

Oil-Soluble Surfanc.

AVATENSIO

Skotfree

IDFREE (UW)

0618

Oil Fluid Concentrate.

AVATENSIO W

Envirospot

IDFREE

Pipe-Lax

W

Black Magic

Pipe-Lax Env

Spotting Oilfree

8.1.8 0303

Borehole Wall Coaters Oil-Dispersable Asphalt

Stabilube

0304

WaterDispersable Asphalt

AVATEX

Barotroll

0306

Sulphonate Asphalt

Soltex

Soltex

IDTEX W

Gilsonite

AVAGILS-W

Barbalok

IDTEX

8.1.9

AK 70

Asphalt

Stabihole

Protectomagic

Holecoat II

Protectomagic M

Soltex

Soltex

BXR-L

Soltex

Defoamers/Foamers

0909

Stereate Al

Stearal

0912

Silicon Defoamers

AVASIL

SDI

IDF Antifoam S

Defoam X

LD 8

0911

Alcohol Defoamers

AVADEFOAM

Baradefoam W300

IDF Defoamer

Magconol

WO Defoam

0913

Foamers

AVAFOAM

Quik-Foam

HI Foam 440

8.1.10

Ampli foam

Corrosion Inhibitors

0901

PO Scavenger

Sodium Sulphite

Barascav D

Idscav 210

Oxygen Scavanger

Noxigen

0907

Fe-Base Hydr. Sul. Sc.

Ironite Sponge

Ironite Sponge

Ironite Sponge

Ironite Sponge

Ironite Sponge

0918

Zn-Base Hydr. Sul. Sc.

Zinc Carbonate

No-Sulf

Idzac

Sulf X

Milgard

Filming Amines

Incorr

Barafilm

Idfilm 220

Conqor 303

Aquatec

Filming DP

Incorr-Q5

Barafilm

Idfilm 120

Conqor 202

Amitec

Anti-Scale

AVA AS-1

0903

Refer to specific literature

ARPO

IDENTIFICATION CODE

PAGE



Code

8.1.11

109 OF 155

Description

0

AVA

Bariod

Dowell

MI

BH Inteq

Bactericides

0914

Paraformaldeide

Paraformaldeide

Paraformaldeide

Paraformaldeide

Paraformaldeide

Paraformaldeide

0915

Liquid Bactericide

AVACID F25

Aldacide G

IDCIDE

Bacbane III

Mil-Bio

8.1.12

Lost Control Materials

0701

Granular

Granular

Wallnut

Wallnut Shells

Nut Plug

Mil-Plug

0702

Mica

AVAMICA

Micatex

Mica

Mica

Mil-Mica

0703

Fibrous

Lintax

Fibertex

Mud-Fiber

Fiber

Mil-Fiber

0704

Cellophene

Jel-Flake

Cellophene Flakes

Flake

Mil-Flake

0705

Mixed

Intamix

Baroseal

ID Seal

Kwik-Seal

Mil-Seal

0706

High Filtration

Diascal M

Diaseal M

Diaseal M

Diaseal M

Diaseal M

0707

Diatomite

Diatomite

0708

Acidified

Intasol

8.1.13

Chemical Products

1001

Caustic Soda

1002

Caustic Potassium

1003

Hydrated Lime

1004

Sodium Carbonate

1005

Potassium Carbonate

1006

Barium Carbonate

1007

Sodium Bicarbonate

1008

Potassium Bicarbonate.

1009

Gypsum

1010

Sodium Chloride

1011

Calcium Chloride

1012

Potassium Chloride

1013

Sodium Bromure

1014

Calcium Bromure

IDF D-Plug Baracarb

Common to all suppliers.

Calcio Carbon

ARPO

IDENTIFICATION CODE

PAGE



Code

8.1.14

Description

110 OF 155

AVA

0

Bariod

Dowell

MI

BH Inteq

Oil Based Fluid Products System Name

AVAOIL

Invermul

Interdrill

Versadril

Carbo-Drill

0601

Primary Emulsifiers

AVAOIL-PE

Invermul

Emul

Versamul

Carbo-Tec

0602

Secondary Emulsion

AVAOIL-SE

EZ-Mul

FL

Versacoat

Carbo-Mull

0603

Wetting Agents

AVAOIL-WA

Driltreat

OW

Versawet

Surf-cote

0605

Organophil Clays

AVABENTOIL

Geltone II

Vistone

Versagel

Carbo-Gel

0608

Asphalt Filtrate Reducers

AVAOIL-FRHT

AK 70

S

Versatrol

Carbo-Trol

Non-Asphalt Filtrate Reducers

AVAOIL-FC

Duratone

NA

Versalig

Carbo-Trol (A9)

Thinners

AVAOIL-TN

OMC

Defloc

Versathin

Rheology Modifiers

AVAOIL-VS

RM-63

IDF Truvis

Versamod

Charbo-Thix

System Name

AVAOIL-LT

Enviromul

Interdrill NT

Versaclean

Carbo-SEA

0601

Primary Emulsifiers

AVAOIL-PELT

Invermul NT

Emul

Versamul

Carbo-Tec

0602

Secondary Emuls.

AVAOIL-SELT

EZ-Mul NT

FL

Versacoat

Carbo-Mull

0603

Wetting Agents

AVAOIL-WALT

Driltreat

OW

Versawet

Surf-cote

Organophil Clays

AVABENTOIL

Geltone II

Vistone

Versagel

Carbo-Gel

0610

0605

Organophil Clays/HT

0608

Asph. Filtr. Reducers

0610

Versagel HT AK 70

S

Versatrol

Carbo-Trol Carbo-Trol (A9)

Non-Asph. Filtr. Red.

AVAOIL-FCLT

Duratone

NA

Versalig

Thinners

AVAOIL-TNLT

OMC

Defloc

Versathin

Rheology Modifiers

AVAOIL-VSLT

RM-63

IDF Truvis

Versamod

Charbo-Thix

ARPO

IDENTIFICATION CODE

PAGE



Code

111 OF 155

0

Description

AVA

Bariod

Dowell

MI

BH Inteq

System Name

AVA Core

Baroid 100

Trudrill

Versacore

Carbo-Core

EZ Core

Trumul

Versamul

Carbo-Tec

0601

Primary Emulsifiers

0602

Secondary Emuls.

AVAOIL-SE

Trusperse

0603

Wetting Agents

AVAOIL-WA

Trusperse

Versa SWA

0605

Organophil Clays

AVABENTOILHY

Geltone III

Truvis

VG 69

Carbo-Gel

0608

Asph. Filtr. Reducers

AVAOIL-FRHT

AK 70

Trudrill S

Versatrol

Carbo-Trol

Non-Asph. Filtr. Red.

AVABIOFILHT

Baracarb

Truloss

LoWate/Fazegel

Carbo-Trol (A9)

Truplex

Versa HRP

Carbo-Vis HT

0610

Thinners

Carbo-Mull

Defloc

Rheology Modifiers

AVAOIL-VS

System Name

AVABIOL

Petrofree

Ultidrill

Novadrill

0601

Primary Emulsifiers

AVABIO PRI.

EZ Mul NTF

Ultimul

Novatec-P

0602

Secondary Emuls.

AVABIO Sec.

Ultimul II

Novatec-S

0603

Wetting Agents

AVABIO Wet

Ultisperse

Novawet

0605

Organophil Clays

AVABIO Bent

Ultitone

VG 69

0608

Asphalt Filtrate Reducers

0610

Geltone II

Vestrol

Non-Asphalt Filtrate Reducers

AVABIOFILHT

Duratone HT

Thinners

AVABIO Thin

OMC 2/42

Rheology Modifiers

AVABIO VIS-

Ultiflo

Versalig

Ultivis

Novamod

ARPO

IDENTIFICATION CODE

PAGE



Code

8.1.15

Description

112 OF 155

AVA

Bariod

0

Dowell

MI

BH Inteq

Lamium BFF.

Lamium

Base Liquids And Corrections

0801

Fresh Water

0802

Sea Water

0803

Brine

0804 0811

Diesel

0812

Fuel Oil

0813

Exhaust Oil

0814

Low Toxicity Oil

Lamium/ AVAOIL base

0815

Glycol GP

AVABIOLUBE

Gem-GP

0816

Glycol CP

AVAGLICO

Gem-CP

0817

Oil Base

AVAOIL base

0818

Synthetic Base

HF 100 N Staplex

Gliddrill-LC

Synthec

0819 0820

KLA-Cure Clay Inhibitor

Aquacol TM Aquacol TM-D Aquacol TM-S

KLA-Gars

ARPO

IDENTIFICATION CODE

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9.

113 OF 155

0

DRILLING FLUIDS APPLICATION GUIDE This document is an extract from a more comprehensive guide published by World Oil relating to some of Eni-Agip's most important contractors, namely AVA, Baroid, Baker Hughes Inteq, MI, Schlumberger, Dowell and IDF. The product functions and systems, for which these products are employed, contained in this section, are provided by the contractors named above.

ARPO

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114 OF 155


0

9.1APPLICATIONS GUIDE APPLICATION GUIDE TO DRILLING FLUID PRODUCTS

X

ALLUMINIUM STERATE AMITEC AMPLI-FOAM

X

ANTIFOAM-S AP-21 AQUA-MAGIC

X X

AQUA-SEAL ASPHALT ATTAPULGITE

X X X

AVAGUM AVALIG AVA PVA

X

AVAREX AVASIL AVATENSIO

X

X

X

X

X

X

X

X X

X

X X

X X

X

X X

X

X

X X X X

X X X

X X X

X X X

X

X X X

X X X

X X

X

X X X

X X X

X X X

X X X

X X X

X X X

X X X

X X X

X

X

X

SH

SU B TH

FL

D LU FO

D LU FO

D LU FO

D FI LU

LU

LU

SH SH V

FI LU SH

FI FI

V TE SH

SH TH

SU FI SH

FI D P

TE

SH

FI FI

SU SU TE

AVOIL-FC AVOIL-PE AVOIL-SE

X X X

FI E E

AVOIL-TN AVOIL-VS AVOIL-WA

X X X

TH V SU

FI

B B SH

CO

BACBAN III BARA-B466 BARABLOK

X X X

X X X

X X X

X X X

X X X

X X X

X X

BARA BRINE DEFOAM BARABUF BARACARB

X X X

X

X X X

X X X

X X X

X X X

X

Legend A B CA CO D E FI FL FO LO

= = = = = = = = = =

Alkaline Agent Bactericide Ca Precipitant Corrosion Inhibitor Defoamer Emusifier Filtrate Reducer Flocculant Foamer Loss Control Agent

X

LU P PA SH SU TE TH V W

X

= = = = = = = = =

X

X

SECONDARY

SECONDARY

SH

X

X

PRIMARY

X

AIR-AERATED

X

X X X X

X X

X

X

X

X X X X

SALT SATURATED

LOW SOLIDS

LIME-BASE

X

OIL-BASE

AKTAFLO-S ALDACIDE-C ALL-TEMP

X

FUNCTIONS

WORKOVER

X

DISPERSED

NON DISPERSED ACTIGUM

POLYMERS

FLUID SYSTEMS

PRODUCTS

E

LU

D A CO

Lubricant Pipe Freeing Agent Polar Activator Shale Inhibitor Surfactant HT Stabilising Agent Thinner Viscofier Weighting Agent

FI

ARPO

IDENTIFICATION CODE

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115 OF 155


0

APPLICATION GUIDE TO DRILLING FLUID PRODUCTS

X X

X X X

X X X

X X X

X X X

X

BARACOR 113 BARACOR 129 BARACOR 450

X X

X X

X X

X X

X X

X X X

X X X

X

BARA-DEFOAM-C BARADEFOAM W-300 BARAFILM

X X X

BARAFLOC BARAFOAM BARAFOAM-K

X

BARAFOS BARA-KLEAN BARANEX

X

X

X

X

X X

X

X X X

X X X

X X X

X X X

X X X

X

X

X

X

X

X

CO CO CO

TE

CO CO PA

X

X

X X

FL FO FO TH SU FI

X X

X

X

X

X

X

X

X

X

CO

X

X

X

X

X

X

X

CO SU

X

X

X

X X X

X

X

X

X

X

X

BARAZAN L BARITE BARODENSE

X X X

X X X

X X X

X X X

X X X

X X X



X X

= = = = = = = = =

X

X

CA TE

LO LO V

X

BARAVIS BARAWEIGHT BARAZAN

= = = = = = = = = =

TE

D D CO

X X X

SH CO CO

X X X

X

BARAPLUG X, XC BARARESIN GRANULE BARARESIN-VIS


AIR AIRATED X

BARACOR 700 BARACOR 1635 BARACTIVE

BARASCAV-D BARASCAV-L BARASCRUB

X

SECONDARY

X X X

PRIMARY

BARACAT BARACOR-95 BARACOR-100

OIL-BASE

FUNCTIONS

WORKOVER

SALT SATUR.

LOW SOLIDS

POLYMER-BASE

LIME-BASE

DISPERSED

NON DISPERSED

MUD SYSTEMS

SECONDARY

PRODUCTS

V W V V W W


A

ARPO

IDENTIFICATION CODE

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116 OF 155


0


X X

X X X

X X X

X X X

X X X

X X

BARO-LUBE BARO-SEAL BARO-SPOT

X X X

X X X

X X X

X X X

X X X

X X X

X

BAROTHIN BARO-TROL BENTONITE

X

X X

X X

X

X X

X

TH SH

SH LU

X

X

X

X

X

V

SH

X

X

X

FI

BIO-LOSE BIO-PAQ BIO-SPOT

X

X X X

X X

X X X

FI FI P

LIME-BASE

X

X

BIO-SPOT II BLACK SPOT MAGIC BLACK SPOT MAGIC CLEAN

X

X

X

X

X

X

X

P P P

X

X

X

X

X

X

X

X

BLACK MAGIC LT BLACK MAGIC SFT BRINE-PAC

X X

X X

X X

X X

X X X

X X

X X

X X

X X

X

X

BROMIMUL BROMI-VIS BRINE-PAC

X X

BROMIMUL BROMI-VIS BX-L

X X X X

X

X

X

X

X X

X

X

X

X

X

X

CARBO-GEL 2 CARBO-GEL N


= = = = = = = = = =



= = = = = = = = =

LU

LU LO P

X X X

CANE FIBER CARBO CORE CARBO-GEL

SH LO W

SECONDARY

OIL-BASE

X X X

PRIMARY

WORKOVER

X X X

AIR AIRATED

SALT SATUR.

BARO-DRILL 1402 BAROFIBRE BAROID

DISPERSED

LOW SOLIDS

FUNCTIONS

POLYMER-BASE

NON DISPERSED

FLUID SYSTEMS

SECONDARY

PRODUCT

FI E

FI

P P CO E V CO E V SH

FI

X X

LO E V

FI

X X

V V


FI

ARPO

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CARBO-MIX CARBO-MUL CARBO-MUL A CARBO-MUL HT CARBONOX CARBOSAN-EF

X

X X

X X

X X

X X

X

X X X

E E E

X

E TH B

SU FI

TE E

FI

TE

X

X

SU

CARBO-TEC CARBO-TEC HW CARBOTHIX

X X X

E E V

CARBO-TROL CARBO-TROL A-9 CARBO-TROL A9 HT

X X X

FI FI FI

X X

V LO FI

LO

X X

FI FI FI

V

CARBOVIS CARBO-SEAL CAT-300

X

CAT-GEL CAT-HI CAT-LO

X X X

CAT-THIN CAUSTILIG CC-16

X

CELLEX CELLOPHANE FLAKES CHEK-LOSS

FI

X

X

X

X

X X X

X X X

X X X

X X X

X X X

X X X

X X X

X

X X

X

TH TH TH

TE FI FI

X X X

X X X

X X X

X X X

X X

FI LO LO

V

X X

CHEMTROL X CHROMEX CHROME FREE II

X

X X X

X X X

X X

X X

FL TE TH

TE TH FI

CLAY-SEAL CMO-568

X

X

X

X

X


= = = = = = = = = =

X

X

X

X X X X

SH X



= = = = = = = = =

SECONDARY

PRIMARY

AIR AIRATED

OIL-BASE

FUNCTIONS

WORKOVER

SALT SATUR.

LOW SOLIDS

POLYMER-BASE

LIME-BASE

DISPERSED

NON DISPERSED

FLUID SYSTEMS

SECONDARY

PRODUCT

LU


LO

TE TE

TH FI

ARPO

IDENTIFICATION CODE

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X

X X

X

X

X

X

X

X

SU CO CO

CONQOR 303 CONQOR 404 CONQOR 505

X X X

X X X

X X X

X X X

X X X

X X X

X X X

X X

CO CO CO

DCP-208 D-D DE-BLOCK/S

X X X

X X X

X X X

X X X

X X X

X X X

X

X

DEFOAMER DEFOAM-X DENSIMIX

X X X

X X X

X X X

X X X

X X X

X X X

X X X

X X

DEXTRID DIASEAL M/DIEARTH DIATOMITE

X

X

X

X

X

X

X

X

X

X

X

X

X

FI LO LO

DI-PLUG DOLSAL DOLSAL B

X X X

X X X

X X X

X X X

X X X

X X X

X X X

LO V V

DRILFOAM DRILLING PAPER DRILTREAT

X

X

X

X

X

X

CON-DET CONQOR 101 CONQOR 202

X

X X

DRYOCIDE DURATONE HT DUROGEL

X

X

X

X

X

X

X

X

X

X

X

X

X

X

ECOL LUBE ENION ENVIRO SPOT

X X X

X X X

X X X

X X X

X X X

X X X

X


= = = = = = = = = =

X



X X

X

= = = = = = = = =

SH SU E

SECONDARY

PRIMARY

AIR AIRATED

OIL-BASE

FUNCTIONS

WORKOVER

SALT SAURATED

LOW SOLIDS

POLYMER-BASE

LIME-BASE

DISPERSED

NON DISPERSED

FLUID SYSTEMS

SECONDARY

PRODUCTS

E

LU E LU

FI LU P

D D W

FO LO E B FI V LU E P

V

LU FI

TE

FI

FI SU LU FI

SU


ARPO

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APPLICATION GIUDE TO DRILLING FLUID PRODUCTS

X

X

X

X

X

X

X

X

EASY DRILL ECOL LUBE ENION

X X X

X X X

X X X

X X X

X X X

X X X

X X

ENVIRO SPOT ENVIRO THIN ENVIRO TORQ

X

X X X

X

X

X X X

X

X X X

X X X

E.P. LUBE E.P. MUDLUBE EZ-CORE

X X

X X

X X

X X

X X

X X

EZ-MUD EZ MUD DP EZ MUL-NT

X X

X X

X

X X

X X

X X

X X

EZ MUL-NTE FER-OX FERROCHROME

X

FIBERTEX FILTER-CHECK FILTREX

X X

B FI V

TE

FI

LU LU E

SU FI SU

SH SU

P TH LU

LU FI

LU LU E

X X X

SECONDARY

X

SECONDARY

X

PRIMARY

X

AIR AIRATED

X

OIL-BASE

X

WORKOVER

LOW SOLIDS

X

LIME-BASE

DRYOCIDE DURATONE HT DUROGEL

DISPERSED

POLYMER-BASE

NON-DISPERSED

FUNCTION

SALT SATURATED

FLUID SYSTEMS

PRODUCTS

V SH E

SH V SU

FI FI

E W TH

FI

E

LO FI FI

V TH

X X

X X

X X

X X

X X

X X

X X X

X X X

X

X X

X X X

X

X

X X X

FLAKE FLO-TROL FLO-VIS

X X X

X

X X X

X X X

X X X

X X X

X X

LO V V

FLOXIT FOAM-BLASTER

X X

X

X X

X X

X

X

FL D


= = = = = = = = = =


X


= = = = = = = = =

SH SU


ARPO

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X X X

X X

GEL TEMP GELTONE GELTONE II

X

X

X

X

X

X

X X

LIME-BASE

X X

X X

X X

X X

X X

X X

GL 1 DRILL LC GRANULAR HF 100-N

X X X

X X X

X X X

X X X

X X X

X X X

X

HOLECOAT H.T.P. IDBOND

X

X

X

X

X

X

X

IDBOND P IDBRIDGE CUSTOM IDBRIDGE L

X X X

IDBRINE P IDCAP IDCARB 75

X X

X

IDCARB 150 IDCARB CUSTOM IDCIDE L

X X X

IDCIDE P IDFAC IDF ANTIFOAM S


= = = = = = = = = =

X

X X

X

X

X X X

X X X

X X

X

X

X

X

X

X

X

X

X X X

X X X

X X X

X X X

X X X

X X X

X X

X

X

X

X

X

X

X

X

X

X

X

X

X

X


X X

X X


X X X

= = = = = = = = =

X

V V V

FL FI FI

V V V

SH FI

V SH SH

X

GELTONE III GEM-GP GEM-GP

SECONDARY

X X X

PRIMARY

X X

AIR AIRATED

X X

OIL-BASE

X X X

FUNCTIONS

WORKOVER

SALT SATURATED

LOW SOLIDS

GELEX GELITE GEL SUPREME

DISPERSED

POLYMER-BASE

NON- DISPERSED

FLUID SYSTEMS

SH LO SH SH FI SH

SECONDARY

PRODUCTS

TE

LU LU

FI

LU

FI

LU

FI

FI V

LU

SH FI FI

LO LO

CO SH W

A FI FI

FI FI B

LO LO

B SU D


W W

ARPO

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X X

IDF DRILL. DETERGENT IDF DV-68 IDF FLOPLEX

X X X

X

X

X

X

X

X

X

X X X

X

X

IDF FLR IDF FLR XL IDF GEL TEMP

X X X

X X X

X X

X X

X X

X X X

X X

IDF HI-FOAM 440 IDF HI-TEMP IDF HI-TEMP II

X X

X X

X X

X X

X X X

X

IDF HYMUL IDFILM 120 IDFILM 220X

X X X

X X X

X X X

X X X

X X X

X X X

X

IDF INSTAVIS IDF KWICKCLEAN IDFLO

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X X X

X

X

IDFLOC IDFLOC C IDFLO HTR

X

X

X

X

X X X

IDFLO LT IDF MUD FIBER IDF POLYLIG

X X X

X X X

X X X

X X X

X X X

X X X

IDF-POLYTEMP IDF PTS-100 IDF PTS-200

X X X

X

X X X

X X X

X X X

= = = = = = = = = =

X



E FL

V FI V

FI

FO FI FI

SU TH

SU CO CO

E

X

X X

V SU FI

X

FL FL FI

X X

X X

= = = = = = = = =

SU V FL

CO CO CO

X

IDFILM 520X IDFILM 620 IDFILM 820X


D LO

X

B FI

FI LO LO FI TE TE

TH A A


SECONDARY

X X

PRIMARY

X X

AIR AIRATED

X X

OIL-BASE

X X

WORKOVER

X X

LIME-BASE

IDF DEFOAMER IDF DI-PLUG

DISPERSED

LOW SOLIDS

SALT SATURATED

FUNCTION

POLYMER-BASE

NON DISPERSED

FLUID SYSTEM

SECONDARY

PRODUCTS

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IDF RHEOPOL IDF SAFEDRIL CONC. IDF SAFELUBE

X X X

X X

X

X

X

X

IDF SEAL IDF SM X IDF TRUDRILL S

X X X

X

X X

X X

X X

X

X

TE P P

A SU

FI SH LU

V LU D

X

LO V FI

IDF TRUFLO 100 IDF TRUFLO 100 IDF TRULOSS

X X X

FI FI FI

IDF TRUMUL IDF TRUPLEX IDF TRUVIS HT

X X X

E V V

IDF TRUVIS IDF ULTRADRIL OIL IDF VISPLEX

X X

V

X

IDHEC IDHEC L IDLUBE

X X X

X X X

X X X

X X X

X X X

X X X

IDMUL 80 IDPAC IDPAC XL

X X X

X X X

X X X

X X X

X X X

X X X

IDPLEX 100 IDPLEX K IDSCAV 110

X

X

X

X

X X X

IDSCAV 210

X

X

X

X

X


= = = = = = = = = =


V

X


X X X

V V LU E FI FI

X

X X X

SU SU CO

X

X

CO

= = = = = = = = =

FI

V


SECONDARY

X X X

X X X

PRIMARY

X X X

AIR AIRATED

X X X

WORKOVER

X X X

OIL-BASE

FUNCTION

SALT SATURATED

LIME-BASE

X X

LOW SOLIDS

X X X

POLYMER-BASE

IDF PTS-300 IDFREE IDFREE (UW)

DISPERSED

NON-DISPERSED

FLUID SYSTEM

SECONDARY

PRODUCT

FI

ARPO

IDENTIFICATION CODE

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X

X X

X

CO CO

X

IDSPERSE XT IDSURF IDTEX

X X

X X X

X X X

X X X

IDTEX W IDTHIN IDTHIN 500

X X X

X X X

X X X

X X

X

IDVIS IDVIS L IDWATE

X X X

X X X

X X X

X X X

X X X

X X X

X X X

IDZAC IDZAC L IMPERMEX

X X X

X X X

X X X

X X X

X X X

X

X

INTAMIX INTASOL INTERDRILL DEFLOC

X X

X X

X X

X X

X X

X X

X X X

X X X

X X

X

X

TH SU SH

FL

SH TH TH

FI FI FI

V V W

FI

FI

FI

CO CO FI

X X

LO LO TH

INTERDRILL EMUL INTERDRILL EMUL HT INTERDRILL ESX

X X X

E E E

FL TE

INTERDRILL FL INTERDRILL LO FL INTERDRILL LOMULL

X X X

FI FI E

E E V

INTERDRILL LO RM INTERDRILL NA INTERDRILL NA HT

X X X

V FI FI


= = = = = = = = = =

SECONDARY

PRIMARY

AIR AIRATED

OIL-BASE

X

FUNCTIONS

WORKOVER

X

SALT SATURATED

LOW SOLIDS

IDSCAV 310 IDSCAV 510 IDSCAV ES

POLYMER-BASE

LIME-BASE

DISPERSED

NON-DISPERSED

FLUID SYSTEMS

SECONDARY

PRODUCTS



X X

= = = = = = = = =


TE FI

ARPO

IDENTIFICATION CODE

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INTERDRILL OW INTERDRILL RM INTERDRILL S

X X X

SU V FI

INTERDRILL VISTONE INTERDRILL VIST. HT INTERSOLV H

X X

V V CA

X

X

K-17 K-52 KLA-CURE

X X

KLA-GARD KLEEN-UP K-LIG

X X

X

X

X

X

X X

X X

X X X

X X X

X X X

X

X

X

X X

X

X

X

X X

X

X X X

X X X

X

X X X X

X X X

X X X

X X

X X

LIGNOX LINTAX LIQUI-VIS NT

X

LO-WATE LUBE-106 LUBE-100

X X X

X X X

X X X

* Legend A B CA CO D E FI FL FO LO

= = = = = = = = = =

X X

X


X X

X

X

X

X X X

X X X

X X

X

X

X X X

X X

X X

X X X

X X

X X

TH

SH

FI

FI

SH

FI

E

LO V D

FI

FL

FI FI TH

TH TH FI

TH LO V

SH

W LU LU

FI

LO

SU

SH

TH SH SH SH SU TH

X

KWUIKSEAL KWUICK-THK LD-8 LIGCO LIGCON LIGNO-THIN

* E LO

X

INTERSOLV XFE INVERMUL-NTL JELFLAKE

barite solvent.


= = = = = = = = =

SECONDARY

PRIMARY

AIR AIREATED

OIL BASE

FUNCTIONS

WORKOVER

SALT SATURATED

LOW SOLIDS

POLYMER-BASE

DISPERSED

LIME BASE

NON DISPERSED

FLUID SYSTEMS

SECONDARY

PRODUCTS


ARPO

IDENTIFICATION CODE

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X X X

X X X

X X X

X

LUBRI-FILM LVO-69 MAGNA-FLUSH

X

X

X

X

X

X

X

MAGNE-SET MCAT MCAT-A

X X X

X

MD TM MELANEX T M-I BAR

X

X

LU LU LU

X

LU V

X

SECONDARY

X X X

PRIMARY

X X X

AIR AIREATED

X X X

OIL BASE

LOW SOLIDS

LUBE-153 LUBE 167 LUBRA BEADS

WORKOVER

POLYMER-BASE

SALT SATURATED

LIME-BASE

FUNCTIONS

DISPERSED

NON DISPERSED

FLUID SYSTEMS

SECONDARY

PRODUCT

SU

SH

V

FI

DT TH

DT FI

* X X X

X X X

X X X

X X X

X

X X X

X X X

X X X

X X X

X X X

MICA MICATEX M-I CEDAR FIBER

X X X

X X X

X X X

X X X

X X X

X X X

M-I GEL MIL-BAR MIL-BEN

X X X

X X X

X X X

X X

X X X

X X X

MIL-CEDAR FIBER MIL-CLEAN MIL-FIBER

X

X

X

X

X

X

X

X

X

X

X

X

X

LO SU LO

MIL-FLAKE MIL-FREE MIL-GARD

X X X

X X X

X X X

X X X

X X X

X X X

X X

LO P CO

MIL-GARD L MIL-GARD R MIL-GEL

X

X X X

X X X

X X

X X X

X X X

X

X X X X

X X X X

X X

LO SH SH DT TE W LO LO LO

X X

X

X X X

V W V

CO CO V

FI FI

FI

* FOR CLEANING UP WELL TUBULARS


= = = = = = = = = =



= = = = = = = = =


ARPO

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X

X

MIL-LUBE MIL-PAC MIL-PAC LV

X X X

X X X

X X

X X X

X X X

MIL-PAC T MILPARK CSI MILPARK MD

X X X

X X X

X X X

X X X

X X X

MILPARK SSI MIL-PLUG MIL-POLIMER 354

X X X

X X

X X

X X X

X X X

MIL-REZ MIL-SEAL MIL-SPOT 2

X X X

X X X

X X X

X X X

X X X

MIL-STARCH MIL-TEMP MIL-THIN

X X

X X X

X X

X X X

X

M-I LUBE M-I LUBE ENV M-I QUEBRACHO

X X X

X X X

X X X

X X X

X X X

X X X

M-I X II MY-LO-JEL N-DRILL

X X

X X

X X

X X

X X

X X

FI FI

X X X

LU FI FI

V

X

FI CO SU

X

X X

X

X

X X

X X X X

X

X

LU LU TH X

LO FI FI

V FI

TH

FI

E

FI

FI FI FI

NEW-DRILL NEW DRILL HP NEW-DRILL PLUS

= = = = = = = = = =

E

CO LO V

FI TE TH

X

X X

V

FI LO P

X

N-DRILL-O N-DRILL-HI N-DRILL-HT


AIR AEREATED

V TH

OIL BASE

SECONDARY

X

WORKOVER

SALT SATURATED

MIL-GEL NT MIL-KEM

FUNCTION

PRIMARY

X X

LOW SOLIDS

POLYMER-BASE

DISPERSED

LIME BASE

NON DISPERSED

FLUID SYSTEM

X X X


X X X

X X X

X X X

X X X


X X

= = = = = = = = =

SECONDARY

PRODUCT

SH SH SH


ARPO

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APPLICATION GUIDE TO DRILLING FLUID PRODUCTS PRODUCTS

FUNCTIONS

SECONDARY

E TH E

SU

NOVATEC-S NOVAWET NOXYGEN

X X

SU SU CO

E E

TH

FI

V

NF-2 NO-SULF NOVAMOD

X

X

X

X

X

X

X X X

X X X

X

X

X

X

X

X

TH FI V

X X

X

PRIMARY

X X X

X X X

OIL BASE

NOVAMUL NOVASOL NOVATEC-P

X X X

WORKOVER

I

NEW-THIN NEW-TROL NEW-VIS

LIME BASE

I

X

I CO V

DISPERSED

SECONDARY

AIR-AEREATED

SALT SATURATED

LOW SOLIDS

POLYMER BASE

NON DISPERSED

FLUID SYSTEMS

X

N-PLZ-X N-SQUEEZE N-VIS-O

SU

LO LO FI

N-VIS-HI N-VIS-P OIL FAZE BASE OIL FOS OMC OMC-42

X

X

X

X

V V E TH TH TH

FI

FI

X X

E E

X

OMNI COTE OMNI MIX OMNI MUL

X X X

X X X

TH E E

TH E E

OMNI PLEX OMNI TEC OMNI COTE

X X X

X X X

V E FI

V E FI

OXIGEN SCAVENGER


= = = = = = = = = =


FI

X

X

X

X

X


X

X

= = = = = = = = =

CO


V E

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APPLICATION GUIDE TO DRILLING FLUID PRODUCTS PRODUCTS

PRIMARY

SECONDARY

SECONDARY

AIR-AEREATED

WORKOVER

SH SH LU

E V LU

LU FI FI

LU FI FI

LU FI FI

X

FI

V

X

CA

X

P P TH

X X

X X

X X

X X

X X

PENETREX PERFLOW DIF PERFLOW 100

X

X

X

X

X X X

PERMA-LOSE HT PETROFREE PHOS

X

X

X

X

X

X

X

X

X

X

X

PIPE LAX PIPE LAX ENV POLYLIG

X X

X X X

X X X

X X X

X X X

X X X

X X X

X X X

X

X

X X

X

FI TH FI

TH FI

X

X X X

X X X

X X X

X X X

X X X

X X

FI TE TE

V TH TH

LO

RHEOPOL RHEOSTAR RHEOMATE RM-63 RV-310 SAFE-BLOCK

X

X X

FI FI LU

PAC-L PAC-R PARA-TEQ

PYROTROL Q-BROXIN RESINEX

X X

OIL BASE

FUNCTIONS

SALT SATURATED

LOW SOLIDS

POLYMER BASE

LIME BASE

DISPERSED

NON DISPERSED

FLUID SYSTEMS

X

X

X

X X X

SU V FI

FI

E V TH

FI FI TH

X

X X X

X X

X

X X X

X

X

SCALE-BAN SDI SHALE-BOND

X X X

X X X

X X X

X X X

X X X

X X X

X X



LU FI

RM FL FI

SALINEX SALT GEL SAPP

= = = = = = = = = =

X

X X

SAFE-KLEEN SAFE-LINK SAFE-TROL


X X X

= = = = = = = = =

CO D SH

SU LU


E TH

LU

ARPO

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RALLAPPLICATION GUIDE TO DRILLING FLUID PRODUCTS PRODUCTS

SM-(X) SOLUFLAKE SP-101

X X X

X X X

X X

X

X X X

X X

X X

AIR-AIREATED

FI SH

TH

V LO FI

SH LO SH

LO TE

TH TH SH

FI FI LU

E E E

LU SU SH

FI

X

SH TH LU D D LU

FI

E

FI

LU

X X

X X X

X X X

X X X

X X X

X X X

X X X

X X X

X X

X X

X

X

X

X

X

X

X

X X X X X X

X X X

X X X

X

X X

X

X

X

STABIL HOLE STABILITE STABILUBE

X X

STEARALL STEARALL LQD STICK-LESS

X X X

X X X

X X X

X X

SULF-X SUPER COL SURF COTE

X X

X

X

X

X X

X

X X

X X

X X

X X

X X

X X

X

V TH TH

TCS/30 THERMA-BUFF THERMA -CHEK

X X X

X X X

X X X

X X X

X X X

X X X

SU TE FI

THERMA-CHEK LV THERMA-THIN THERMA-THIN DP

X X X

X X X

X X X

X X X

X X X

X X X

FI TH TH

THERMA-VIS

X

X

X

X

X

= = = = = = = = = =



V

= = = = = = = = =

FI

CO V SU

SUSPENTONE TACKLE TANNATHIN


X

PRIMARY SH CO V

OIL-BASE

WORKOVER

SALT SATURATED

LOW SOLIDS X X

SECONDARY

X X

FUNCTIONS

SECONDARY

X X

POLYMER BASE

DISPERSED

SHALE-CHEK SI-1000 6-UP

SPERSENE SPERSENE CF STAPLEX

X X

LIME BASE

NON DISPERSED

FLUID SYSTEMS

FI


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130 OF 155


PRODUCTS

0

X

X

X

X

X

X X

X

X

X

X

X

X

TE SU FI

LU

PRIMARY P E TH

FI LU LU

X X

AIR-AIREATED

OIL-BASE

WORKOVER

X

SALT SATURATED

DISPERSED

X

SECONDARY

X

X

X X X

FUNCTIONS

SECONDARY

TRIMULSO ULTIMUL UNI-CAL

LOW SOLIDS

X X

POLYMER BASE

THERMPAC UL TORQ-TRIM 22 TORQ-TRIM II

LIME BASE

NON DISPERSED

FLUID SYSTEMS

TH

FI

X X

LO E

SU

TE

VERSADUAL VERSAGEL-HT VERSAGARD

X X X

SU V SU

E TE E

TH

VERSA-HRP VERSALIG VERSAMOD

X X X

V FI V

VERSAMUL VERSAPRO VERSA-SWA

X X X

E E SU

FI SU E

V TE

VERSATHIN VERSATRIM VERSATROLL

X X X

TH SU FI

E

VERSATROLL NS VERSAWET

X X

FI SU

UNI-CAL CF VEN-FYBER VERSACOAT


= = = = = = = = = =



= = = = = = = = =

E


TH

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131 OF 155


0


VG-69 VICTOGEL AF VICTOSAL

X X

X X

X X

X X

X X

X X

VISCO 83 VISCO SL VISCO XC/84

X X X

X X

X X

X X X

X X X

X X X

VISPLEX VISGEL WALLNUT SHELLS

X X

X X

X X

X X X

X X

X X X

X

X X X X X X

X X

X

X

W.O. DEFOAM WONDERSEAL XCD POLYMER

X X X

X X X

X X

X-CIDE 207 XP 20 X-TEND II

X

X X

X X


= = = = = = = = = =

X


V

X X X

SH FL SH

V SH V SH FL

X

X

X

V V LO

X X X

X X X

X

V V W

X X X

X X X

X

X X X

X X

D SH V

X X

X

X

X


= = = = = = = = =

B TE FL V V

SECONDARY

PRIMARY

X

V FI FI

X X

AIR AIRATED

OIL-BASE X

W.O. 21 W.O. 21L W.O. 30

X-VIS ZEOGEL

FUNCTIONS

WORKOVER

SALT SATURATED

LOW SOLIDS

POLYMER BASE

DISPERSED LIME BASE

NON DISPERSED

FLUID SYSTEMS

SECONDARY

PRODUCTS

FI FI

LU

FI

TH V

FI

FI


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10.

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0

DRILLING FLUID ANALYSIS The contents of this section comply with specification API RP 13B-1 dated June 1st, 1990.

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10.1

DRILLING FLUIDS

10.1.1

Density (Fluid Weight)

133 OF 155

0

Equipment Required: • Fluid balance • Pressurised balance o • Thermometer 0-105 C Calibration: • With fresh water at 21 C = 1kg/l Procedure: o

1) 2) 3) 4) 5) 6) 7)

Level with the instrument base. Fill the balance cup with the drilling fluid to be tested. Put on the cap and make sure some of the fluid is expelled through the hole. When using the pressurised balance, use pump to add fluid into the cup under pressure. Wash the fluid from outside of the balance. Place the balance on the support. Move the rider so that the bubble is on the centre. Read the density value at the side of the rider toward the support.

Result: • •

10.1.2

Report the density to the nearest 10gr (0.1lbs/gal). 3 The balance provides the reading in ft and the gradient in psi per 1,000ft depth.

Marsh Viscosity Equipment Required: • Marsh Funnel • Chronometer o • Thermometer 0-105 C Calibration: • With fresh water at 21 C, /4 gallon = 26(+/- 0.5) secs. Procedure: o

1) 2) 3) 4) 5)

1

Record the temperature of the sample. Keep the funnel upright. Close the orifice with a finger. Pour non-gelatinised fluid through the screen. Remove the finger and measure the number of seconds required for fluid to fill the 1 receiving vessel, commonly /4 gallon (946 cc).

Results: Viscosity is recorded in seconds. • •

1

API regulations indicate /4 gals (946). Eni-Agip generally specifies 1 litre (1,000cc).

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10.1.3

134 OF 155

0

Viscosity, Yield Point, Gel Strength • • •

• Apparent Viscosity • Plastic Viscosity • Yield Point Equipment Required:

Gels Strength K (Consistency Index) n (Flow Index)

• Rotational viscosimeter (Fann) (2) • Thermostatic cup Calibration:

(1)

• •

Chronometer o Thermometer 0-105 C

• With fluids of known viscosity (Silicon Oils) (3) • With a suitable mechanical calibration kit Procedure: 1) 2) 3) 4) 5) 6) 7) 8) 9) 10) 11) 12)

Record the fluid sample point. Place the sample in a suitable container. Place the rotor exactly at the scribed line. Record the temperature of the sample. With the rotor rotating at a speed of 600 RPM, wait for reading to become a steady value. Change to 300 RPM, and again wait for reading to reach a steady value. Stir the fluid at high speed for 10 secs. Allow the fluid to stand undisturbed for 10 secs. Shift to 3 RPM and record the maximum reading. Re-stir the fluid at high speed for 10 secs. Allow the fluid to stand undisturbed for 10 secs. At 3 RPM again, record the maximum reading.

Alternative Steps For Oil Based Fluids: 1) 2) 3) Results:

Place the fluid sample in the thermostatic cup. Place rotor exactly at the scribed line. (4) Adjust the thermostat to the pre-selected temperature , and record on the report.

Apparent Viscosity (cP) Plastic Viscosity (cP) Yield Point (lbs/100sqft) Gels Values (lbs/100sqft) at 10” and 10 n (Dimensionless) . n K (lbs S /100sqft)

= = = =

(Reading at 600rpm) /2 (Reading at 600rpm) - (Reading at 300RPM) (Reading at 300rpm) - (Plastic Viscosity) (Reading at 3rpm) after 10” and at 10’

= =

3.32 log of reading at 600rpm/Reading at 300rpm (Reading at 600rpm/1020)

Conversion Factors: 2

(1) (2) (3) (4)

/2 = lbs/100ft n 2 lbs* s /100ft *4.79 = 2 lbs100ft *0.48 = Preferably at six speeds. Must be used with oil based fluids Recommended if used at the rig site. o o 120 +/- 2 F, 150 +/-2 F.

2

+/- (g/100 cm ) n 2 (dyne*s /cm ) Pa (pascal)

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10.1.4

135 OF 155

0

API Filtrate Equipment Required: • Filter press with internal diameter of 3", filter area of 7.1 +/- 0.1 in • Paper filter, Whatman No 50 or S&S No 576 diameter 90mm • 30min timer • 10 or 25cc graduated cylinder Calibration:

2

• Verify the accuracy of the filter press manometer and filtrate area. Procedure: 1) 2) 3) 4) 5)

1

Pour the fluid into the dry filter press until it is /2 inch from the top. Place the cylinder at the filtrate exit. Apply a pressure of 100 +/- 5 psi for 30secs. After 30 ins, measure the volume of filtrate and release the pressure. Remove the paper from filter and wash the filter cake .

Result: • • • •

Record the fluid temperature at the start. Report the filtrate volume in cc. Report the thickness of the filter cake in ?/32". 2 If filtrate area is 3.5in , double the filtrate volume.

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10.1.5

136 OF 155

0

HPHT Filtrate Equipment Required: • • • • • •

2

A complete HP/HT filter press with a filter area of 3.5 or 7.1in ; CO2 source (not AOTE, only CO2) Paper filter, Whatman No 50 or S&S No 576 diameter 90mm Pressurised connection cell 30 min timer 25 or 50cc graduated cylinder

•

High speed stirring unit o

Procedure to Test at Max. Temperature of 300 F: 1) 2) 3) 4) 5) 6) 7) 8) 9) 10) 11) 12) 13) 14) 15) 16) 17) 18)

19)

o

Pre-heat the heating jacket to 10 F above the selected test temperature. Stir the fluid at a high speed for 10mins. 1 Fill the cell up to /2" from the top. Place filter paper. Complete the assemble of the cell. Place the cell into the heating jacket with both the top and bottom valves closed. Place the pressurised cell to collect the filtrate. Apply pressure of the top with not less than 100psi with valves closed. Open the top valve and apply a pressure to the fluid while heating it to the selected temperature. Note: Total time of heating should not exceed 1hr. When the sample pressure reaches the set temperature, increase the pressure of the top pressure to 600psi. Open the collector valve to start the filtration. Collect the filtrate for 30mins. o Maintain the pre-selected test temperature to within +/- 5 F. If back pressure increases over 100psi, reduce the pressure by draining some filtrate from the graduated cylinder. At the end of the test, close both valves of the filter press. Recover all the filtrate in the graduated cylinder. Bleed the pressure from both regulators. Allow sufficient time for the cell to cool before draining the internal pressure and open the cell.

Recover the cake and wash it with a gentle stream of water .

(6)

Results : • • •

• (6)

Record temperature and test pressure. Report the filtrate volume in cc. Report the thickness of the filter cake in ?/32". 2

If filtrate area is 3.5 ins , double the filtrate volume.

HP/HT filtrate is commonly carried out at 500psi (35atm) and at 300oF (149oC). It aims to evaluate the filtrate reducer performance at a temperature where most of the cellulose polymers degrade, thus allowing the use of appropriate filtrate reducers. As for oil based fluids, HP/HT filtrate represents an important index of emulsion stability.

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10.1.6

137 OF 155

0

Oil, Water, Solids Measurement Equipment Required: • • • • • • • Procedure: 1) 2) 3) 4) 5) 6) 7) 8) 9)

10 to 20cc retort (required accuracy +/- 5%) 10 or 20cc collection cylinder (required accuracy 0.1 and 0.2cc respectively) Fine steel wool Silicon grease Spatula with a blade shaped to fit inside the dimensions of the retort sample cup Defoamer Pipe cleaner Thoroughly check that retort is clean, dry and operating. Collect a sample of fluid filtered through a 20 mesh screen on the marsh funnel. If the fluid sample is aerated, add some defoamer to about 300cc of the fluid and slowly stir for 2-3 mins. Lubricate the threads. Fill the retort with fluid. Allow an overflow of the sample through the hole in the lid. Wipe the overflow from the sample cup and lid. Screw the retort cup onto the retort chamber by positioning a ring of steel wool into the chamber. Heat the retort and collect the fluid into the dry liquid receiver. Continue heating for 10mins after the last recovered fluid. Note: If the recovered fluid contains solids, the test must be repeated .

Results: Volume percent water Volume of oil: (7)

Volume percent solids (7)

=

100 (volume of water in the fluid)/volume of the sample

=

100 (volume of oil in the fluid)/volume of the sample

=

100 - (vol. percent water + vol. percent oil)

The solids percentage, as calculated above, is the difference between the volume of water and volume of oil and the total volume of the sample. The calculation does not make any difference between the solids and salts which may have been dissolved. To correct solids from NaCl, for every 10gr/l, deduct 0.3% from the solids calculated by means of the retort.

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10.2

WATER-BASED FLUIDS

10.2.1

Sand Content Estimate

138 OF 155

0

Equipment Required: •

A sand screen set consisting of a 200 mesh sieve of 2.5" diameter, a funnel to fit the screen, a glass measuring tube with indicated marks relating to the quantity of fluid and water to be reached. In addition, the tube must have graduations from 0% to 20% which immediately allows the reading of sand percentage .

Procedure: 1) 2) 3) 4)

Fill the glass measuring tube to the indicated mark with the fluid. Add water to relating mark. Close the tube and shake vigorously. Pour the mixture into the screen and discard the fluid. Repeat until the wash water passes through clear. 5) Wash the sand retained on the screen. 6) Fit the funnel on the screen. 7) Turn upside down the funnel and the screen onto the tube. 8) Wash the sand into the tube by collecting water and solids in the tube. 9) Allow sand to settle. 10) Read the percent by volume of the sand from the graduation . Results: • •

Report the sand contents of the fluid in percent by volume. Report where the fluid was caught.

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10.2.2

139 OF 155

0

pH Measurment Equipment Required: • pH paper test strips which permit estimation of pH to 0.5/0.2 units (9) • Glass-electrode pH meter • Buffet solutions according to the indications supplied with the instruments . Procedure: (8)

•

Using paper test strips: 1) Place a 2cm strip on the indicator paper on the surface of fluid. 2) Allow it to remain until the fluid has wetted the surface of the paper (+/-30"). 3) Compare the colour standards provided on the side of the strip with the test strip.

•

Glass-electrode pH meter. 1) Make the necessary adjustment to standardise the meter with the solutions (10) according to the directions supplied with the instrument . 2) Insert the electrode into the fluid contained in a beaker. 3) Stir the fluid around the electrode by rotating the beaker. 4) After the meter reading becomes constant, record the pH .

Results: •

(8) (9)

(10)

As for pH determination with paper test strips, record the fluid pH to the nearest 0.2/0.5 units. • As for pH determination with glass-electrode pH-meter, record pH to the nearest 0.1 unit. The paper strip method may not be reliable if salt concentration of the sample is high. The electrometric method is subject to error in solutions containing high concentrations of sodium ions, unless a special glass electrode is used. Suitable correction factors must be applied. For accurate pH readings, the test fluid, buffet solutions and reference electrode must all be at the same temperature.

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10.2.3

140 OF 155

0

Methylene Blue Capacity Determination Equipment Required: • • • • • • • Reagents:

1cc syringe. 250cc Erlenmeyer flask. 1cc Serological (graduated) pipette. 50cc graduated cylinder. Glass stirring rod. Hot plate. Paper filter, Whatman No. 1 or equivalent, 11cm in diameter .

• Methylene blue solution, 1cc = 0.01 milli-equivalents. • Hydrogen peroxide, 3% solution. • Sulphuric acid, 5N . Procedures: 1) 2) 3) 4) 5) 6) 7) 8) 9)

10) 11)

Place 1cc of fluid or more (or suitable volume to require 10cc of blue methylene) in the Erlenmeyer flask. Add 15cc of Hydrogen peroxide. Add 0.5cc of sulphuric acid. Stir. Boil for 10mins. Add blue methylene solution. After each addition of 0.5cc, swirl the content for about 30secs. Remove one drop of fluid with the glass stirring rod and place it on the filter paper. The end point is reached when the dye appears as a blue ring surrounding the dyed solids placed on the filter paper. When the situation as described in step 8 occurs, shake the flask for an additional 2mins and repeat step 7. If the ring is again evident, the end point has been reached. If the ring does not appear, repeat steps 6 and 7. Continue shaking the flask for 2mins until a drop shows the blue tint. Record the number of cc of blue used to reach the end step .

Results: Cation exchange capacity (CEC) MBT (Bentonite equivalent) in lbs/bbl MBT (Bentonite equivalent) in kg/m

3

=

cc of methylene/cc of fluid

=

CEC X 5

=

CEC X 14.25

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10.2.4

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0

Chloride Content Determination Equipment Required: • • • • Reagents:

1cc pipette. 1cc serological (graduated) pipette. 100-150cc beaker (or a white vessel). Glass stirring rod .

• • • • Procedure:

Silver nitrate solution with known titration. Potassium chromate indicator solution. Sulphuric acid: N/50. Phenolphthalein indicator solutions .

1) 2) 3) 4) 5) 6) 7) 8)

Place 1cc (or more) of filtrate into the beaker. Add 2 or 3 drops of phenolphthalein. If the indicator turns pink, add sulphuric acid drop by drop until the colour is discharged. dilute with 25-50cc of distilled water. Add 5-10 drops of potassium chromate. Titrate with the addition of silver nitrate until colour changes from yellow to orange/red and persists for 30secs. Record the number of cc of silver nitrate required to reach the end point. If over 10cc of silver nitrate are required to reach the end point, repeat the test with a smaller sample of filtrate .

Results: Chloride gr/l

=

NaCl gr/l

=

(11)

cc AgNO3 (normality of solutions) 35.453

/(cc of filtrate)

(12)

cc AgNO3 (Normality of solution) 58.443

/(cc of filtrate)

Solutions and Conversion Factors: Concentration of AgNO3 commonly required:

(11) (12)

•

0.1N

Chlorides (Cl-) gr/l Salt (NaCl) gr/l

= =

(cc AgO3 x 3.545) / (cc of filtrate) (cc AgNO3 x 5.844) / (cc of filtrate)

•

0.282N

Chlorides (Cl-) gr/l Salt (NaCl) gr/l

= =

10 x cc AgNO3 / (cc of filtrate) 10 x cc AgNO3 x 1.65 / (cc of filtrate)

•

0.0282 N

Chlorides (Cl-) gr/l Salt (NaCl) gr/L

= =

cc AgNO3 / (cc of filtrate) cc AgNO3 x 1.65 / (cc of filtrate)

PM Cl PM Cl

= =

PE Cl PE Cl

= =

35.45 58.443

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10.2.5

142 OF 155

0

Calcium Hardness Determination Equipment Required: • • • • • • • Reagents: • • • • • •

1cc pipette 1cc graduated pipette 1cc serological (graduated) pipette 100-150cc beaker Glass stirring rod *Two 10cc graduated pipettes *Hot plate 0.01 Molar EDTA solution Buffer solution, pH 10 Hardness indicator (Black Eriochrome T or similar) (13) Sodium Hypochlorite, solution at 5.25% (14) *Galcial acetic acid *pH paper strip (15 )

* equipment and reagents required if filtrate is coloured Procedure: 1) 2) 3) 4) 5)

Place 1 cc (or more) of filtrate into the beaker Dilute to 30-40 cc with distilled water Reach pH 10 with buffet solutions Add an adequate quantity of indicator Titrate with EDTA until colour changes from pink-red to light blue-blue.

Procedure for Filtrate Coloured 1) 2) 3) 4) 5) 6) 7)

(16)

:

Place 1cc of filtrate into the beaker. Add 10cc of sodium ipochlorite and mix. Add 1cc of acetic acid and mix. Boil for 5mins. Maintain the volume by adding distilled water. Verify if hypochlorite is totally discharged with the pH paper strip. If the paper strip becomes white, boil for longer. Cool the solution. Continue as indicated from step 3 in the normal procedure .

Results: Total hardness (gr/l Ca++) (13) (14) (15) (16)

=

cc 0.01 M EDTA x 0.4/cc of filtrate.

In the same cases, ipochlorite can be contaminated by calcium, verify. Avoid all contact with your skin. It is used only if coloured filtrate does not allow the evaluation of colour change. The analysis must be carried out in a well ventilated placed. Do not breathe in vapours.

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10.2.6

143 OF 155

0

Calcium And Magnesium Determination Equipment Required: • • • • • Reagents:

1cc pipette 5 cc graduated pipette 100-150cc beaker Glass stirring rod 10cc serological (graduated) pipette

• 0.01 Molar EDTA solution • Buffer solution: pH 10 • NaOH drops or solution • Total hardness indicator (Black Eriochrome T or similar ) Procedure for Determining Calcium: 1) 2) 3) 4) 5) 6) 7) 8)

Determine the total hardness as described in the related procedure. Record as ‘a’ the number of cc required. Place a volume of filtrate identical to that required for determining the total (17) hardness . Dilute to 30-40cc with distilled water. Increase pH to 12 by using NaOH. Add the calcium indicator (with calcine or calver II). Titrate with 0.01 M EDTA until colour changes from green to pink-brown in case of calcine, otherwise from pink to blue in case of Calver II. Record as ‘b’ the number of cc required .

Results:

(17)

‘b’

=

cc of EDTA required for calcium

Calcium (gr/l Ca++)

=

‘b’ x 0.04/cc of filtrate

‘a’ -’b’

=

cc of EDTA required for magnesium

Magnesium (gr/l Mg++)

=

‘a’ - ‘b’ x 0.243/cc of filtrate

Also in this case, coloured filtrates may be applied.

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10.2.7

144 OF 155

0

Alcalinity, Excess Lime, Pf, Mf, Pm Measurment Equipment Required: • • • • • • Reagents:

100-150cc pottery or plastic vessel 1cc pipette 2cc syringe 10cc graduated pipette Glass stirring rod 10 cc serological (graduated) pipette

• Sulphuric acid, N/50 (0.02 N) • Phenolphthalein indicator solution (18) • Methyl orange (or bromocresol blue) indicator solution Procedure: •

Pf 1) 2) 3) 4)

•

Mf 1) 2) 3)

•

Pm 1) 2) 3) 4)

5) Interpretation: •

• (18) (19) (20)

Place 1cc of filtrate into the vessel. Add 2-3 drops of phenolphthalein solution. If the indicator turns red, add sulphuric acid until the colour disappears (pH 8.3). Report as Pf the number of cc of N/50 sulphuric acid required. To the sample which has been titrate to the Pf end point, add 2-3 drops of methyl orange (or bromocresol blue). Titrate with N/50 sulphuric acid until colour changes (pH 4.3) from yellow to pink with methyl orange or from violet to yellow with bromocresol blue. Report as Mf the total of cc N/50 sulphuric acid required to reach phenolphthalein (Pf) end point, and methyl orange (Mf) end point. Place a syringe of 1cc of fluid into the vessel. Dilute the sample with 25-50cc of distilled water. Add 4-5 drops of phenolphthalein. If sample turns red, titrate by adding N/50 sulphuric acid until the colour disappears (Ph 8.3). Report as Pf the number of cc N/50 sulphuric acid required . (19)

Alkalinity Pf = 0 2Pf < Mf 2Pf = Mf 2Pf > Mf Pf = Mf

Excess lime:

mg/l of OH 0 0 0 340 (2Pf - Mf) 340Mf

CO3 HCO3 0 1220Pf 1200Pf 1200 (Mf-Pf) 0 3

kg/m lbs/bbl

= =

1220 Mf 1220 (Mf-2Pf) 0 0 0

0.742 x (Pm - Fw x PF) 0.26 X (Pm - Fw x PF)

(20)

It is required for deeply coloured filtrates and the colour will change from violet to yellow. Quantity can be measured with Garret Gas train. Fw represents the liquid fraction measured with a retort.

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10.2.8

145 OF 155

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Excess Gypsum Measurment Equipment Required: • • • • • • Reagents:

1cc pipette 5 cc graduated pipette 100-150cc beaker Calibrated floating-ball or graduated cylinder: 250 cc Glass stirring rod 10cc serological (graduated) pipette

• 0.01 Molar EDTA solution • NaOH drops or solution • Calcium indicator (with calcine or calver II ) Procedures: 1) 2) 3) 4) 5) 6) 7) 8) 9) 10) 11) 12) 13) 14) 15) Results:

(21)

Place 5cc of filtrate into the ball, dilute to 250cc with distilled water. Mix the solution for 15mins. Filtrate with an API standard filter press. Collect only clear filtrate. Place 10cc of filtrate obtained into the beaker. Increase pH to 12 by adding NaOH. Add calcium indicator (with calcine or calver II). Titrate with 0.01 M EDTA until colour changes from green to pink brown in case of calcine, or from pink to blue in case of calver II. Record the volume of EDTA required as ’Vt’. Place 1cc of filtrate into the vessel. Dilute with 30-40cc of distilled water. Increase pH to 12 by adding NaOH. Add calcium indicator (with calcine or calver II). Titrate with 0.01 M EDTA until colour changes. Record as ‘Vf’ the number of cc required .

•

Total gypsum

(lbs/bbl) 3 (kg/m )

= =

2.38 x (Vt) 6.78 x (Vt)

•

Excess gypsum

(lbs/bbl) (kg/m3)

= =

2.38 x (Vt) - 0.48 x (Vf x Fw) 6.78 x (Vt) - 1.37 x (Vf x Fw)

Fw represents the liquid fraction measured with a retort.

(21)

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10.2.9

146 OF 155

0

Semiquantitative Determination Of Sulphurs (Hatch Test) Equipment Required: • • • • Reagents:

The apparatus consists of a sample chamber provided with a holed cap for positioning the lead acetate paper disks Lead acetate paper disks 25cc graduated cylinder 5cc graduated syringe.

• Sulphuric acid, N/10 • Alkaseltzer (or sodium bicarbonate) • Defoamer. Procedures: 1) 2) 3) 4) 5) 6) 7) 8) 9)

(24)

Using the syringe take away 2.5cc of fluid filtrate . Place the sample into the chamber by diluting with 22.5cc of fresh water. Position a lead acetate paper disk on the top cap of the chamber. Wet the chamber walls with a film of defoamer. Add 1cc of N/10 sulphuric acid. (25) Place a tablet of Alkaseltzer (or a bit of sodium bicarbonate ). Screw the cap containing the lead acetate paper disk. Allow the tablet to be completely dissolved. Compare the colours of lead acetate paper disk with the hatch colour standards. If (25) colours are too dark, the test must be repeated with a diluted sample .

Results: •

(22) (23) (24) (25)

Results are compared against the hatch paper and be multiplied by 10. Values are in mg/l of H2S. Garret gas train can also be applied for quantitative evaluation. Complete gas kits are available. Soluble sulphurs are determined with filtrate analysis, while total sulphurs with fluid analysis. Coloration is altered if cement is present in fluid. In this case the test may result positive even in absence of H2S. Calculations of the concentration must be carried out on the dilutions made.

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10.2.10

147 OF 155

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Fluid Corrosivity Analysis

FLUID CORROSIVITY ANALYSIS EQUIPMENT • •

Corrosion rings pre-weight 4.5” (AISI 4140) Drill string

PROCEDURE • • • • • •

Insert a corrosion ring into the tool joint closest to the drill bit. Insert rings at halfway and at the top end of the drill string. To keep in situ at least 40 hrs and max. of 10 days. Recover the test pieces, dry them off with a cloth. Notice the original weight and serial number. For each corrosion ring, record : 1) 2) 3) 4) 5) 6)

Phase and depth of the ring. Seria number and original weight. Date and time of installation in the string Date and time of recovery Mud type, pH, Temperature in/out, flow rate. Description of any treatment with corrosion inhibitors.

Send the test pieces to and the report data to: Eni-Agip/Corm RESULT •

Speed corrosion

lbs/ft3/year

mm/year

Interpretation

<1

<0.6

Low

1-2

0.6 - 1.2

Moderate

2-5

1.2 - 3.1

High

>5

> 3.1

Severe

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10.3

OIL BASED FLUIDS

10.3.1

Electrical Stability Determination

0

Equipment Required: • • • • Procedure: 1) 2) 3) 4) 5) 6) 7) 8) 9) 10) 11)

Electrical stability meter, 0-200 volt range, optimum operating frequency of 330-350 hertz at 1500 volts, 61 microamps of current at emulsion break. Electrode probe with space of 1.59mm (0.061 in.) o o 0-150 C (32-220 F) thermometer Heating cup Glass or plastic beaker Place a sample of the filtrated fluid from the screen of the marsh funnel into the heating cup. o o Heat sample at 50 C (120 F). Put the sample into a plastic or glass container. Position the electrode probe into the fluid sample. Stir the sample with electrode probe for 15-30secs. Be sure that the electrode probe is completely covered by the sample. It must not touch the bottom or sides of the container. Push test button and start from zero by rotating the PO tentsionmeter clockwise with increments of 100-200 v/sec. (Most models start up automatically.) Record the ES value displayed on the readout device (which is lit at the passage of current). Record the reading and reset potentiometer. Clean the electrode probe with a tissue paper. Repeat test and evaluate accuracy. Re-stir the sample for 30secs and repeat from step 4 to step 9 .

Results: (27)

Electrical stability = 2 (reading of potentiometer) . (27) Some emulsion testers, i.e. Bariod’s testers, provide the value of electrical stability directionally.

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10.3.2

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0

Fluid Alkalinity Determination Equipment: • • • • Reagents:

Half litre glass jar with lid. 5cc syringe. 5cc graduated pipette. Magnetic stirrer with 38mm stirring bar (1.5in) .

• • • • Procedure:

Xilene/Hysopropanole mixture: 50/50. Distilled water. Phenolphthalein. Sulphuric acid: 0.1 regular (N/10) .

1) 2) 3) 4) 5) 6) 7) 8) 9) 10)

Add 100cc xilene/hysopropanole mixture to half litre jar. Add 2cc fluid with the syringe. Swirl the mixture until it is homogenous. Add 200cc distilled water. Add 15 drops of phenolphthalein. Slowly titrate with 0.1 N sulphuric acid, while stirring rapidly with magnetic stirrer. Titrate until red colour just disappears for 1min. Let the sample stand for 5mins, if no red colour re-appears, the end point has been reached. If colour reappears, titrate until it disappears again. Repeat steps 6,7,8. If a third titration is necessary, call the total value of acid the end point, even if the colour re-appears a fourth time .

Results: Fluid Alkalinity: Pom

=

cc 0.1N sulphuric acid/cc fluid sample.

Pom

=

cc 0.1N sulphuric acid/2.

Excess Lime: lbs/bbl kg/m

3

=

1.3 Pom.

=

3.7 Pom.

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10.3.3

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0

Fluid Chloride Determination Equipment Required: • • • • • Reagents:

Half litre glass jar with lid. 5cc syringe. 5cc graduated pipette. 10cc graduated pipette. Magnetic stirrer with 38mm stirring bar (1.5in) .

• • • • • • Procedure:

Xilene/Hysopropanole mixture, 50/50. Distilled water. Phenolphthalein. Sulphuric acid: 0.1 regular (N/10). Potassium chromate indicator. 0.282N silver nitrate .

1) 2) 3) 4) 5)

Lead the alkaline test as indicated in the previous form. Be sure acqueous solution pH is less than 7 by adding 1-2 drops of N/10 sulphuric acid. (28) Add 10 to 15 drops of potassium chromate indicator . (29) While stirring rapidly, slowly titrate with silver nitrate . When the pink salmon colour stabilises for at least 1min, then the end point has been reached .

Results: Fluid chloride (mg/l) Whole fluid chloride (mg/l) (28) (29)

(30) (31)

= =

(30)

1000 (cc AgNO3 * PM Cl-)/cc fluid sample required. (31) 10000 (cc AgNO3 0.282N )/2.

A further addition of potassium chromate may be required. Rapid stirring is required. It may be necessary, however that the stirring is stopped to allow separation of the two phases to occur. Pm Cl = PE Cl = 35.45. The normal 0.0282 N reagent is calculated as follows: 1cc AgNO3 equals 10g/l Cl.

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10.3.4

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0

Calcium Determination Equipment Required: • • • • • Reagents:

Half litre glass jar with lid; 5cc syringe 5cc graduated pipette 10cc graduated pipette Magnetic stirrer with 38mm stirring bar (1.5in )

• • • • • Procedure:

Xilene/Hysopropanole mixture, 50%/50% Distilled water 1N hydroxide sodium (NaOH) 1N Calcium indicator (Calver II) (32 ) 0.1M EDTA

1) 2) 3) 4) 5) 6) 7) 8) 9) 10) 11) 12) Results:

Add 100cc of 50/50 xilene/hysopropanol mixture. Add 2cc of fluid with syringe. Shake vigorously, until the mixture is homogeneous. Add 200cc distilled water. Add 3cc 1N NaOH. Add 0.1 - 0.25gr calcium indicator (Calver II). Shake vigorously for 2mins. Let the sample stand to allow the separation of the two phases to occur. If a reddish colour appears in the aqueous phase, calcium is present. Place the jar on the magnetic stirrer and drop in the stir bar. Titrate with 0.1 M EDTA. When the colour changes to blue-green, the end point has been reached. Record the number of cc of 0.1M EDTA required .

Fluid calcium (mg/l) sample Whole fluid calcium (mg/l) (32)

=

1000 (cc EDTA

*

Normal EDTA PMCa++)/cc of fluid

= 1000 (cc EDTA * 0.1 40/2cc = 4000 (cc EDTA) 2cc This EDTA solution is ten times more concentrated than the solution required for water based fluids.

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0

APPENDIX A - DRILLING FLUID CODING SYSTEM This coding system describes the Eni-Agip drilling fluid coding system currently in use and how the system can be used for further developments of drilling fluids. A.1.

CODE GROUPS There are three groups in the system: 1

• • •

2

3

The first grouping represents the base fluid, such as fresh water, sea water, diesel, etc. The base fluid must be included in the full code. The second grouping represents the base fluid system, such as lignosulfonate, gels, polymers, invert emulsion, etc. The base system again must be included. The third grouping describes the base system more precisely by providing further information: i.e. the water/oil ratio in an invert emulsion, the type of salt in a brine and underlining the specific treatment, such as addition of polymers, soltex, lignosulfonates. The third group is included only if relevant information is applicable.

If there is one or more special treatments, only the most significant of these will be included. For example, DS-IE 80 signifies a diesel base, invert emulsion drilling fluid, with a WO ratio of 80/20. If this drilling fluid is relaxed, the code would be DS-IE RF, as 'Relaxed Fluid' is to be considered a more significant characteristic than the W/O ratio.

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A.2.

153 OF 155

0

EXAMPLE CODING Consider the development of a drilling fluid, as follows: 1)

The code for sea water fluid with prehydrated bentonite is: SW

2)

During drilling, if the fluid is treated with light additions of lignosulfonate, its code will be: SW

3)

GE

LS

Again during drilling, the addition of lignosulfonate will characterise the fluid further and the code will be: SW

4)

GE

LS

Finally, if lubricants are added, the code will be: SW

GE

LU

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0

APPENDIX B - ABBREVIATIONS B.1.

AR

FLUID CODE ABBREVIATIONS

-

1

2

3

Base Fluid

Base System

Specific Treatment

Air

AR

-

Air

(- -) -

Non Specific

FW -

Fresh Water

AT

-

Aerated

CA

-

Calcium Carbonate

SW -

Sea Water

BR

-

Brine

CB

-

Calcium Bromide

BW -

Brine Water

CL

-

Chromelignin

CC

-

Calcium Chloride

DS

Diesel

CT

-

Cationic Polymers

CL

-

Chromelignin

-

LT

-

Low Toxicity Oil

DE

-

Modified Tannins (Desco)

KA

-

Potassium Acetate

EB

-

Ester

DF

-

Drilling Fluid

KB

-

Potassium Base (KOH)

OF

-

Poltolefine

GE

-

Bentonite-Base

KC

-

Potassium Chloride

UT

-

Olio Ultra LT

GG -

Guar Gum

KF

-

Potassium Formiate

GL

-

Glycol-Base

GL

-

Glycol-Base

GY

-

Gypsum-Base

LI

-

Lime

HT

-

High Temperature

LS

-

Lignosulfonate

IE

-

Invert Emulsion

LU

-

Lubricants

K2

-

Potassium Carbonate

NC

-

Sodium Chloride

KA

-

Potassium Acetate

NB

-

Sodium Bromide

KC

-

Potassium Chloride

PA

-

Polyanionic Pol.(PAC)

KF

-

Potassium Formiate

PN

-

Na Polyacrylates

LI

-

Lime-Base

PC

-

PHPA

LS

-

Lignosulfonate-Base

PK

-

Agipak (K-CMC/PAC)

LW

-

Low-Solids

PO

-

Generic Polymers (CMC)

-

NOTE:

MM -

Mud-Misting

RF

MR -

Morex-Base

RM -

Rheology Modifiers

Relaxed Filtrate

OB

-

Oil Base

RX

-

Ht Pol. Mixtures

PA

-

Polyanionic Pol.(PAC)

SX

-

Soltex

PC

-

PHPA

TA

-

Tannins

PK

-

Agipak (K-PAC, K-CMC)

XC

-

XCD Polymer

PO

-

Generic Polymers (CMC)

VB

-

Viscosity Base

ZB

-

Zinc Bromide

QU

-

Quebracho-Base

SF

-

Foam-Base

SS

-

Salt Saturated (NaCl)

XC

-

XCD Polymer

The oil/water ratio of a fluid with an oil numeric value, such as O/W = 70/30, will be expressed only by the first ratio, i.e. 70, omitting the later 30 ratio.

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B.2.

OTHER ABBREVIATIONS

AC

-

Antiscale

AF

-

Antifoam

B

-

Bactericide

C

-

Chelant

CC

-

Diesel

CI

-

Low Toxicity Oil

E

-

Ester

F

-

Poltolefine

FP

-

Olio Ultra LT

FR

-

Filtrate Reducer

LC

-

Loss Circulation Material

LU

-

Lubricant

P

-

Primary

pH

-

pH Control

S

-

Secondary

S

-

Solvent

SA

-

Suspension Agent

SH

-

Shale Stabiliser

SU

-

Surfactant

TH

-

Thinner

TR

-

Tracer

TS

-

Temperature Stability Agent

V

-

Viscofier

W

-

Weighting Material

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Drilling Fluids Operations Manual

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