Drilling Fluids Operations Manual
January 7, 2017 | Author: Carlos Perea | Category: N/A
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Description
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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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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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
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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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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
ENI S.p.A. Agip Division
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
ENI S.p.A. Agip Division
ENV.
CHARACTERISTICS OF THE SYSTEM
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
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A. Agip Division
REVISION STAP -P-1-M-6160
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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IDENTIFICATION CODE
PAGE
ENI S.p.A. Agip Division
REVISION STAP -P-1-M-6160
2.6
17 OF 155
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
8kg/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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IDENTIFICATION CODE
PAGE
ENI S.p.A. Agip Division
REVISION STAP -P-1-M-6160
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’.
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A. Agip Division
REVISION STAP -P-1-M-6160
0
AGIP CODE
DESCRIPTION OF THE SYSTEM
FW/SW-SS
SALT SATURATED FLUID
B
CUTTINGS
D4
Lubricant Properties
T2
COSTO
A
Density
B
Temperature
A
Solid-removal eq.
A
Re-use
Logistic Difference
B
Convertible
Maint. Difference
M
LGS Tolerance
A
Formation Inhibition
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)
CHARACTERISTICS OF THE DRILLING FLUID
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A. Agip Division
39 OF 155
REVISION STAP -P-1-M-6160
0
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
+
- PRETREAT WITH NaHCO3
+
- 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.
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A. Agip Division
REVISION STAP -P-1-M-6160
0
AGIP CODE
DESCRIPTION OF THE SYSTEM AGIPAK (KCMC)-BASE FLUID
FW-PK
ENV.
B
MUD
D1
Lubricant Properties
T1
CUTTINGS
A
COSTO
A
Density
M
Temperature
B
Solid-removal eq.
B
Re-use
Maint. Difference
B
Convertible
LGS Tolerance
M
Logistic Difference
Formation Inhibition
X
Cutting Inhibition
Dispersed
Non-Dispersed
CHARACTERISTICS OF THE SYSTEM
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.)
API Filtrate (cc/30')
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)
CHARACTERISTICS OF THE DRILLING FLUID
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A. Agip Division
41 OF 155
REVISION STAP -P-1-M-6160
0
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
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A. Agip Division
REVISION STAP -P-1-M-6160
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
Lubricant Properties
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.
CHARACTERISTICS OF THE SYSTEM
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
Electrical Stability (volt)
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')
API Filtrate (cc/30')
Gel 10' (gr/100cm2)
Gel 10" (gr/100cm2 )
Yield Point (gr/100cm2)
Plastic Visc. (cps)
Funnel V isc. (sec/qt)
Density (SG)
CHARACTERISTICS OF THE DRILLING FLUID
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IDENTIFICATION CODE
PAGE
ENI S.p.A. Agip Division
43 OF 155
REVISION STAP -P-1-M-6160
0
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
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A. Agip Division
REVISION STAP -P-1-M-6160
0
AGIP CODE
DESCRIPTION OF THE SYSTEM
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
CHARACTERISTICS OF THE SYSTEM
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
Electrical Stability (volt)
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')
API Filtrate (cc/30')
Gel 10'(gr/100cm 2)
Gel 10" (gr/100cm 2)
Yield Point (gr/100cm 2)
Plastic Visc. (cps)
Funnel Visc. (sec/qt)
Density (SG)
CHARACTERISTICS OF THE DRILLING FLUID
ARPO
IDENTIFICATION CODE
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ENI S.p.A. Agip Division
45 OF 155
REVISION STAP -P-1-M-6160
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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ENI S.p.A. Agip Division
REVISION STAP -P-1-M-6160
0
DESCRIPTION OF THE SYSTEM
AGIP CODE
LIME-BASE FLUIDS
FW/SW-LI
D4
B
B
B
Mud
T2
Cost
M
Lubricant Properties
Density
M
Temperature
B
Solids-removal Eq.
M
Re-use
Logistic Difference
A
Convertible
Maint. Difference
B
LGS Tolerance
Cutting Inhibition M
Formation Inhibition
Dispersed
Non-dispersed
Alternative Oil
X
Cutting
ENV.
CHARACTERISTICS OF THE SYSTEM
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
Electrical Stability (volt)
2.15
Excess Lime (kg/m3)
12
MBT(kg/m3 equiv.)
5
Ca (gr/l)
pH
10
Pf
API Filtrate (cc/30')
3
Pm
Gel 10'(gr/100cm 2)
1
Sand (% in vol)
Gel 10" (gr/100cm2)
4
Water (% in vol.)
Yield Point (gr/100cm 2)
8
Oil (% in vol.)
Plastic Visc. (cps)
38
Solids (% in vol.)
Funnel Visc. (sec/qt)
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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ENI S.p.A. Agip Division
REVISION STAP -P-1-M-6160
AGIP CODE
MOR-REX-BASE FLUID (KLM)
FW/SW-MR
ENV.
D4
B
Mud
T1
Cuttings
A
Cost
B
Lubricant Properties
A
Density
A
Temperature
Logistic Difference
A
Solids-removal Eq.
Maint. Difference
B
Re-use
LGS Tolerance
A
Convertible
Formation Inhibition
X
(X)
Cutting Inhibition
Dispersed
Non-dispersed
Alternative Oil
CHARACTERISTICS OF THE SYSTEM
LT oil
Diesel
Sea Water
Fresh Water
0
DESCRIPTION OF THE SYSTEM
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
Electrical Stability (volt)
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
API Filtrate (cc/30')
Gel 10" (gr/100cm 2)
4
Plastic Visc. (cps) 15
Funnel Visc. (sec/qt)
1.1 40
Density (SG)
Yield Point (gr/100cm 2)
CHARACTERISTICS OF THE DRILLING FLUID
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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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REVISION STAP -P-1-M-6160
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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REVISION STAP -P-1-M-6160
AGIP CODE
DIESEL INVERT EMULSION FLUID
DS-IE
ENV.
T4
Lubricant Properties
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
Formation Inhibition
Cutting Inhibition
X
Dispersed
Non-dispersed
Alternative Oil
CHARACTERISTICS OF THE SYSTEM
LT Oil
Diesel
Sea Water
0
DESCRIPTION OF THE SYSTEM
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 Filtrate (cc/30')
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.
Electrical Stability (volt)
Gel 10'(gr/100cm2 )
2
Mf
Gel 10" (gr/100cm2 )
5
Pf
Yield Point (gr/100cm2 )
15
Pom (cc H2SO4 N/10)
Plastic Visc. (cps)
40
pH
Funnel Visc. (sec/qt)
1.2
Sand (% in vol)
Density (SG)
CHARACTERISTICS OF THE DRILLING FLUID @ 120 °F
600 2000
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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
REVISION STAP -P-1-M-6160
0
)
AGIP CODE
DESCRIPTION OF THE SYSTEM
DS-IE-RF
DIESEL INVERT EMULSION, FILTRATE RELAXED FLUID
ENV.
M
D3
Lubricant Properties
Density
Temperature T4
A
Mud
A
Cuttings
B
Solid-removal Eq.
A
Re-use
M
Cost
A
Convertible
A
Logistic Difference
A
Maint. Difference
Formation Inhibition
X
LGS Tolerance
Cutting Inhibition
X
Dispersed
Non-dispersed
Alternative Oil
CHARACTERISTICS OF THE SYSTEM
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 Filtrate (cc/30')
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
Yield Point (gr/100cm2 )
15
Pom (cc H2SO4 N/10)
Plastic Visc. (cps)
40
pH
Funnel Visc. (sec/qt)
1.2
Sand (% in vol)
Density (SG)
CHARACTERISTICS OF THE DRILLING FLUID @ 120 °F
600 1000
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REVISION STAP -P-1-M-6160
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DESCRIPTION OF THE SYSTEM
AGIP CODE
100% DIESEL INVERT EMULSION FLUID
DS/LT-IE-100
ENV.
A
Mud
D5
Cuttings
T4
Cost
A
Lubricant Properties
Density
A
Temperature
A
Re-use
A
Convertible
M
Solids-removal Eq.
A
Logistic Difference
A
Maint. Difference
A
LGS Tolerance
Formation Inhibition
X
Cutting Inhibition
Dispersed
Non-dispersed
Alternative Oil
CHARACTERISTICS OF THE SYSTEM
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
Electrical Stability (volt)
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')
Yield Point (gr/100cm2 )
12
API Filtrate (cc/30')
Plastic Visc. (cps)
1.4
Funnel Visc. (sec/qt)
Density (SG)
CHARACTERISTICS OF THE DRILLING FLUID @ 120 °F
2000+
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PAGE
ENI S.p.A. Agip Division
REVISION STAP -P-1-M-6160
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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ENI S.p.A. Agip Division
REVISION STAP -P-1-M-6160
AGIP CODE
POTASSIUM CARBONATE-BASE FLUID
FW-K2
ENV.
Mud
D3
B
B
0
30
B
Cost
Cuttings
Lubricant Properties
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
Formation Inhibition
Cutting Inhibition
Dispersed
X
LGS Tolerance
X
Non-dispersed
LT Oil
Alternative Oil
CHARACTERISTICS OF THE SYSTEM
Diesel
Sea Water
0
DESCRIPTION OF THE SYSTEM
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
Electrical Stability (volt)
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')
Funnel Visc. (sec/qt)
1.1
API Filtrate (cc/30')
Density (SG)
Yield Point (gr/100cm 2)
CHARACTERISTICS OF THE DRILLING FLUID
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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 +
- 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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PAGE
ENI S.p.A. Agip Division
REVISION STAP -P-1-M-6160
0
DESCRIPTION OF THE SYSTEM
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
Lubricant Properties
Logistic Difference
M
Density
Maint. Difference
M
Temperature
LGS Tolerance
A
Solids-removal Eq.
Formation Inhibition
(X)
Re-use
Cutting Inhibition
X
Convertible
Dispersed
X
Non-dispersed
Alternative Oil
CHARACTERISTICS OF THE SYSTEM
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
Electrical Stability (volt)
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')
API Filtrate (cc/30')
Gel 10'(gr/100cm2 )
Gel 10" (gr/100cm 2)
Yield Point (gr/100cm2 )
Plastic Visc. (cps)
Funnel Visc. (sec/qt)
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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ENI S.p.A. Agip Division
REVISION STAP -P-1-M-6160
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
Lubricant Properties
B
Re-use
B
Convertible
Formation Inhibition
B
Logistic Difference
Cutting Inhibition
X
Maint. Tolerance
Dispersed
X
LGS Tolerance
Non-Dispersed
Alternative Oil
CHARACTERISTICS OF THE SYSTEM
LT Oil
Sea Water
Diesel
Fresh Water
X
0
DESCRIPTION OF THE SYSTEM
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
Electrical Stability (volt)
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.)
API Filtrate (cc/30')
5
Oil (% in vol.)
Gel 10'(gr/100cm 2)
1
Solids (% in vol.)
Gel 10" (gr/100cm 2)
4
Plastic Visc. (cps) 10
Funnel Visc. (sec/qt)
1.1 38
Density (SG)
Yield Point (gr/100cm2)
CHARACTERISTICS OF THE DRILLING FLUID
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REVISION STAP -P-1-M-6160
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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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
Lubricant Properties
A
Density
A
Maint. Tolerance
LGS Tolerance
Formation Inhibition M
Temperature
A
Solids-removal Eq.
X
X
Cutting Inhibition
Dispersed
Non-dispersed
Alternative Oil
CHARACTERISTICS OF THE SYSTEM
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
Electrical Stability (volt)
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
API Filtrate (cc/30')
2
Pf
Gel 10'(gr/100cm 2)
1
Pm
Gel 10" (gr/100cm 2)
2
pH
Yield Point (gr/100cm 2)
10
Sand (% in vol)
Plastic Visc. (cps)
45
Water (% in vol.)
Funnel Visc. (sec/qt)
1.1
Oil (% in vol.)
Density (SG)
CHARACTERISTICS OF THE DRILLING FLUID
(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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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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REVISION STAP -P-1-M-6160
0
DESCRIPTION OF THE SYSTEM
CODICE AGIP
GLYCOL-BASE FLUID
FW/SW-GL
ENV.
Cutting
Mud
T2
Cost
A
Lubricant Properties
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
CHARACTERISTICS OF THE SYSTEM
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
Electrical Stability (volt)
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')
API Filtrate (cc/30')
Gel 10'(gr/100cm2 )
Gel 10" (gr/100cm2 )
Yield Point (gr/100cm2 )
Plastic Visc. (cps)
Funnel Visc. (sec/qt)
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
+
- PRETREAT WITH NaHCO3
+
- 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.
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REVISION STAP -P-1-M-6160
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DESCRIPTION OF THE SYSTEM
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
Lubricant Properties
Density
Temperature
Solids-removal Eq.
Re-use
Convertible
Logistic Difference
Maint. Tolerance
LGS Tolerance
Formation Inhibition
Cutting Inhibition
Dispersed
Non-dispersed
LT Oil
Alternative Oil
A
X
Cuttings
ENV.
CHARACTERISTICS OF THE SYSTEM
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
Electrical Stability (volt)
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
API Filtrate (cc/30')
Gel 10" (gr/100cm 2)
15
Plastic Visc. (cps)
40
Funnel Visc. (sec/qt)
1.2
Density (SG)
Yield Point (gr/100cm 2)
CHARACTERISTICS OF THE DRILLING FLUID @ 120 °F
600 1500
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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
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REVISION STAP -P-1-M-6160
0
DESCRIPTION OF THE SYSTEM
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
Lubricant Properties
Density
Temperature
Solids-removal Eq.
Re-use
Convertible
Logistic Difference
Maint. Tolerance
LGS Tolerance
Formation Inhibition
Cutting Inhibition
Dispersed
Non-dispersed
Alternative Oil
CHARACTERISTICS OF THE SYSTEM
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
Electrical Stability (volt)
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
API Filtrate (cc/30')
Gel 10" (gr/100cm2 )
10
Plastic Visc. (cps) 40
Funnel Visc. (sec/qt)
1.45 +/-
Density (SG)
Yield Point (gr/100cm2 )
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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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 %.
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REVISION STAP -P-1-M-6160
0
DESCRIPTION OF THE SYSTEM
AGIP CODE
INVERT EMULSION, ESTER-BASE FLUID
EB-IE ENV.
Mud
D3
Cuttings
T2
Cost
M
Lubricant Properties
A
Density
B
Temperature
A
Solid-removal Eq.
M
Re-use
Logistic Difference
A
Convertible
Maint Diffrence
A
LGS Tolerance
A
X
Formation Inhibition
Cutting Inhibition
Dispersed
Non-dispersed
Alternative Oil
CHARACTERISTICS OF THE SYSTEM
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
Electrical Stability (volt)
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')
Yield Point (gr/100cm2)
35
API Filtrate (cc/30')
Plastic Visc. (cps)
Funnel Visc. (sec/qt)
Density (SG)
CHARACTERISTICS OF THE DRILLING FLUID @ 120 °F
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.
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ENI S.p.A. Agip Division
REVISION STAP -P-1-M-6160
0
AGIP CODE
DESCRIPTION OF THE SYSTEM
PO-IE
INVERT EMULSION, POLIOLEFINE-BASE FLUID
ENV.
M
A
B
A
A
T3
D4
A
Cost
Lubricant Properties
Density
Temperature
Solids-removal Eq.
Re-use
Convertible
Logistic Difference
Maint. Tolerance
LGS Tolerance A
AA
Mud
A
Cuttings
A
X
Formation Inhibition
Cutting Inhibition
Dispersed
LT Oil
Alternative Oil
Non-dispersed
CHARACTERISTICS OF THE SYSTEM
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:
Electrical Stability (volt)
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
API Filtrate (cc/30')
Gel 10" (gr/100cm2)
30
Yield Point (gr/100cm2 )
1.32 +/-
Plastic Visc. (cps)
Funnel Visc. (sec/qt)
Density(SG)
CHARACTERISTICS OF THE DRILLING FLUID @ 120 °F
m3/h
Kg-l/m3 580 275 15 6 17 6 AS NEEDED AS NEEDED
15 + WEIGHTING TIME
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REVISION STAP -P-1-M-6160
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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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.
MAINTENANCE PROBLEMS OF WATER-BASE FLUIDS
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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
ENI S.p.A. Agip Division
+
+
+
YIELD
+
OTHER
MAINTENANCE PROBLEMS OF WATER-BASE FLUIDS
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REVISION
0
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REVISION STAP -P-1-M-6160
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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ENI S.p.A. Agip Division
REVISION STAP -P-1-M-6160
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
Pre-treatment 3 30kg/m
Pre-treatment 3 30kg/m
Pre-treatment 3 30kg/m
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
Pre-treatment 3 5-8kg/m
Pre-treatment 3 4-8kg/m
Pre-treatment 3 5-8kg/m
Pre-treatment 3 6-9kg/m
Coat-RD
IDZAC L
SV-120
20gr/1grH2S
13gr/1grH2S
13gr/1grH2S
Pre-treatment 3 5-10kg/m
Pre-treatment 3 14-29kg/m
Pre-treatment 3 3-6kg/m
IDZAC L
Fer-Ox
*Zinc Chelate (powder)
Zinc Oxide (Polvere)
Zinc Mixture
Milgard R
8gr/1grH2S
19gr/1grH2S
Pre-treatment 3 14-23kg/m
Pre-treatment 3 23-24kg/m
Oxide Zinc
Sulf-X
2.3gr/1grH2S
2.3gr/1grH2S
Pre-treatment 3 3-6kg/m
Pre-treatment 3 3-6kg/m
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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REVISION STAP -P-1-M-6160
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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PAGE
ENI S.p.A. Agip Division
80 OF 155
REVISION STAP -P-1-M-6160
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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REVISION STAP -P-1-M-6160
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
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ENI S.p.A. Agip Division
REVISION STAP -P-1-M-6160
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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REVISION STAP -P-1-M-6160
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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REVISION STAP -P-1-M-6160
5.
84 OF 155
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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IDENTIFICATION CODE
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ENI S.p.A. Agip Division
REVISION STAP -P-1-M-6160
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 (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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ENI S.p.A. Agip Division
REVISION STAP -P-1-M-6160
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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IDENTIFICATION CODE
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ENI S.p.A. Agip Division
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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ENI S.p.A. Agip Division
REVISION STAP -P-1-M-6160
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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REVISION STAP -P-1-M-6160
7.
101 OF 155
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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REVISION STAP -P-1-M-6160
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
STUCK PIPE PARAMETERS
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/PREVENTIVE ACTIONS
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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STUCK PIPE PARAMETERS
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/PREVENTIVE ACTIONS
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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REVISION STAP -P-1-M-6160
8.
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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.
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REVISION STAP -P-1-M-6160
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
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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
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REVISION STAP -P-1-M-6160
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
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REVISION STAP -P-1-M-6160
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
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REVISION STAP -P-1-M-6160
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
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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
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REVISION STAP -P-1-M-6160
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
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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.
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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
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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
Alkaline Agent Bactericide Ca Precipitant Corrosion Inhibitor Defoamer Emusifier Filtrate Reducer Flocculant Foamer Loss Control Agent
LU P PA SH SU TE TH V W
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
Legend A B CA CO D E FI FL FO LO
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
Lubricant Pipe Freeing Agent Polar Activator Shale Inhibitor Surfactant HT Stabilising Agent Thinner Viscofier Weighting Agent
A
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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
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
LU P PA SH SU TE TH V W
= = = = = = = = =
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
Lubricant Pipe Freeing Agent Polar Activator Shale Inhibitor Surfactant HT Stabilising Agent Thinner Viscofier Weighting Agent
FI
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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
Legend A B CA CO D E FI FL FO LO
= = = = = = = = = =
X
X
X
X X X X
SH X
Alkaline Agent Bactericide Ca Precipitant Corrosion Inhibitor Defoamer Emusifier Filtrate Reducer Flocculant Foamer Loss Control Agent
LU P PA SH SU TE TH V W
= = = = = = = = =
SECONDARY
PRIMARY
AIR AIRATED
OIL-BASE
FUNCTIONS
WORKOVER
SALT SATUR.
LOW SOLIDS
POLYMER-BASE
LIME-BASE
DISPERSED
NON DISPERSED
FLUID SYSTEMS
SECONDARY
PRODUCT
LU
Lubricant Pipe Freeing Agent Polar Activator Shale Inhibitor Surfactant HT Stabilising Agent Thinner Viscofier Weighting Agent
LO
TE TE
TH FI
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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
Legend A B CA CO D E FI FL FO LO
= = = = = = = = = =
X
Alkaline Agent Bactericide Ca Precipitant Corrosion Inhibitor Defoamer Emusifier Filtrate Reducer Flocculant Foamer Loss Control Agent
LU P PA SH SU TE TH V W
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
Lubricant Pipe Freeing Agent Polar Activator Shale Inhibitor Surfactant HT Stabilising Agent Thinner Viscofier Weighting Agent
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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
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
= = = = = = = = =
SH SU
Lubricant Pipe Freeing Agent Polar Activator Shale Inhibitor Surfactant HT Stabilising Agent Thinner Viscofier Weighting Agent
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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
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 X
X X X
X X X
X X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Alkaline Agent Bactericide Ca Precipitant Corrosion Inhibitor Defoamer Emusifier Filtrate Reducer Flocculant Foamer Loss Control Agent
X X
X X
LU P PA SH SU TE TH V W
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
Lubricant Pipe Freeing Agent Polar Activator Shale Inhibitor Surfactant HT Stabilising Agent Thinner Viscofier Weighting Agent
W W
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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
Alkaline Agent Bactericide Ca Precipitant Corrosion Inhibitor Defoamer Emusifier Filtrate Reducer Flocculant Foamer Loss Control Agent
LU P PA SH SU TE TH V W
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
Legend A B CA CO D E FI FL FO LO
D LO
X
B FI
FI LO LO FI TE TE
TH A A
Lubricant Pipe Freeing Agent Polar Activator Shale Inhibitor Surfactant HT Stabilising Agent Thinner Viscofier Weighting Agent
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
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
V
X
LU P PA SH SU TE TH V W
X X X
V V LU E FI FI
X
X X X
SU SU CO
X
X
CO
= = = = = = = = =
FI
V
Lubricant Pipe Freeing Agent Polar Activator Shale Inhibitor Surfactant HT Stabilising Agent Thinner Viscofier Weighting Agent
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
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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
Legend A B CA CO D E FI FL FO LO
= = = = = = = = = =
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
Alkaline Agent Bactericide Ca Precipitant Corrosion Inhibitor Defoamer Emusifier Filtrate Reducer Flocculant Foamer Loss Control Agent
LU P PA SH SU TE TH V W
X X
= = = = = = = = =
Lubricant Pipe Freeing Agent Polar Activator Shale Inhibitor Surfactant HT Stabilising Agent Thinner Viscofier Weighting Agent
TE FI
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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
Alkaline Agent Bactericide Ca Precipitant Corrosion Inhibitor Defoamer Emusifier Filtrate Reducer Flocculant Foamer Loss Control Agent
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.
LU P PA SH SU TE TH V W
= = = = = = = = =
SECONDARY
PRIMARY
AIR AIREATED
OIL BASE
FUNCTIONS
WORKOVER
SALT SATURATED
LOW SOLIDS
POLYMER-BASE
DISPERSED
LIME BASE
NON DISPERSED
FLUID SYSTEMS
SECONDARY
PRODUCTS
Lubricant Pipe Freeing Agent Polar Activator Shale Inhibitor Surfactant HT Stabilising Agent Thinner Viscofier Weighting Agent
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
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
LU P PA SH SU TE TH V W
= = = = = = = = =
Lubricant Pipe Freeing Agent Polar Activator Shale Inhibitor Surfactant HT Stabilising Agent Thinner Viscofier Weighting Agent
ARPO
IDENTIFICATION CODE
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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
Legend A B CA CO D E FI FL FO LO
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
Alkaline Agent Bactericide Ca Precipitant Corrosion Inhibitor Defoamer Emusifier Filtrate Reducer Flocculant Foamer Loss Control Agent
X X X
X X X
X X X
X X X
LU P PA SH SU TE TH V W
X X
= = = = = = = = =
SECONDARY
PRODUCT
SH SH SH
Lubricant Pipe Freeing Agent Polar Activator Shale Inhibitor Surfactant HT Stabilising Agent Thinner Viscofier Weighting Agent
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IDENTIFICATION CODE
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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
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
FI
X
X
X
X
X
LU P PA SH SU TE TH V W
X
X
= = = = = = = = =
CO
Lubricant Pipe Freeing Agent Polar Activator Shale Inhibitor Surfactant HT Stabilising Agent Thinner Viscofier Weighting Agent
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
Alkaline Agent Bactericide Ca Precipitant Corrosion Inhibitor Defoamer Emusifier Filtrate Reducer Flocculant Foamer Loss Control Agent
LU P PA SH SU TE TH V W
LU FI
RM FL FI
SALINEX SALT GEL SAPP
= = = = = = = = = =
X
X X
SAFE-KLEEN SAFE-LINK SAFE-TROL
Legend A B CA CO D E FI FL FO LO
X X X
= = = = = = = = =
CO D SH
SU LU
Lubricant Pipe Freeing Agent Polar Activator Shale Inhibitor Surfactant HT Stabilising Agent Thinner Viscofier Weighting Agent
E TH
LU
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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
= = = = = = = = = =
Alkaline Agent Bactericide Ca Precipitant Corrosion Inhibitor Defoamer Emusifier Filtrate Reducer Flocculant Foamer Loss Control Agent
LU P PA SH SU TE TH V W
V
= = = = = = = = =
FI
CO V SU
SUSPENTONE TACKLE TANNATHIN
Legend A B CA CO D E FI FL FO LO
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
Lubricant Pipe Freeing Agent Polar Activator Shale Inhibitor Surfactant HT Stabilising Agent Thinner Viscofier Weighting Agent
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REVISION STAP -P-1-M-6160
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
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
LU P PA SH SU TE TH V W
= = = = = = = = =
E
Lubricant Pipe Freeing Agent Polar Activator Shale Inhibitor Surfactant HT Stabilising Agent Thinner Viscofier Weighting Agent
TH
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APPLICATION GUIDE TO DRILLING FLUID PRODUCTS
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
Legend A B CA CO D E FI FL FO LO
= = = = = = = = = =
X
Alkaline Agent Bactericide Ca Precipitant Corrosion Inhibitor Defoamer Emusifier Filtrate Reducer Flocculant Foamer Loss Control Agent
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
LU P PA SH SU TE TH V W
= = = = = = = = =
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
Lubricant Pipe Freeing Agent Polar Activator Shale Inhibitor Surfactant HT Stabilising Agent Thinner Viscofier Weighting Agent
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REVISION STAP -P-1-M-6160
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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REVISION STAP -P-1-M-6160
10.1
DRILLING FLUIDS
10.1.1
Density (Fluid Weight)
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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
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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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REVISION STAP -P-1-M-6160
10.1.4
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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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REVISION STAP -P-1-M-6160
10.1.5
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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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REVISION STAP -P-1-M-6160
10.1.6
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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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ENI S.p.A. Agip Division
REVISION STAP -P-1-M-6160
10.2
WATER-BASED FLUIDS
10.2.1
Sand Content Estimate
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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
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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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ENI S.p.A. Agip Division
REVISION STAP -P-1-M-6160
10.2.3
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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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REVISION STAP -P-1-M-6160
10.2.4
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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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REVISION STAP -P-1-M-6160
10.2.5
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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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REVISION STAP -P-1-M-6160
10.2.6
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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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REVISION STAP -P-1-M-6160
10.2.7
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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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ENI S.p.A. Agip Division
REVISION STAP -P-1-M-6160
10.2.8
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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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REVISION STAP -P-1-M-6160
10.2.9
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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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REVISION STAP -P-1-M-6160
10.2.10
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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
3.1
Severe
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REVISION STAP -P-1-M-6160
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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REVISION STAP -P-1-M-6160
10.3.2
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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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ENI S.p.A. Agip Division
REVISION STAP -P-1-M-6160
10.3.3
150 OF 155
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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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ENI S.p.A. Agip Division
REVISION STAP -P-1-M-6160
10.3.4
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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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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.
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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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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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IDENTIFICATION CODE
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ENI S.p.A. Agip Division
REVISION STAP -P-1-M-6160
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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