Drilling Fluids Operations Manual - Eni-Agip

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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1.2
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0
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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2)
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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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Agip Division
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3)
4)
5)
6)
1.3
8 OF 155
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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Agip Division
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2.
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GUIDE TO DRILLING FLUID PROGRAMMING
This section is integrated with the following sub sections and covers all the various types
of drilling fluids.
GATHER
INFORMATION AS PER FLOW CHART
SECTION
IDENTIFY
THE TYPE(S) OF FLUID AS PER CHARTS
AT SECTION
VERIFY
THE FEASIBILITY CHARACTERISTICS OF
THE SYSTEM AT SECTION
CHECK
THE CHOICE MADE FROM THE
DESCRIPTION OF FLUIDS IN DOCUMENTS
DEFINE
THE CHARACTERISTICS OF FLUIDS AS
PER CHARTS
The Eni-Agip codes are fully described in Appendix A.
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2.1
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0
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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0
AVA
Bariod
Dowell
MI
BH Inteq
AVA Spud
Mud
FW+Gel Pills
FW+Gel Pills
FW+Gel Pills
FW+Gel Pills
FW-GE+SW
SW Spud
Mud
SW+H.VIS
Pills
SW+H.VIS
Pills
SW+H.VIS
Pills
SW-GG
AVAGUM
LO-LOSS
SM(X)
LO-LOSS
LO-LOSS
SW+H.VIS
Pills
Circulating, Start-Up Drilling Fluids
Fresh Water
FW-GE
AVAGEL
Spud Mud
Spud Mud
Spud Mud
Spud Mud
Seawater
SW-GE
AVAGEL
Prehydrated
Gel
Prehydrated
Gel
Prehydrated
Gel
Prehydrated
Gel
2.2.3
Drilling Formations With Gradients Less Than 1.0kg/cm2/10m
Aerated
FW/SW-AT
Foam Base
FW-SF
Mixed
AR-MM
Air/FoamBase
AR-SF
Air-Base
AR-AR
2.2.4
Drilling Fluids For Non-Reactive Formations
2
With Gradient Between 1.03 - 1.5kg/cm /10m
BentoniteBase
FW/SWGE-PO
AVAGELPOL
Gel/Polymer
Gel/Polymer
Gel/Polymer
FW/SW-LS
AVAFLUID
Q-BROXIN
FCL Muds
Spersene
UNI-CAL
GELEX
Systems
Low-Solid/
BENEX
Spersene /XP20
UNICAL/
LIGCO
Desco
Desco
FW-LW
AVABEX
X-TEND II
Gel/Polymer
2
With Gradient > 1.5kg/ cm /10m
BentoniteBase
FW/SW-LSCL
FW/SW-TA
AVA
Fluid/LIG
Q-Broxin
/CC16
FCL/CL
Desco
Desco
Desco
o
With Gradient >1.5 High Temperature (+/- 150-200 C)
BentoniteBase
Oil-Base
FW/SWCL-RX
AVAREX
FW/SWCL-PC
+POLICELL
ACR
DS-IE
AVOIL
OC16/DUREN
FCL/CL/HITEMP
SPER/XP20/R
ESINEX
+THERMACHECK
+POLYTEMP
+POLY RX
Invermul
Interdril
Versadril
LIGCO/CHEM
TRO-X
+PYROTROL
Carbodril
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2.2.5
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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.
ARPO
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
8<pH<12+; Value 8 min. helps reduce corrosion. The other values depend
upon the fluid system chosen.
Chemical
Characteristics
Dependent on the
drilling fluid chosen.
Compatible to the fluids
and shales of the
reservoir.
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
18 OF 155
REVISION
STAP -P-1-M-6160
2.7
WATER-BASED FLUIDS
2.7.1
Optimum Values Of Marsh Viscosity, Solids And Gel
0
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
2.7.2
19 OF 155
Optimum Values Of Plastic Viscosity And Yeld Point
0
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
20 OF 155
REVISION
STAP -P-1-M-6160
3.
FLUID CHARACTERISTICS
3.1
NON-INHIBITIVE WATER BASED FLUIDS
0
This section contains descriptions of the various water based drilling fluids, their
applications and limitations.
The Eni-Agip codes, abbreviations and symbols used in this section are listed in Appendix
A and Appendix B.
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
0
DESCRIPTION OF THE SYSTEM
AGIP CODE
BENTONITE BASED FLUID
FW-GE
ENV.
Cuttings
Mud
A
Cost
B
Lubricant Properties
Convertible
B
Density
Logistic Difference
B
Temperature
Mainten. Difference
B
Solids-removal Eq.
LGS Tolerance
B
Re-use
Formation Inhibition
X
X
Cutting Inhibition
Dispersed
Non-dispersed
LT Oil
Alternative Oil
CHARACTERISTICS OF THE SYSTEM
Diesel
Sea Water
BASE FLUID
Fresh Water
21 OF 155
B
T1
D1
B
B
B
B
APPLICATION
- Drilling start-up;
- Viscose pills; A clay base should be provided to more complex polymer-base fluid;
- After prehydrating, sea water can be added;
- Specific treatments may adapt characteristics to the needs;
- Easily convertible to more complex systems.
LIMITATIONS
- Highly sensitve to chemical contaminants;
- Low solids tolerance;
- Unadequate characteristics for situations other than drilling start-up.
15
20
9.5
FORMULATION
PRODUCTION
FRESH WATER
BENTONITE (OCMA)
CAUSTIC SODA
MIXING TIME:
+/- 25 m 3 /hr
320
kg-l/m 3
40-70
1-2
50
Electrical stability (volt)
3
30
O/W ratio
10
MBT(Kg/m3 equiv.)
10
Ca (gr/l)
60
NaCl (gr/l)
1.15
Mf
8.5
Pf
12
Pm
API Filtrate (cc/30')
6
pH
Gel 10'(gr/100cm2)
1
Sand (% in vol)
Gel 10" (gr/100cm 2)
5
Water (% in vol.)
Yield point (gr/100cm2 )
6
Oil (% in vol.)
Plastic visc. (cps)
40
Solids (% in vol.)
Funnel visc. (sec/qt)
1.3
API HTHP (cc/30')
Density (SG)
CHARACTERISTICS OF THE DRILLING FLUID
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
22 OF 155
REVISION
STAP -P-1-M-6160
0
MAINTENANCE:
SAND GROUNDS
SHALES
GYPSUM/ANHYDRITE
SALT
+
=/+
+
+
=
+
=/--
+
+
+
=/+ +/--
+
+
+
+/--
+
+
+
+
+
+
+
CO 2
--
H S
2
--
+
+
%Sand
NaCl
Ca
MBT
Solids
Mf
Pf / Pm
=/+
+/--
CEMENT
pH
Filtrate
Gels
Yield
PV
CONTAMINANTS
Density
- Maintain an adequate solids percentage;
- Use water and bentonite to control viscosity and/or vary pH.
+
--
=/--
--
=/--
--
+
+
-SO - DILUTION
4
+ - Na CARBONATE
- CONVERT TO FW-LS
- CONVERT TO FW-GY
+
+
--
--
--
+
--
--
--
- DESANDERS
- CENTRIFUGE
- DILUTION
- CONVERT TO FW-LS
+
+
REMEDIALS
+
- DILUTION, CMC
- CONVERT TO FW -SS
- DILUTION
- Na BICARBONATE
- DEGAS
- ALTERNATE TREATMENT
WITH NaOH and Ca(OH)2
STINKING SMELL
GREEN OR BLACK COLOUR
- PREVENTIVE TREATMENT
WITH SCAVENGER.
- HYDROGEN PEROXIDE +
NaOH.
- DEGAS
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
0
AGIP CODE
DESCRIPTION OF THE SYSTEM
GUAR-GUM SUSPENSION
SW-GG
ENV.
Cuttings
Mud
B
B
Electrical Stability (volt)
NaCl (gr/l)
B
O/W Ratio
D1
Cost
Density
T1
Lubricant Properties
Temperature
X
X
Mf
Solids-removal Eq.
Re-use
Convertible
Logistic Difference
Maint. Difference
LGS Tollerance
Formation Inhibition
Cutting Inhibition
Dispersed
Non-dispersed
Alternative Oil
CHARACTERISTICS OF THE SYSTEM
LT Oil
Diesel
Sea Water
BASE FLUID
Fresh Water
23 OF 155
DESCRIPTION AND APPLICATION
- Drilling start-up
- Viscose pills in sea water or in presence of electorlytes;
- Can be used as Bentonite extender (in low concentrations);
- Reduced logistical problems in drlling start-up.
ADVANTAGES AND LIMITATIONS
- Fresh water is needed for hydration;
- Low cost;
- Low concentration usage;
- Fermention;
- Non resistant to high temperatures;
- Suitable for viscose pills only.f
FORMULATION
MIXING TIME:
7
PRODUCT
kg-l/m 3
SEA WATER
GUAR GUM
BACTERICIDE
10
as needed
+/- 30 m 3 /hr
MBT(kg/m3 equiv.)
Ca (gr/l)
Pf
Pm
pH
NC
Sand (% in vol)
API Filtrate (cc/30')
15
Water (% in vol.)
Gel 10'(gr/100cm2)
15
Oil (% in vol.)
Gel 10" (gr/100cm2)
30
Solids (% in vol.)
Yield Point (gr/100cm2)
20
API HTHP (cc/30')
Plastic Visc. (cps)
1.03 100+
Density (SG)
Funnel Visc. (sec/qt)
CHARACTERISTICS OF THE DRILLING FLUID
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
24 OF 155
REVISION
STAP -P-1-M-6160
0
PREPARATION
- Avoid adding NaOH to the system;
- Use a bactericideif not used immediately;
- For hydrations, stir at high speed for approx. 1hr;
- 'Fish eyes' can be easily observed.
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
0
DESCRIPTION OF THE SYSTEM
AGIP CODE
BENTONITE-AND CMC-BASE FLUID
FW-GE-PO
ENV.
Mud
B
B
B
Electrical Stability (volt)
B
Cuttings
D1
Excess Lime (kg/m3)
T1
Cost
B
Lubricant Properties
A
Calcium (gr/l)
B
Density
Convertible
B
NaCl (gr/l)
Logistic Difference
B
Temperature
Maint. Difference
B
Solids-removal Eq.
LGS Tolerance
B
Re-use
Formation Inhibition
X
Cutting Inhibition
Dispersed
Non-dispersed
Alternative Oil
CHARACTERISTICS OF THE SYSTEM
LT Oil
Sea Water
X
Diesel
Fresh Water
BASE FLUID
X
25 OF 155
DESCRIPTION AND APPLICATION
- Drilling start-up when FW-GE characteristics are not sufficient;
- Drilling non reactive formations with gradient <1.1 kg/cm2.
ADVANTAGES AND LIMITATIONS
- Easy maintenance and low cost;
- Highly sensitive to chemical contaminants;
- Low solids tolerance.
15
4
15
2
9.5
60
FORMULATION
MIXING TIME:
PRODUCT
kg-l/m 3
FRESH/SALT WATER
BENTONITE
CAUSTIC SODA
CMC HV
CMC LV
20 - 60
1-3
0-6
2 - 10
+/- 25 m 3 /hr
MBT(kg/m3 equiv.)
15
Mf
80
Pf
1.15
Pm
20
pH
8.5
Sand (% in vol)
10
Water (% in vol.)
8
Oil (% in vol.)
API Filtrate (cc/30')
2
Solids (% in vol.)
Gel 10'(gr/100cm2)
4
API HTHP (cc/30')
Gel 10" (gr/100cm 2)
5
Plastic Visc. (cps)
40
Funnel Visc. (sec/qt)
1.03
Density (SG)
Yield Point (gr/100cm 2)
CHARACTERISTICS OF THE DRILLING FLUID
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
26 OF 155
REVISION
STAP -P-1-M-6160
0
MAINTENANCE:
To control RHEOLOGY:
- Increase: Bentonite, CMC HV;
- Decrease: Solids-Removal, Dilution, Lignosulfonates.
+
=/+ +/-+/--
SALT
CEMENT
CO 2
--
H2 S
--
+
+
=/+
=/--
--
--
+
+
=/--
--
+
+
+
+
+
+
+
+
+
+
+
=/--
+
-SO4 - DILUTION
+ - Na CARBONATE
- CONVERT TO FW-LS
- CONVERT TO FW-GY
+
+
--
--
--
+
--
--
--
- DESANDERS
- CENTRIFUGE
- DILUTION
- CONVERT TO FW LS
+
+
+
REMEDIALS
%Sand
+/--
NaCl
=
Ca
GYPSUM/ANHYDRITE
MBT
+
Solids
+
Mf
+
Pf / Pm
SHALES
pH
=/+
Filtrate
+
Gels
PV
SAND GROUNDS
CONTAMINANTS
Yield
Density
To control FILTRATE:
- CMC LV and/or Bentonite.
+
- DILUTION, CMC
- CONVERTIRE IN FW SS
- DILUTION
- Na BICARBONATE
- DEGAS
STINCKING SMELL
GREEN OR BLACK COLOUR
- PREVENTIVE TREATMENT
WITH SCAVENGER.
- HYDROGEN PEROXIDE +
NaOH
- DEGAS
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
0
AGIP CODE
DESCRIPTION OF THE SYSTEM
LOW-SOLIDS FLUID WITH BENTONITE EXTENDER
D1
B
B
B
Mud
Cost
T1
Lubricant Properties
A
Cuttings
ENV.
Density
A
Temperature
B
Solids-removal Eq.
M
Re-use
LGS Tolerance
B
Convertible
B
Logistic Difference
M
Formation Inhibition
Cutting Inhibition
Dispersed
X
Maint. Diference
X
Non-dispersed
Alternative Oil
LT Oil
Diesel
Sea Water
FW-LW
CHARACTERISTICS OF THE SYSTEM
BASE FLUID
Fresh Water
27 OF 155
B
DESCRIPTION AND APPLICATION
- Low density and high viscocity with a reduced solids-contents;
- Reduced transportation problems;
- Optimum for drilling start-up or when high mixing time is required.
ADVANTAGES AND LIMITATIONS
- Sensitive to chemical contaminants;
- Sensitive to chlorides;
- Low solids tolerance.
3
15
6
FORMULATION
PRODUCT
9.5
8
MIXING TIME:
m3 /h
kg-l/m 3
30
BENT. EXTENDER
0,12
NaOH/KOH
1-1,2
(CMC LV)
2-10
: 50
0.1
MAX MAX
FRESH WATER
BENTONITE
Electrical Stability. (volt)
O/W Ratio
MBT(kg/m 3equiv.)
Ca (gr/l)
NaCl (gr/l)
Mf
Pf
Pm
pH
5
Sand (% in vol)
Gel 10'(gr/100cm 2)
2
Water (% in vol.)
Gel 10" (gr/100cm 2)
8
Oil (% in vol.)
Yield Point (gr/100cm 2)
5
Solids (% in vol.)
Plastic Visc. (cps)
45
API HTHP (cc/30')
Funnel Visc. (sec/qt)
1.03
API Filtrate (cc/30')
Density (SG)
CHARACTERISTICS OF THE DRILLING FLUID
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
28 OF 155
REVISION
STAP -P-1-M-6160
0
MAINTENANCE
CaSO4
=
-
-
-
+
=/-
SOLIDS
+
+
+
+
+
+
EXCESS
POLYMER
=
-
-
-
-
-
% Sand
=/-
NaCl
+
Ca
+
MBT
+
Solids
Filtrate
+
Mf
Gels
Pf / Pm
Yield
+/-
CONTAMINANTS
pH
PV
Density
- Prehydrate bentonite before adding extencer;
- Extender should be prehydrated before adding to the active system;
- Addition ratio is1 kg of extender every 250 kg of bentonite;
- Control solids as per range indicated;
- Efficiency of shale shakers and cyclones is important;
- High quantity of extender is an energic encapsulating agent.
REMEDIAL
SALT,
SALT WATER
=
+
=
+
+
CONVERT TO SW-PO
SODA ASH + EXTENDER
ADD EXTENDER, DILUTE
ADD. BENTONITE
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
0
DESCRIPTION OF THE SYSTEM
AGIP CODE
FW/SW-LS
LIGNOSULPHONATE-BASE FLUIDS
ENV.
DESCRIPTION
Mud
M
Cuttings
Convertible
B
Cost
Logistic Tolerance
B
Lubricant Properties
Maint. Tolerance
A
Density
LGS Tolerance
B
Temperature
Formation Inhibition
B
Solids-removal
Eq.
Cutting Inhibition
X
Re-use
Dispersed
Non-dispersed
Alternative Oil
CHARACTERISTICS OF THE SYSTEM
LTOil
Sea Water
X
Diesel
Fresh Water
BASE FLUID
X
29 OF 155
B
T2
D4
B
B
B
M
- Most versatile fluid. Ideal for exploration wells;
- High solids-tolerance. Easy maintenance;
- High tolerance to chemical contaminants;
- Convertible to Lime or Gypsum-based fluids.
ADVANTAGES AND LIMITATIONS
- Environmental impact concerns;
- Lignosulphonates are uneffective in salt saturated fluids;
- Optimum pH is 10, this value helps shale dispersion;
- Lignosulphonate stabilises the collidal dispersion of shale in water reducing the
effectiveness of any encapsulators.
FORMULATION
7
60
PRODUCT
0.5
20
3
0.7
70
kg-l/m 3
MIXING TIME:
+/- 20 m 3 /hr + weighting time
20 - 70
10 - 30
1-4
2-10 / 10 - 20
as needed
Electrical Stability (volt)
1
O/W Ratio
9.5
10.5
FRESH (SALT) WATER
BENTONITE
FCL
NaOH
CMC LV / LIGNIN
BARITE
MBT(kg/m3 equiv.)
Ca (gr/l)
NaCl (gr/l)
40
Mf
10
Pf
2
Pm
10
15
pH
5
2
Sand (% in vol)
API Filtrate (cc/30')
1
12
Water (% in vol.)
Gel 10'(gr/100cm2 )
2
45
Oil (% in vol.)
Gel 10" (gr/100cm2 )
5
60
Solids (% in vol.)
Yield Point (gr/100cm2 )
38
2.1
API HTHP (cc/30')
Funnel Visc. (sec/qt)
1.1
Plastic Visc. (cps)
Density (SG)
CHARACTERISTICS OF THE DRILLING FLUID
ARPO
IDENTIFICATION CODE
PAGE
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Agip Division
30 OF 155
REVISION
STAP -P-1-M-6160
0
MAINTENANCE:
+
+
+
+
=/-
+
=/-
-
=/-
+
-
-
=/+
CO2
-
+
+
+
=/+
-
-
+
CEMENT
=
+/-
+
+
+
+
+
=/-
REMEDIAL
- SOLIDS CONTROL
- TREATMENT WITH FCL+SODA
+
+
- FCL + SODA ASH
- ADD CMC LV
- CONVERT TO FW-GY
+
SALT
% Sand
+/-
-
NaCl
=
=/-
Ca
GYPSUM/ANHYDRITE
=/-
MBT
+
Solids
+
Mf
+
Pf / Pm
Gels
+
pH
Yield
SHALE
CONTAMINANTS
Filtrate
PV
Density
- Dependent on the solids percentage;
- Thanks to the system flexibility characteristics may be adapted according to the needs by simply
adding additives;
- For high temperature and/or high density, use lignin as an alternative to CMC to control filtrate.
-FCL + SODA ASH
-CMC LV
-CONVERT TO SS
- FCL + C.SODA and/or LIME
+/=
-PRETR. WITH NaHCO3
- FCL+CMC
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
AGIP CODE
(CHROME)-LIGNIN-BASE FLUIDS
FW/SW-CL
ENV.
Mud
B
Cuttings
Convertible
B
Cost
Logistic Difference
B
Lubricant Properties
Maint. Difference
A
Density
LGS Tolerance
B
Temperature
Formation Inhibition
B
Solids-removal Eq.
Cutting Inhibition
X
Re-use
Dispersed
Alternative Oil
Non-dispersed
CHARACTERISTICS OF THE SYSTEM
LT Oil
Sea Water
Diesel
Fresh Water
(X)
0
DESCRIPTION OF THE SYSTEM
BASE FLUID
X
31 OF 155
M
T3
D4
B
B
B
M
DESCRIPTION AND APPLICATION
- Development of Lignosulphonate-based fluids at high temperatures:
To aid filtrate control add chrome Lignin which integrates the thinning effect of
Lignosulphonate.
ADVANTAGES AND LIMITATIONS
- Versatile and economical system;
- High solids tolerance;
- Cr-Lignin is a less effective scavenger than lignosulphonate. Its effectivness is further reduced in
sea water and becomes completely uneffective in presence of calcium;
- Environmental impact concerns.
Mf
Ca (gr/l)
MBT(kg/m 3equiv.)
8
9.5
1
0.3
0.5
0.2
60
2.1
60
40
8
1
10
2
10
40
11
3
0.7
1.5
MAX
10
FORMULATION
MIXING TIME:
3
m /h
PRODUCT
kg-l/m 3
FRESH WATER
BENTONITE
FCL
CL
NaOH
POLYMERS (CMC, PAC)
BARITE
20-70
10-30
10-30
0.5-5
0-10
as needed
20 + WEIGHTING TIME
Electrical Stability (volt)
Pf
30
O/W Ratio
Solids (% in vol.)
10
NaCl (gr/l)
API HTHP (cc/30')
4
Pm
Gel 10'(gr/100cm 2)
1
pH
Gel 10" (gr/100cm 2)
5
Sand (% in vol)
2
Yield Point (gr/100cm )
8
Water (% in vol.)
Plastic Visc. (cps)
40
Oil (% in vol.)
Funnel Visc. (sec/qt)
1.08
API Filtrate (cc/30')
Density (SG)
CHARACTERISTICS OF DRILLING FLUIDS
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
32 OF 155
REVISION
STAP -P-1-M-6160
0
MAINTENANCE
- High solids tolerance;
- Up to 150°C, deflocculant effect is due to FCL; over this temperature CL is most commonly employed;
- Alkalinity control is highly important to guarantee Cr-Lignin solubility;
- Dump if contamination from carbonates or bicarbonates is present.
- RHEOLOGY
- Decrease: add FCL/CL/ Soda, dilute only in case of excess solids;
- Increase: add prehydrated and FCL protected Bentonite carefully. Evaluate the addition of polyacrylates.
- FILTRATE
SHALE
+
+
+
+
-
-
-
CEMENT
=
+/-
+
+
+
+
+
CaSO4
=
+/-
+
+
+
+/-
=
=/+
=/+
+/-
+
+
+
-
-
-
CARBONATES/
BICARBONATES
=
+
+
+
=/-
+/-
+
TEMPERATURE
+
+
+
+
SALT
=/-
+
+
% Sand
NaCl
Ca
MBT
Solids
Mf
Pf / Pm
pH
Filtrate
Gels
Yield
CONTAMINANTS
PV
Density
- Maintain a reduced quantity of Bentonite, add CL, and HPHT polymers.
REMEDIAL
- CENTRIFUGE
- +FCL + CL + NaOH
- DILUTION
=/+
- + NaHCO3 O Na2CO3
- + FCL + CL
+
- + Na2SO4 E/0 NaOH
- + FCL + CL
- CONVER.IN FW-GY
+
+/-
- + FCL + CL
- CONVER.IN FW-SS
- FOR T. >150° C
UTILIZZARE DS-IE
- + LIME AND/OR C. SODA
- + FCL + CL
- + DEFLOC. AT HT
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
0
DESCRIPTION OF THE SYSTEM
AGIP CODE
P.A.C.- BASE FLUIDS (DRISPAC)
ENV.
B
Mud
Lubricant Properties
Density
D4
Cuttings
T2
Cost
A
Temperature
A
Solids-removal
Eq.
M
Re-use
B
Convertible
Logistic Difference
B
Maint. Diffrence
Formation
Inhibition
M
LGS Tolerance
X
Cutting Inhibition
Dispersed
Non-dispersed
Alternative Oil
LT Oil
Sea Water
Diesel
Fresh Water
X
FW/SW-PA
CHARACTERISTICS OF THE SYSTEM
BASE FLUID
X
33 OF 155
M
B
B
DESCRIPTION AND APPLICATION
- Encapsulating system, optimum base for inhibitive polymer systems;
- High concentrations may limit cutting dispersion;
- Same application as FW-PO, but has a better efficiency at high concentrations of monovalent salts.
ADVANTAGES AND LIMITATIONS
- Encapsulating system which needs the addition of an inhibitive salt for inhibition;
- High sensitvity to contaminations from polyvalent salts;
- Low solids tolerance.
16
9.5
MAX 20
FORMULATION
Solids (% in vol.)
PRODUCT
FRESH/SALT WATER
BENTONITE
P.A.C.(REGULAR)
P.A.C.LV
NaOH
BARITE
MIXING TIME:
3
m /h
25 + WEIGHTING TIME
kg-l/m 3
20-40
2-5
0-5
1,0-1,5
as needed
Electrical Stability (volt)
2
20
O/W Ratio
15
MBT(kg/m3 equiv.)
5
Ca (gr/l)
10
NaCl (gr/l)
20
Mf
60
1.5
Pf
0.4
Pm
8.5
pH
6
Sand (% in vol)
8
Water (% in vol.)
API Filtrate (cc/30')
10
Oil (% in vol.)
Gel 10'(gr/100cm2 )
3
API HTHP (cc/30')
Gel 10" (gr/100cm 2)
6
Plastic Visc. (cps)
10
Funnel Visc. (sec/qt)
1.05 45
Density (SG)
Yield Point (gr/100cm2)
CHARACTERISTICS OF THE
DRILLING FLUIDS
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
34 OF 155
REVISION
STAP -P-1-M-6160
0
MAINTENANCE
- Mainly encapsulating, this system needs an adequate concentration of polymer (>3 kg/m3) to limit cutting
dispersion and high increase of viscosity;
- Easily convertible to a Potassium-base system, both Polymer-base and dispersed;
- If a density increase above optimum range is desired, convert the system to a more solids-tolerant one.
- RHEOLOGY
- Decrease: Deflocculate using a short chain polymer (i.e.: short chain CMC LV, PHPA); Dilute; add CL
and/or FCL.
- FILTRATE
SHALE
+
+
+
+
-
-
-
CEMENT
=
+/-
+
+
+
+
+
CaSO4
=
+/-
+
+
+
-
=
=/+
=/+
+/-
+
+
+
-
-
-
SALT
+
+
% Sand
NaCl
Ca
MBT
Solids
Mf
Pf / Pm
pH
Filtrate
Gels
Yield
PV
CONTAMINANTS
Density
- Use PAC Regular/LV and/or CMC LV dependent on rheology desired. High salt content fluids can result
economical if employed with starches.
REMEDIAL
- DILUTION
- CONV. TO A MORE
INHIBITIVE SYSTEM
+
- PRETREAT WITH SODIUM
BICARBONATE
+
- ADD. SODA ASH.
- CONV IN FW/SW GY
- ADD FCL
+
- CONTAMINANT IS
DEPENDENT ON OBM
- CONV. TO FW/SW-SS
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
0
AGIP CODE
DESCRIPTION OF THE SYSTEM
PHPA-BASE FLUIDS
ENV.
Cuttings
Mud
B
M
B
B
O/W Ratio
D3
Lubricant Properties
T2
Cost
A
Density
A
Temperature
M
Solids-removal Eq.
M
Re-use
M
Convertible
Logistic Difference
B
Maint. Difference
Formation Inhibition
M
LGS Tolerance
X
Cutting Inhibition
Dispersed
Non-dispersed
Alternative Oil
LT Oil
Sea Water
Diesel
Fresh Water
X
FW/SW-PC
CHARACTERISTICS OF THE SYSTEM
BASE FLUID
X
35 OF 155
DESCRIPTION AND APPLICATION
- Pre-soluble polymers are required to viscosify and encapsulating cuttings;
- High solids-tolerance;
- Optimum base for a KCI-base fluid;
ADVANTAGES AND LIMITATIONS
- Encapsulating system which needs the addition of an inhibitive salt for inhibition;
- High sensitivity to contaminations from polyvalent salts;
- Low solids tolerance.
FORMULATION
PRODUCT
FRESH/SALT WATER
BENTONITE
PHPA
CMC LV (CL)
NaOH/KOH
BARITE
MIXING TIME:
m3/h
25 + WEIGHTING TIME
MBT(kg/m3equiv.)
MAX
20
kg-l/m3
30
5
0-7 (10)
0.1-0.5
as nedeed
Electrical Stability (volt)
Ca (gr/l)
10.5
NaCl (gr/l)
2
50
Mf
20
0.4
Pf
5
8.5
Pm
15
27
pH
30
Sand (% in vol)
60
1.8
Water (% in vol.)
8
Oil (% in vol.)
15
Solids (% in vol.)
2
API HTHP (cc/30')
5
API Filtrate (cc/30')
Gel 10'(gr/100cm2)
10
Plastic Visc. (cps)
1.03 45
Density (SG)
Gel 10" (gr/100cm2)
Yield Point (gr/100cm2)
Funnel Visc. (sec/qt)
CHARACTERISTICS OF THE DRILLING FLUID
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
36 OF 155
REVISION
STAP -P-1-M-6160
0
MAINTENANCE
- Encapsulating system: An adequate concentration of polymer (3>kg/M3) is needed to limit cutting
dispersion and high increase of viscosity;
- Easily convertible to a potassium-base system;
- Polymer may be added wherever but not through the hopper to avoid foam formation;
- Can tolerate up to 170°C by using additives.
- RHEOLOGY
- Decrease: Deflocculate using a short chain polymer (i.e.: short chain CMC LV, PHPA);
Dilute; If a more energic action is needed, them add CL and/or FCL.
FILTRATE
SHALE
+
+
+
+
+/-
-
-
+
CEMENT
=
+/-
+
+
+
+
+
CaSO4
=
+/-
+
+
+
-
=
=/+
SALT
=/+
+/-
+
+
+
-
-
-
+
% Sand
NaCl
Ca
MBT
Solids
Mf
Pf / Pm
pH
Filtrate
Gels
Yield
PV
CONTAMINANTS
Density
- Use the most adequate a filtrate reducer according to the usage: (temperature, density, salinity).
REMEDIAL
- ADD PHPA
- ADD. PHPA LMW.
-INCREASE INHIBITION
+
- PRETREAT WITH
NaHCO3
+
- ADD. Na2CO3
- CONV IN FW/SW GY
- ADD FCL
+
- CONTAMINANT IS
DEPENDENT ON MBT
- CONV. TO FW/SW-SS
ARPO
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
ARPO
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
PAGE
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
ARPO
IDENTIFICATION CODE
PAGE
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
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
47 OF 155
REVISION
STAP -P-1-M-6160
0
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
ARPO
IDENTIFICATION CODE
PAGE
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
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
49 OF 155
REVISION
STAP -P-1-M-6160
0
MAINTENANCE
- System with floculation controlled by the balance between two salts and a polymer: Highly important to
maintain the balance between Pf, Pm and Morex;
- Always add Lime and Morex simultaneously in a ratio of 4/2 and 3/2 dependent on the characteristics
desired and temperature.
RHEOLOGY
- Flocculation control is due to the ratio Lime/Morex. Do not use dispersers;
- Keep MBT below 10%; For high densities and temperatures > 135 °C, do not exceed 4-6%.
FILTRATE
SHALE
+
CEMENT
=
CaSO4
SALT
HIGH
TEMPERATURE
+/-
+
% Sand
Cl
Ca
+
=/-
-
-
+
+
+
+
+
+
- ADD. LIME + MOR-REX
+ WATER + LIGNITE +
+KOH.
+
+
+
-
-/+
+
- IF Ca++ > 1200 ppm
ADD. K2CO3
- CONV. TO FW-GY
+
+
+
-
-
+
+
-
-
+
REMEDIAL
+
+
+
MBT
Solids
Mf
Pf / Pm
pH
Filtrate
Gels
Yield
CONTAMINANT
PV
Density
- Use starch as main filtrate reducer up to a temperature of 100 °C, for higher temperatures use starch and
lignite in a ratio of 2/1 and 1/1;
- Do not add alkaline agent to starch simultaneously as it may cause an increase of viscosity. Pre-solubilised
lignite may be convienvent.
- Ca++ AND MOR-REX
- DECREASE MBT
+
+
- CONV. TO FW-SS
- DECREASE MBT.
- ADD. LIGNITE FOR
FILTRATE.
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
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.
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
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
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
52 OF 155
REVISION
STAP -P-1-M-6160
0
MAINTENANCE
- An Oil-base fluid is traditionally easy to maintain. Pay attention to record dilutions and product quantities
required in order to keep correct concentrations;
- To avoid problems, constantly monitor any modifications of the characteristics, especially the electrical
stability and HPHT filtrate. If any modifications, determine the possible causes and take prompt remedial
actions.
RHEOLOGY
- Should be determined at a temperature of 120 or 150oF. Do not use marsh viscosity for maintenance;
- Water is the principle viscosifier of Oil-base fluids. Its percent will vary depending on the characteristics
required. Other viscosifiers enhance yield point and Gels. Viscosity is also given by solids, thus it is essential
to decrease the water content in the fluid by increasing density.
FILTRATE
SOLIDS
+
+
+
++
=/-
=
WATER
-/+
+
+
+
+
-
+/-
+/-
+
CaCl2 > 35%
-
-
-
-
Cuttings
Aspect
Wetting
Water
CaCl2
EL. STAB.
0/W
POM
F. HPHT
Gels
Yield
CONTAMINANTS
PV
Density
-The main filtrate reducer is given by the quality of emulsion. Other filtrate reducers may be needed for
high temperatures or for very low HPHT filtrate values.
REMEDIALS
(?)
(PLASTIC) - ADD.WETTING AGENT
- DILUTE
(+)
(PLAST.)
- IF O/W OK, + EMULSION.
IF O/W K.O., + OLIO X OK
(PLAST.)
- LIGHT CONTAM.
- CONV. TO DS/LT-IE
=/+
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
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
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
0
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+
ARPO
IDENTIFICATION CODE
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.
ARPO
IDENTIFICATION CODE
PAGE
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
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
57 OF 155
REVISION
STAP -P-1-M-6160
0
MAINTENANCE
- Encapsulating system: An adequate concentration of polymer (3>kg/M3) is needed to limit cutting
dispersion and high increase of viscosity;
- Easily convertible to a potassium-base system;
- Polymer may be added wherever but not through the hopper to avoid foam formation;
- Can tolerate up to 170°C by using additives.
- RHEOLOGY
- Decrease: Deflocculate using a short chain polymer (i.e.: short chain CMC LV, PHPA);
Dilute; If a more energic action is needed, them add CL and/or FCL.
FILTRATE
SHALE
+
+
+
+
+/-
-
-
+
CEMENT
=
+/-
+
+
+
+
+
CaSO4
=
+/-
+
+
+
-
=
=/+
SALT
=/+
+/-
+
+
+
-
-
-
+
% Sand
NaCl
Ca
MBT
Solids
Mf
Pf / Pm
pH
Filtrate
Gels
Yield
PV
CONTAMINANTS
Density
- Use the most adequate a filtrate reducer according to the usage: (temperature, density, salinity).
REMEDIAL
- ADD PHPA
- ADD. PHPA LMW.
- INCREASE INHIBITION
+
- PRETREAT WITH
NaHCO3
+
- ADD. Na2CO3
- CONV IN FW/SW GY
- ADD FCL
+
- CONTAMINANT IS
DEPENDENT ON MBT
- CONV. TO FW/SW-SS
ARPO
IDENTIFICATION CODE
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
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
59 OF 155
REVISION
STAP -P-1-M-6160
0
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
ARPO
IDENTIFICATION CODE
PAGE
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
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
61 OF 155
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.
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
0
AGIP CODE
DESCRIPTION OF THE SYSTEM
CATION-BASE FLUID
FW/SW-CT
ENV.
D3
Mud
T2
Cutting
A
Cost
Re-use
Convertible
Logistic Difference
A
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.
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
63 OF 155
REVISION
STAP -P-1-M-6160
0
MAINTENANCE
- Tolerance between cationic and conventional (anionic) polymers should be verified. Tolerance is traditionally
possible for formulations with a certain content of chloride ion;
- Never use lignosulphonates or other anionic polymers, even in presence of chlorides. Do not increase pH
above 9.5 value.
RHEOLOGY
- System maintenance may be difficult due to the poor availability of compatible products with cationic
polymers;
- Generally a biopolymer and/or HEC is used as a viscosifier;
- Solids control is highly important.
FILTRATE
SHALE
+
CEMENT
=
+
+
+
=/-
-
-
+
+
+
+
+
+
CaSO4
SALT/SALT WATER +/-
HIGH
TEMPERATURE
+
+
+
-
-
+
REMEDIAL
- ADD.CATIONIC POLYMER
- DILUTE
+
- ADD. CH3COOH
- ADD. NaHCO3
+
- NO CONTAMINATION
+
+
%Sand
Cl
Ca
MBT
Solids
Mf
Pf / Pm
pH
Filtrate
Gels
Yield
CONTAMINANTS
PV
Density
- The most used filtrate reducers are: Modificated starches, kaolinte, prehydrated and PVA (Polyvinil alcohol)
protected bentonite;
- PAC can be employed in presence of electrolytes.
- NO CONTAMINATION
- REDUCE MBT.
- DEFLOCCULATE
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
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
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
65 OF 155
REVISION
STAP -P-1-M-6160
0
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.
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
0
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
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
67 OF 155
REVISION
STAP -P-1-M-6160
0
MAINTENANCE
SOLIDS
+
+
+
++
=/-
(?)
=
(PLAST.)
Aspect
Cuttings
Wetting
Water
CaCl2
El. Stab.
0/W
POM
HPHT F.
Gels
Yield
CONTAMINANTS
PV
Density
- Refer to DS-IE for maintenance procedures;
- Control if oil percentage of cuttings from oil-base fluid is within the values to allow the discharge. Take
all actions to maintain this percentage low;
- Optimise solids-removal equipment;
- Maintain the lowest oil/water ratio, compatible to the characteristics required.
REMEDIAL
- ADD. WETTING AGENT
- DILUTE
WATER
-/+
+
+
+
+
-
-
-
-
(+)
(PLAST.) -IF O/W IS OK,
THAN RESTORE ADDITIVE
PERCENTAGE
-IF O/W IS NOT OK
THAN ADD LT OIL+ ADDIT. %
OIL
-
-
-
-
-
=
+
-
-IF O/W IS OK,
THEN RESTORE ADDITIVE
PERCENTAGE
-
- IF O/W IS NOT OK THEN
ADD WATER + ADDIT.%
CaCl2 > 35%
+/-
+/-
+
-
+
-
-
(+)
(PLAST.) - ADD. FRESH WATER
- ADD. WETTING AGENT
HIGH
TEMPERATURE
-
-
=
-
- ADDEMULSIFIERS
- ADD FILTRATE REDUCERS
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
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
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
69 OF 155
REVISION
STAP -P-1-M-6160
0
MAINTENANCE
- Generally maintained as an oil-base fluid;
- Unstable due to the high water percentage and more difficult to maintain than
a conventional oil-base fluid;
- Low electrical stability. Emulsion quality is evaluated from HPHT filtrate by verifying
the absence of water.
RHEOLOGY
- Very high rheology;
- High viscosity may allow a high percentage of residual fluid, and oil from cuttings. To
reduce viscosity, increase the O/W ratio. However, this may also increase oil from
cuttings, find a right balance between the two factors.
FILTRATE
SOLIDS
+
+
+
++
=/-
-/+
+
+
+
+
-
Aspect
Cuttings
REMEDIAL
(PLAST.) - ADD. WETTING AGENT
=
(?)
WATER
Wetting
Water
CaCl2
EL. Stab.
0/W
POM
F. HPHT
Gels
Yield
CONTAMINANTS
PV
Density
- HPHT filtrate provides stability to the system. Its maintenance is highly important. Avoid
overtreatment with emulsifiers or filtrate reducers for excessive viscosity.
-
-
-
(+)
- DILUTE
(PLAST.) -IF O/W RATIO IS OK, THEN
RESTORE ADDITIVE%.
-IF THE O/W IS NOT OK,
THEN ADD LT OIL +
ADDITIVE%.
OIL
-
-
-
-
-
=
+
-
-
- IF O/W IS OK, THEN
RESTORE ADDITIVE %.
-IF THE O/W IS NOT OK,
THEN ADD WATER +
ADDITIVE %.
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
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.
ARPO
IDENTIFICATION CODE
PAGE
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
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
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
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
73 OF 155
REVISION
STAP -P-1-M-6160
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
ARPO
ENI S.p.A.
Agip Division
IDENTIFICATION CODE
PAGE
74 OF 155
REVISION
0
Maintenance Problems
HIGH VISCOSITY,
PARTICULARLY YIELD
AND GELS AT 10".
UNEFCETVE
TREATMENTS.
VISCOSITY INCREASE
WITH/WITHOUT VOLUME
INCREASE.
DIFFICULTY TO MAINTAIN
pH.
EFFECT ON FLUID
YIELD
+
+
GELS
+
+
FILTRATE
+
pH/Pf
=/+
-/-
IONS
Cl
Mg
MgCl2, FROM
FORMATION:
WATER WITH MgCl2
COMPLEX SALTS, SEA
WATER.
CAUSE
Mf+ FORMATION CO2:
THERMAL
DEGRADATION OF
POLYMERS:
CONTAMINATED
BARITE,
OVERTRATMENT WITH
BICARBONATE OR
CARBONATE, NaCO3
ADDED BENTONITE.
OTHER
SOLIDS
PV
DENSITY
REMEDIAL
STAP -P-1-M-6160
ATTENTION: DUMP ALL CONTAMINANTS THOROUGHLY, AS
SMALL CONCENTRATION MAY CREATE PROBLEM TO FLUID
MAINTENANCE, AVOID OVERTREATING WITH SEQUESTRING
ION (Ca++).
PAY ATTENTION TO HIGH TEMPERATURE, HIGH DENSITY
AND/OR POLYMER-BASE FLUID.
CONTAMINATION DIFFICULT TO RECOGNIZE, ESPECIALLY IN
COLORED FILTRATES.
INCREASE pH WITH NaOH, IF CONTAMINATION IS DUE TO
HCO3 AND Ca++ IS PRESENT THE FLUID;
USE Ca(OH)2, IF Ca++ IS NOT PRESENT OR USE CaSO4 IF pH
INCREASE IS NOT DESIRED;
USE cACl2 FOR BRINE OR CHLORIDE CONTENT FLUIDS.
TREAT WITH CAUSTIC SODA FOR LIGHT CONTAMINATION AND
MAINTAIN pH >/= 10.
CONVERT TO A FLUID TOLERANT OF MAGNESIUM (SALT
SATURATED, LOW pH, MIXED SALT SATURATED OR OIL-BASE
FLUID) IF CONTAMINATION IS SEVERE.
ATTENTION: CONTINUED ADDITIONS OF Mg(OH)2 TO THE
SYSTEM WILL RESULT IN A GREAT VISCOSITY INCREASE.
MAINTENANCE PROBLEMS OF WATER-BASE FLUIDS
ARPO
ENI S.p.A.
Agip Division
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
ARPO
PAGE
76 OF 155
REVISION
0
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
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
ARPO
IDENTIFICATION CODE
PAGE
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.
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
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
ARPO
IDENTIFICATION CODE
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.
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
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
ARPO
IDENTIFICATION CODE
PAGE
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.
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
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.
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
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
ARPO
IDENTIFICATION CODE
PAGE
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
(<1.3 s.g.)
5.4
85 OF 155
x
x
CENTRIFUGES:
-BARITE RECOVERY
x
- HIGH SPEED
*
()
SCALPING SHALE SHEKERS
NOT OBLIGATORY
x
x
- HIGH VOLUME
(x)
x
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
5.4.1
86 OF 155
0
Double Shale Shakers
COARSE SCREEN
COARSE SCREEN
BACKFLOW PLATE
FINE SCREEN
Figure 5.B - No Backflow Plated Shale
Shaker
Description:
Two-layer screen shale shaker with a course
upper screen and a fine lower screen.
FINE SCREEN
Figure 5.C - Backflow Plated Shale Shaker
Description:
Two-layer screen shale shaker with an
inclined plate located between them which
allows fluid to flow back to the beginning of
the fine lower screen.
Advantages:
Simple and economical to use and maintain
coarse screen removes most of the cuttings,
thus limiting the wearing out of the fine
screens.
Limitations:
Fluid losses from the lower screen. Wet
cuttings due to the short stay on screens.
Advantages:
Same as the no-backflow plated shale shaker
with better use of the lower finer screen.
Cuttings removed by the fine lower screen
are drier than those of the no-backflow plated
shale
shaker
system.
Fairly
good
performance with reduced sizes
Limitations:
Recommended for:
•
•
Marginal well plants, with low cost water
base fluids and lower costs of waste
discharge.
Same as scalping shale shaker used in
single
deck,
high
performance
configurations.
Replacement of the lower screens may be
difficult. Cuttings are not as dry of a single
deck shale shaker integrated with a scalping
shale shaker.
Recommended for:
•
As a primary shale shaker, especially
for water based fluids and noncascading plants (scalping, single deck,
premium shale shaker).
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
5.4.2
87 OF 155
0
Single Deck Shale Shakers
COARSE SCREEN
FINE SCREEN
Figure 5.E - Underflow Screens
Figure 5.D - Multiple Screens
Description:
Single deck, linear shaker with two more
screens
of
different
weave
placed
sequentially from the finer to the coarser. The
screens can be positioned forwards or
backwards.
Description:
Single deck, single screen with the initial
section completely underflowed by fluid.
Screen vibration allows cuttings to overflow
up the final inclined section.
Advantages:
Advantages:
Efficient and especially reliable with cuttings
from hard formations or oil based fluids. If
used properly, cuttings discarded are dry.
Designed to obtain very dry cuttings. 8-30
sized screens are installed when it is used as
a scalping shaker.
Limitations:
Limitations:
All cuttings are processed by the fine screen
which wears out more often, especially if
cuttings are plastic (drilled clays with water
based fluid). This problem can be solved by
using a another shale shaker placed in front
in sequence acting as a scalping shale
shaker.
Is solely a speciality shale shaker to reduce
residual oil, from cuttings.
If used with water based fluids and plastic
formations, the screens can be easily
plugged.
Recommended for:
•
Recommended for:
•
•
Use as a primary shale shaker for oil
based fluids.
With the use of very fine screens their
efficiency can be exploited by using a
bank of shale shakers sufficient for the
capacity required. This processes the
volume of fluid an efficient cost.
Exclusive use with oil based fluids and
when cutting discharge is allowed with
an oil residue percentage which can be
achievable.
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
5.5
88 OF 155
0
SCREEN SPECIFICATION
Type Of Screen
Mesh Per Inch
Wire Diameter
(ins)
Mesh Opening
(Microns)
Flow Area
(%)
1905 X1905
838 X838
381 X 81
178 X 78
117 X 17
105 X 5
74 X 4
56.3
43.6
36.0
31.4
30.9
37.9
33.6
762 X 3362
465 X 89
310 X 910
190 X 1037
200 X 406
457 X 140
45.7
39.1
36.8
34.0
31.1
35.6
Square Mesh Screens
S10
S20
S40
S80
S120
S150
S200
10 X 10
20 X 20
40 X 40
80 X 80
120 X 120
150 X 150
200 X 200
0.025
0.017
0.010
0.0055
0.0037
0.0026
0.0021
Rectangular Mesh Screens
B20
B40
B60
B80
B100
B120
5.5.1
8 X 20
20 X 30
20 X 40
20 X 60
40 X 60
40 X 80
0.032/0.02
0.015/0.015
0.014
0.013/0.009
0.009
0.0075
Nomenclature
Derrick
Description
Panel
Nomenclature
SWG
PWP
GBG
Pyramid
Screen
Example:
GBG HP 200 - Multiple, high performance screen mounted on a non-rigid support. 200
indicates that the equivalent mesh size does not correspond exactly to mesh number.
Derrick
Description
Example:
DC
DF
DX
HP
SCGR
3 layered, derrick standard screens, non-repairable.
3 layered screens mounted on a rigid support, repairable with
fitted plugs or silicon. The support takes up 35% of the flow area.
3 layered screens bonded to a non-rigid support, temporarily
repairable. The support takes up 10% of the flow area.
Corrugated screens on a rigid support gives approx. a 50%
increase in flow area.
Coarse mesh screens.
Fine mesh screens.
Extra fine mesh screens
High performance screens.
Rectangular mesh screens
BLS
BXL
S
B
Nomenclature
3 layered screens with plastic strips between the coarse screen and the others.
3 layered screens mounted on a plastic grid.
Square meshed screens.
Rectangular meshed screens.
The letter designation is followed by a number which, as in ‘BLS’, ‘BXL’ and ‘S’ screens,
indicates the mesh number. For ‘B’ designation, it is the sum of the mesh in both directions.
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
5.6
89 OF 155
0
CYCLONE SYSTEMS
EFFICIENCY GRADE (%)
VISCOSITY/CYCLOPE PERFORMANCE (4")
PV 6 cps, YP 1 gr/100cm2
100
PV 25 cps, YP 5 gr/100cm2
80
60
40
20
0
0
10
20
30
40
50
60
70
80
90
SOLIDS SIZE (MICRON)
Figure 5.F - Typical Viscosity/Cyclone Performance (4”)
Equipment
Desander
Desilter
Mud-Cleaner
Treatment Capacity
Required
1.25 (Max. Perf. Q)
1.5 (Max. Perf Q)
1.5 (Max. Perf. Q)
Weight Difference
Entrance/Discharge
0.3-0.6kg/l
0.3-0.4kg/l
0.3-0.4kg/l
Feed Pressure
30-45psi
30-45psi
30-45psi
Volume Discharged
From Equipment
3
+/- 1.5m /h
3
+/- 3.5m h
3
+/- 1m /h
SPRAY
DISCHARGE
DROP
DISCHARGE
NO
DISCHARGE
EXCESSIVE OPENING
PROPER FUNCTIONING
EXCESSIVE CLOSING
Figure 5.G - Calibration Of Water Discharge Cyclones
'B'
'B'
'A'
SPRAY
DISCHARGE
'C'
AIR CONE
PROPER FUNCTIONING
WASHING AWAY
-CONE HOLED IN "A"
- PARTIALLY PLUGGED CONE IN "B"
- TOO HIGH IN "C".
FLOOD
- CONE OR COLLECTOR
PLUGGED IN "B".
Figure 5.H - Typical Cyclone Malfunctions
DRY DISCHARGE
- HIGH SOLIDS PERCENTAGE
- CLOSED DISCHARGE.
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PAGE
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Agip Division
REVISION
STAP -P-1-M-6160
5.7
90 OF 155
0
CENTRIFUGE SYSTEMS
DECANTATION
OF SOLIDS
(POND)
DEHYDRATION
OF SOLIDS
(BEACH)
LIQUID DISCHARGE
SOLIDS
DISCHARGE
ROTATING BOWL
FEED PIPE
SCROLL
SOLIDS
DISCHARGE
OVERFLOW PORTS
FLUID FEED
Figure 5.I - Centrifuge Operating Principle
5.7.1
PrInciple Of Operation
a)
b)
c)
d)
Fluid to be processed is delivered to the centrifuge through the feed pipe.
The rotating bowl creates a very high centrifugal force which increases the
gravitational separation effects of the of fluids and solids.
The solids being heavier gather on the drum walls and when build up are
moved by the scroll to the solids discharge port.
The liquids move through the unit to the liquid discharge port nozzles.
The liquids decanting effect and solids dehydration depends on the following:
•
•
‘g’ centrifugal force.
Settling time of the solids on the drum.
Increasing
Feed Rate/H
‘G’
Micron Solids
Solids Fluid %
Feed Capacity
+
=
+
+
RPM
=
+
-
-
RPM Difference Between
Rotor/Scroll
=
=
=
+
Height Of Underflow Ports
=
=
+
+
Table 5.A- Effects Of Variables
ARPO
IDENTIFICATION CODE
PAGE
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Agip Division
REVISION
STAP -P-1-M-6160
5.7.2
91 OF 155
0
Centrifuge Processing
FLUID TO BE
PROCESSED
LGS DISCHARGE
LGS DISCHARGE
PROCESSED FLUID
Figure 5.J - Unweighted Fluid-Parallel Processing
HIGH "G"
LOW "G"
FLUID TO BE
PROCESSED
BARITE RECOVERY
LGS
DISCHARGE
PROCESSED FLUID
Figure 5.K - Weighted Fluid-Sequential Processing
ARPO
IDENTIFICATION CODE
PAGE
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Agip Division
REVISION
STAP -P-1-M-6160
6.
92 OF 155
0
TROUBLESHOOTING GUIDE
This section is a troubleshooting guide which addresses loss of circulation, describing
remedial actions to be taken for the various types of losses and includes some
information on the use of LCM and the appropriate procedures.
HIGH VISCOSITY
FLUID
HIGH VISCOSITY
FLUID AND HIGH
GELS
FRACTURES
AERETED FLUIDS
STIFF-FOAM
HIGH/VERY HIGH FILTRATION
MIXTURE
DOBC
IDENTIFICATION CODE
AERETED FLUIDS
STIFF-FOAM
HIGH FILTRATION
MIXTURE
FLUID THINNING
AND/OR
UNWEIGHTING
HIGH DENSITY
FLUIDS
STAP -P-1-M-6160
DOBC
DOB
HIGH
FILTRATION
MIXTURE
SET TIME LOW
LOADING
LOW DENSITY
FLUIDS
HYDRAULICALLY-INDUCED
FRACTURES
ENI S.p.A.
Agip Division
AERETED FLUIDS
STIFF-FOAM
DOBC
GEL CEMENT
DOBC
SPOT PILL WITH LCM
- HIGH FILTRATION FLUID
CEMENT +
GELSONITE
GEL-CEMENT
SLURRIES
HIGH
FILTRATION
MIXTURE
SPOT PILLS
WITH LCM
CEMENT/GEL
CEMENT
SLURRIES
CAVERNS
FRACTURES
FRACTURES
TOTAL
HIGH
FILTRATION
MIXTURE
- LCM IN CIRCULATION
HIGHLY
PERMEABLE
SURFACE
AREAS
ALMOST TOTAL
more than 50%
6.1
SEEPAGE
LOSS
less than 50%
ARPO
PAGE
0
LOST CIRCULATION CONTROL TECHNIQUES
Figure 6.A - Lost Circulation Control Flow Chart
93 OF 155
REVISION
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
6.2
94 OF 155
0
LOSSES IN VARIOUS FORMATION TYPES
Loss Determination In Various Formation Types
Unconsolidated Formations
Sands, gravel beds, etc.
Gradual increase in loss which may
develop and increase with penetration.
If permeability is less than 4/5 darcy, the
loss is maybe due to formation fracture.
Natural Fractures
Every type of elastic rock.
Gradual increase in losses which may
develop and increase with penetration
Cavernous Or Macrovugular
Formations
Limestones, dolomites,
reef, volcanic rocks.
Sudden and severe, to complete loss, of
returns.
The bit may fall from a few centimetres to
some metres at the moment of loss.
Perforations may be 'disturbed' before the
losses.
Induced Fractures
May occur to all formations.
Sudden and sever to complete losses.
It is likely to occur to
preferred plans of fractures.
Fluids with density more than 1.3 SG may
help create fractures.
Fracture may occur during, or
subsequent, to rough drilling.
If it occurs in one single well and does not
occur to the nearby wells, fracture may be
the cause
6.3
CHOICE OF LCM SPOT PILLS
RESULTS
GOOD
IF USED
WITH...
CEMENT
GOOD
NO GOOD
NONE
"PLASTIC" PLUGS
PERLITE
GRANULAR
(COTTON) FLAKE
FIBROUS
CELLOPHANE
MICA
MACROFRACTURES/CARSIMS
FRACTURES
GRAVEL
SAND
Figure 6.B - LCM Spot Pill Selection Chart
PORES
ARPO
IDENTIFICATION CODE
PAGE
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Agip Division
REVISION
STAP -P-1-M-6160
6.3.1
95 OF 155
0
LCM Information
Materials
Type
Granulometry
(mm)
Seepage
Loss
Partial
Loss
CaCO3
Granular
50% @ +/- 0.05
X
CaCO3
Granular
CaCO3
Can Be
Acidised
Can Be
Used In
OBM
X
X
X
50% @ +/- 0.1
X
X
X
Granular
50% @ +/- 0.6 a3
X
X
X
Fine Nuts
Granular
0.16 - 0.5
X
X
Medium
Nuts
Granular
0.5 - 1.6
X
X
Coarse Nuts
Granular
1.6 - 5
X
Fine Mica
Lamellar
2-3
X
X
Coarse Mica
Lamellar
4-6
X
X
X
Vegetal
Fibres
Fibrous
5 - 15
X
X
Cellophane
Lamellar
10 - 20
X
X
X
X
X
X
X
LCM Efficiency
Kg/m3 OF LCM
6.3.2
Total
Loss
60
60
50
50
40
40
30
30
20
20
10
10
0
0
0
1
2
3
4
5
FRACTURE WIDTH (mm)
FIBROUS LAMELLAR GRANULAR
Figure 6.C - Fracture Dependent Efficiency Of LCM
6
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
96 OF 155
REVISION
STAP -P-1-M-6160
6.4
TROUBLESHOOTING GUIDE
6.4.1
Loss Of Circulation With Water Based Fluids
Treatment
Formulation
0
Operational Remarks
Allow 4-8 hours set time. Plan
further action to be taken.
Stand-By/Set Time
High Viscosity Fluids
Add contaminants (lime, salt,
etc.) to circulating fluids (lime,
salt, etc.) by increasing viscosity
and filtrate.
Viscosity at +/- 100sec.
LCM In Circulation
Approximately:
Shale shakers max., 10-12 mesh.
High Filtration Fluids
•
•
•
•
•
•
Bentonite 5%
Caustic Soda/Lime 10%
Diatomite 10%
Filtrate 30-50 cc
3
Volume, from 15 to 80 m of high
filtration fluid conditioned with 68% of LCM adequate for loss.
Do not use with unstable
formations.
•
•
•
•
•
•
•
Attapulgite 3-6%
(bentonite 1.5-6%)
Lime 0.15%
Diatomite 15%
*Mica 1-1.5%
*Granular 1-2.5%
*Fibrous 0.3-1%
*(chosen dependent on loss).
RIH or EDP on top loss, squeeze
with low pressure (starting with +/50psi @ 150ltr/min). Do not exceed
fracture pressure and maintain for
6-8hrs.
•
•
•
•
•
•
Same application procedure as
high filtration slurries with
o
temperature >60 C. It may develop
mechanical resistance.
Spot Pills With LCM
High Filtration Mixtures
(200-400cc API)
Very High Filtration Slurries
(>600cc API)
Fine mica 2%
Fine granulars 2%
Diatomite 30%
Lime 15%
Attapulgite 0-4%
*Granular 1-2.5%
*Fibrous 1%
*Lamellar 1%
*(chosen dependent on loss)
Displace loss zone if there is
excessive solids loading in the
annulus. Squeeze slowly with a low
pressure (50psi). Displace by
means of bit with no nozzle or with
nozzles >14/32".
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
Treatment
Diaseal M (Filtrate >1000cc
API)
Cement Gilsonite
0
Formulation
Operational Remarks
Formulation for the preparation of
3
1m final Diaseal M
Density Diaseal
kg/l
sacks
1.08
6
1.45
5
1.80
4
2.15
3
GEL Cement (Prehydrated
Bentonite)
97 OF 155
Barite
t
0
0.2
1.0
1.5
Same application procedure as
high filtration slurries.
Water
3
m
0.9
0.8
0.7
0.6
A higher slurry must be
prepared. The percentages
Density indicated, provide mechanical
resistance. Formation of slurries
with higher percentages of
kg/l
Bentonite may improve LCM
1.9
characteristics while decreasing
1.6
mechanical resistance
Formula for preparing slurries ('G'
cement)
Bent
Water
%
0
2
3
4
weight%
44
84
104
112
Slurry
Yield
l/100kg
75.7
116.5
136.9
157.25
1.51
1.45
Good mechanical resistance
associated with material control
action of gilsonite. As for
Density
cement plugs, it is advisable to
drill the loss zone and carry out
kg/l
the remedial procedure when
1.9
finished.
1.51
WOC for at least 8hrs.
Formulation for preparing slurries
('G' cement)
Bent
Water
%
0
50
100
200
weight%
44
61
78
112
Slurry
Yield
l/100kg
75.7
139.5
203.9
330.25
1.37
1.25
DOBC Squeeze (Diesel Oil
Bentonite)
Materials required for final vol. 1
3
m
3
• Diesel
0.72m
• Cement
450kg
• Bentonite 450kg
Apply DOBC/DOB squeeze
procedure. RIH or EDP on top
of loss zone. Plastic plug
volume to equal, or be greater
than, the hole below the loss
zone first and second plug, both
3
about 1m diesel.
DOB Squeeze
Materials required for final vol.
3
1m
3
• Diesel
0.70m
• Bentonite 800kg
When plug exits drill string,
close annular preventer and
pump fluids into annulus while
displacing the plug from the DP.
Drillpipe/ annulus ratio is 2:1,
about 600 l/min from drillpie and
300 l/min from annulus. After
displacing half the plug, reduce
pump rate by half. After
displacing 3/4 of the plug,
attempt a 'hesitation squeeze
pressure' with 100-500psi.
Underdisplace plug by one
barrel, POOH, allow 8-10hrs set
time.
ARPO
IDENTIFICATION CODE
PAGE
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.
ARPO
IDENTIFICATION CODE
PAGE
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)
ARPO
IDENTIFICATION CODE
PAGE
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)
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
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.
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
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.
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
103 OF 155
REVISION
STAP -P-1-M-6160
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.
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
104 OF 155
REVISION
STAP -P-1-M-6160
0
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.
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
8.
105 OF 155
0
DRILLING FLUID TRADEMARK COMPARISONS
Comparison of similar products and functional performances are compared in this section.
This comparison evaluates the various products with the differing concentrations required
against their relevant costs. Technical and/or economical analyses of all differing products
should be carried out with the concentrations required in similar operational conditions
and results.
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
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
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
Code
8.1.4
Description
107 OF 155
AVA
Bariod
0
Dowell
MI
BH Inteq
CMC
CMC
Filtrate Reducers
0401
Technic CMC
HV/LV
CMC
Cellex
CMC
0403
Semipurif.
CMC HV/LV
CMC-S
CMC S
CMC S
0405
Purified CMC
HV/LV
CMC-P
CMC P
CMC P
Driscose
0407
K-CMC LV/HV
Agipak
K-PAC R/LV
Agipak
0409
Purified PAC
R/LV
Visco 83
PAC
IDF-FLR
Polypac
Drispac
0411
Semi Purified
PAC R/LV
Policell
Barpol
IDPAC
0416
Na
Polyacrylates
Policell ACR
Polyac
Polytemp
SP 101
New-Trol
0418
Pregelat.
Starches
Victogel AF
Impermex
IDFLO LT
MY-LO-Gel
Milstarch
0417
Non-Ferm.
Starches
Victosal
0419
HT Starches
AVATEMP
Milpac
Flo-Trol
Dextrid
IDFLO
Polysal
IDFLO HTR
Thermpac UL
Permalose HT
Burastar
0421
AVAREX
Baranex
IDF HI-Temp
Resinex
Filtrex
Envir. Friendly
Lubricant.
Ecolube
Tork Trim II
Idlube
Lube 167
Mil-Lube
0303
EP Lubricants
AVALUB EP
EP Mudlube
0302
Various
Lubricants
AVA GreenLube
Lubrabeads
8.1.5
0301
8.1.6
HT Polyster
Mixture
Lubricants
Stick Less
Lube 100
Easy Drill
EP Lube
Lubrifilm
Graphite
Walnut Shells
Detergents/Emulsifiers/Surfactants
0307
Detergents
AVADETER
Condet
Drilling Deter.
DD
MD
0308
Non-ionic
Emulsifiers
TCS 30
Aktaflo E
IDMULL 80
DME
DME
0309
non-ionic
Surfactant.
AVAENION
Aktaflo S
Hymul
DMS
DMS
Salinex
Atlosol
Anionic
Surfactant
Trimulso
Clay Seal
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
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
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
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
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
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
ARPO
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PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
Code
111 OF 155
0
Description
AVA
Bariod
Dowell
MI
BH Inteq
System Name
AVA Core
Baroid 100
Trudrill
Versacore
Carbo-Core
EZ Core
Trumul
Versamul
Carbo-Tec
0601
Primary
Emulsifiers
0602
Secondary
Emuls.
AVAOIL-SE
Trusperse
0603
Wetting Agents
AVAOIL-WA
Trusperse
Versa SWA
0605
Organophil
Clays
AVABENTOILHY
Geltone III
Truvis
VG 69
Carbo-Gel
0608
Asph. Filtr.
Reducers
AVAOIL-FRHT
AK 70
Trudrill S
Versatrol
Carbo-Trol
Non-Asph. Filtr.
Red.
AVABIOFILHT
Baracarb
Truloss
LoWate/Fazegel
Carbo-Trol
(A9)
Truplex
Versa HRP
Carbo-Vis HT
0610
Thinners
Carbo-Mull
Defloc
Rheology
Modifiers
AVAOIL-VS
System Name
AVABIOL
Petrofree
Ultidrill
Novadrill
0601
Primary
Emulsifiers
AVABIO PRI.
EZ Mul NTF
Ultimul
Novatec-P
0602
Secondary
Emuls.
AVABIO Sec.
Ultimul II
Novatec-S
0603
Wetting Agents
AVABIO Wet
Ultisperse
Novawet
0605
Organophil
Clays
AVABIO Bent
Ultitone
VG 69
0608
Asphalt Filtrate
Reducers
0610
Geltone II
Vestrol
Non-Asphalt
Filtrate Reducers
AVABIOFILHT
Duratone HT
Thinners
AVABIO Thin
OMC 2/42
Rheology
Modifiers
AVABIO VIS-
Ultiflo
Versalig
Ultivis
Novamod
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
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
ARPO
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ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
9.
113 OF 155
0
DRILLING FLUIDS APPLICATION GUIDE
This document is an extract from a more comprehensive guide published by World Oil
relating to some of Eni-Agip's most important contractors, namely AVA, Baroid, Baker
Hughes Inteq, MI, Schlumberger, Dowell and IDF.
The product functions and systems, for which these products are employed, contained in
this section, are provided by the contractors named above.
ARPO
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ENI S.p.A.
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114 OF 155
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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
ARPO
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115 OF 155
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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
ARPO
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116 OF 155
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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
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
ARPO
IDENTIFICATION CODE
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117 OF 155
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APPLICATION GUIDE TO DRILLING FLUID PRODUCTS
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
ARPO
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118 OF 155
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APPLICATION GUIDE TO DRILLING FLUID PRODUCTS
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
ARPO
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APPLICATION GIUDE TO DRILLING FLUID PRODUCTS
X
X
X
X
X
X
X
X
EASY DRILL
ECOL LUBE
ENION
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
ENVIRO SPOT
ENVIRO THIN
ENVIRO TORQ
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
E.P. LUBE
E.P. MUDLUBE
EZ-CORE
X
X
X
X
X
X
X
X
X
X
X
X
EZ-MUD
EZ MUD DP
EZ MUL-NT
X
X
X
X
X
X
X
X
X
X
X
X
X
EZ MUL-NTE
FER-OX
FERROCHROME
X
FIBERTEX
FILTER-CHECK
FILTREX
X
X
B
FI
V
TE
FI
LU
LU
E
SU
FI
SU
SH
SU
P
TH
LU
LU
FI
LU
LU
E
X
X
X
SECONDARY
X
SECONDARY
X
PRIMARY
X
AIR AIRATED
X
OIL-BASE
X
WORKOVER
LOW SOLIDS
X
LIME-BASE
DRYOCIDE
DURATONE HT
DUROGEL
DISPERSED
POLYMER-BASE
NON-DISPERSED
FUNCTION
SALT SATURATED
FLUID SYSTEMS
PRODUCTS
V
SH
E
SH
V
SU
FI
FI
E
W
TH
FI
E
LO
FI
FI
V
TH
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
FLAKE
FLO-TROL
FLO-VIS
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
LO
V
V
FLOXIT
FOAM-BLASTER
X
X
X
X
X
X
X
X
X
FL
D
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
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
120 OF 155
REVISION
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APPLICATION GUIDE TO DRILLING FLUID PRODUCTS
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
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
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121 OF 155
REVISION
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APPLICATION GUIDE TO DRILLING FLUID PRODUCTS
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
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
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122 OF 155
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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
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
123 OF 155
REVISION
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APPLICATION GUIDE TO DRILLING FLUID PRODUCTS
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
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
124 OF 155
REVISION
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APPLICATION GUIDE TO DRILLING FLUID PRODUCTS
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
PAGE
ENI S.p.A.
Agip Division
125 OF 155
REVISION
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APPLICATION GUIDE TO DRILLING FLUID PRODUCTS
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
PAGE
ENI S.p.A.
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126 OF 155
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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
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
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127 OF 155
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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
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
128 OF 155
REVISION
STAP -P-1-M-6160
0
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
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
129 OF 155
REVISION
STAP -P-1-M-6160
0
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
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
130 OF 155
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
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
131 OF 155
REVISION
STAP -P-1-M-6160
0
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
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
10.
132 OF 155
0
DRILLING FLUID ANALYSIS
The contents of this section comply with specification API RP 13B-1 dated June 1st,
1990.
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
10.1
DRILLING FLUIDS
10.1.1
Density (Fluid Weight)
133 OF 155
0
Equipment Required:
•
Fluid balance
•
Pressurised balance
o
•
Thermometer 0-105 C
Calibration:
•
With fresh water at 21 C = 1kg/l
Procedure:
o
1)
2)
3)
4)
5)
6)
7)
Level with the instrument base.
Fill the balance cup with the drilling fluid to be tested.
Put on the cap and make sure some of the fluid is expelled through the hole. When
using the pressurised balance, use pump to add fluid into the cup under pressure.
Wash the fluid from outside of the balance.
Place the balance on the support.
Move the rider so that the bubble is on the centre.
Read the density value at the side of the rider toward the support.
Result:
•
•
10.1.2
Report the density to the nearest 10gr (0.1lbs/gal).
3
The balance provides the reading in ft and the gradient in psi per 1,000ft depth.
Marsh Viscosity
Equipment Required:
•
Marsh Funnel
•
Chronometer
o
•
Thermometer 0-105 C
Calibration:
•
With fresh water at 21 C, /4 gallon = 26(+/- 0.5) secs.
Procedure:
o
1)
2)
3)
4)
5)
1
Record the temperature of the sample.
Keep the funnel upright.
Close the orifice with a finger.
Pour non-gelatinised fluid through the screen.
Remove the finger and measure the number of seconds required for fluid to fill the
1
receiving vessel, commonly /4 gallon (946 cc).
Results:
Viscosity is recorded in seconds.
•
•
1
API regulations indicate /4 gals (946).
Eni-Agip generally specifies 1 litre (1,000cc).
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
10.1.3
134 OF 155
0
Viscosity, Yield Point, Gel Strength
•
•
•
•
Apparent Viscosity
•
Plastic Viscosity
•
Yield Point
Equipment Required:
Gels Strength
K (Consistency Index)
n (Flow Index)
•
Rotational viscosimeter (Fann)
(2)
•
Thermostatic cup
Calibration:
(1)
•
•
Chronometer
o
Thermometer 0-105 C
•
With fluids of known viscosity (Silicon Oils)
(3)
•
With a suitable mechanical calibration kit
Procedure:
1)
2)
3)
4)
5)
6)
7)
8)
9)
10)
11)
12)
Record the fluid sample point.
Place the sample in a suitable container.
Place the rotor exactly at the scribed line.
Record the temperature of the sample.
With the rotor rotating at a speed of 600 RPM, wait for reading to become a steady
value.
Change to 300 RPM, and again wait for reading to reach a steady value.
Stir the fluid at high speed for 10 secs.
Allow the fluid to stand undisturbed for 10 secs.
Shift to 3 RPM and record the maximum reading.
Re-stir the fluid at high speed for 10 secs.
Allow the fluid to stand undisturbed for 10 secs.
At 3 RPM again, record the maximum reading.
Alternative Steps For Oil Based Fluids:
1)
2)
3)
Results:
Place the fluid sample in the thermostatic cup.
Place rotor exactly at the scribed line.
(4)
Adjust the thermostat to the pre-selected temperature , and record on the report.
Apparent Viscosity (cP)
Plastic Viscosity (cP)
Yield Point (lbs/100sqft)
Gels Values (lbs/100sqft) at 10”
and 10
n (Dimensionless)
. n
K (lbs S /100sqft)
=
=
=
=
(Reading at 600rpm) /2
(Reading at 600rpm) - (Reading at 300RPM)
(Reading at 300rpm) - (Plastic Viscosity)
(Reading at 3rpm) after 10” and at 10’
=
=
3.32 log of reading at 600rpm/Reading at 300rpm
(Reading at 600rpm/1020)
Conversion Factors:
2
(1)
(2)
(3)
(4)
/2
=
lbs/100ft
n
2
lbs* s /100ft
*4.79
=
2
lbs100ft
*0.48
=
Preferably at six speeds.
Must be used with oil based fluids
Recommended if used at the rig site.
o
o
120 +/- 2 F, 150 +/-2 F.
2
+/- (g/100 cm )
n
2
(dyne*s /cm )
Pa (pascal)
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
10.1.4
135 OF 155
0
API Filtrate
Equipment Required:
•
Filter press with internal diameter of 3", filter area of 7.1 +/- 0.1 in
•
Paper filter, Whatman No 50 or S&S No 576 diameter 90mm
•
30min timer
•
10 or 25cc graduated cylinder
Calibration:
2
•
Verify the accuracy of the filter press manometer and filtrate area.
Procedure:
1)
2)
3)
4)
5)
1
Pour the fluid into the dry filter press until it is /2 inch from the top.
Place the cylinder at the filtrate exit.
Apply a pressure of 100 +/- 5 psi for 30secs.
After 30 ins, measure the volume of filtrate and release the pressure.
Remove the paper from filter and wash the filter cake .
Result:
•
•
•
•
Record the fluid temperature at the start.
Report the filtrate volume in cc.
Report the thickness of the filter cake in ?/32".
2
If filtrate area is 3.5in , double the filtrate volume.
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
10.1.5
136 OF 155
0
HPHT Filtrate
Equipment Required:
•
•
•
•
•
•
2
A complete HP/HT filter press with a filter area of 3.5 or 7.1in ;
CO2 source (not AOTE, only CO2)
Paper filter, Whatman No 50 or S&S No 576 diameter 90mm
Pressurised connection cell
30 min timer
25 or 50cc graduated cylinder
•
High speed stirring unit
o
Procedure to Test at Max. Temperature of 300 F:
1)
2)
3)
4)
5)
6)
7)
8)
9)
10)
11)
12)
13)
14)
15)
16)
17)
18)
19)
o
Pre-heat the heating jacket to 10 F above the selected test temperature.
Stir the fluid at a high speed for 10mins.
1
Fill the cell up to /2" from the top.
Place filter paper.
Complete the assemble of the cell.
Place the cell into the heating jacket with both the top and bottom valves closed.
Place the pressurised cell to collect the filtrate.
Apply pressure of the top with not less than 100psi with valves closed.
Open the top valve and apply a pressure to the fluid while heating it to the selected
temperature. Note: Total time of heating should not exceed 1hr.
When the sample pressure reaches the set temperature, increase the pressure of
the top pressure to 600psi.
Open the collector valve to start the filtration.
Collect the filtrate for 30mins.
o
Maintain the pre-selected test temperature to within +/- 5 F.
If back pressure increases over 100psi, reduce the pressure by draining some
filtrate from the graduated cylinder.
At the end of the test, close both valves of the filter press.
Recover all the filtrate in the graduated cylinder.
Bleed the pressure from both regulators.
Allow sufficient time for the cell to cool before draining the internal pressure and
open the cell.
Recover the cake and wash it with a gentle stream of water .
(6)
Results :
•
•
•
•
(6)
Record temperature and test pressure.
Report the filtrate volume in cc.
Report the thickness of the filter cake in ?/32".
2
If filtrate area is 3.5 ins , double the filtrate volume.
HP/HT filtrate is commonly carried out at 500psi (35atm) and at 300oF (149oC). It aims to
evaluate the filtrate reducer performance at a temperature where most of the cellulose
polymers degrade, thus allowing the use of appropriate filtrate reducers.
As for oil based fluids, HP/HT filtrate represents an important index of emulsion stability.
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
10.1.6
137 OF 155
0
Oil, Water, Solids Measurement
Equipment Required:
•
•
•
•
•
•
•
Procedure:
1)
2)
3)
4)
5)
6)
7)
8)
9)
10 to 20cc retort (required accuracy +/- 5%)
10 or 20cc collection cylinder (required accuracy 0.1 and 0.2cc respectively)
Fine steel wool
Silicon grease
Spatula with a blade shaped to fit inside the dimensions of the retort sample cup
Defoamer
Pipe cleaner
Thoroughly check that retort is clean, dry and operating.
Collect a sample of fluid filtered through a 20 mesh screen on the marsh funnel.
If the fluid sample is aerated, add some defoamer to about 300cc of the fluid and
slowly stir for 2-3 mins.
Lubricate the threads.
Fill the retort with fluid.
Allow an overflow of the sample through the hole in the lid. Wipe the overflow from
the sample cup and lid.
Screw the retort cup onto the retort chamber by positioning a ring of steel wool into
the chamber.
Heat the retort and collect the fluid into the dry liquid receiver.
Continue heating for 10mins after the last recovered fluid. Note: If the recovered
fluid contains solids, the test must be repeated .
Results:
Volume percent water
Volume of oil:
(7)
Volume percent solids
(7)
=
100 (volume of water in the fluid)/volume of the sample
=
100 (volume of oil in the fluid)/volume of the sample
=
100 - (vol. percent water + vol. percent oil)
The solids percentage, as calculated above, is the difference between the volume of water
and volume of oil and the total volume of the sample. The calculation does not make any
difference between the solids and salts which may have been dissolved. To correct solids
from NaCl, for every 10gr/l, deduct 0.3% from the solids calculated by means of the retort.
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
10.2
WATER-BASED FLUIDS
10.2.1
Sand Content Estimate
138 OF 155
0
Equipment Required:
•
A sand screen set consisting of a 200 mesh sieve of 2.5" diameter, a funnel to fit
the screen, a glass measuring tube with indicated marks relating to the quantity of
fluid and water to be reached. In addition, the tube must have graduations from 0%
to 20% which immediately allows the reading of sand percentage .
Procedure:
1)
2)
3)
4)
Fill the glass measuring tube to the indicated mark with the fluid.
Add water to relating mark.
Close the tube and shake vigorously.
Pour the mixture into the screen and discard the fluid. Repeat until the wash water passes
through clear.
5)
Wash the sand retained on the screen.
6)
Fit the funnel on the screen.
7)
Turn upside down the funnel and the screen onto the tube.
8)
Wash the sand into the tube by collecting water and solids in the tube.
9)
Allow sand to settle.
10) Read the percent by volume of the sand from the graduation .
Results:
•
•
Report the sand contents of the fluid in percent by volume.
Report where the fluid was caught.
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
10.2.2
139 OF 155
0
pH Measurment
Equipment Required:
•
pH paper test strips which permit estimation of pH to 0.5/0.2 units
(9)
•
Glass-electrode pH meter
•
Buffet solutions according to the indications supplied with the instruments .
Procedure:
(8)
•
Using paper test strips:
1)
Place a 2cm strip on the indicator paper on the surface of fluid.
2)
Allow it to remain until the fluid has wetted the surface of the paper (+/-30").
3)
Compare the colour standards provided on the side of the strip with the test
strip.
•
Glass-electrode pH meter.
1)
Make the necessary adjustment to standardise the meter with the solutions
(10)
according to the directions supplied with the instrument .
2)
Insert the electrode into the fluid contained in a beaker.
3)
Stir the fluid around the electrode by rotating the beaker.
4)
After the meter reading becomes constant, record the pH .
Results:
•
(8)
(9)
(10)
As for pH determination with paper test strips, record the fluid pH to the nearest
0.2/0.5 units.
•
As for pH determination with glass-electrode pH-meter, record pH to the nearest 0.1
unit.
The paper strip method may not be reliable if salt concentration of the sample is high.
The electrometric method is subject to error in solutions containing high concentrations of
sodium ions, unless a special glass electrode is used. Suitable correction factors must be
applied.
For accurate pH readings, the test fluid, buffet solutions and reference electrode must all be
at the same temperature.
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
10.2.3
140 OF 155
0
Methylene Blue Capacity Determination
Equipment Required:
•
•
•
•
•
•
•
Reagents:
1cc syringe.
250cc Erlenmeyer flask.
1cc Serological (graduated) pipette.
50cc graduated cylinder.
Glass stirring rod.
Hot plate.
Paper filter, Whatman No. 1 or equivalent, 11cm in diameter .
•
Methylene blue solution, 1cc = 0.01 milli-equivalents.
•
Hydrogen peroxide, 3% solution.
•
Sulphuric acid, 5N .
Procedures:
1)
2)
3)
4)
5)
6)
7)
8)
9)
10)
11)
Place 1cc of fluid or more (or suitable volume to require 10cc of blue methylene) in
the Erlenmeyer flask.
Add 15cc of Hydrogen peroxide.
Add 0.5cc of sulphuric acid.
Stir.
Boil for 10mins.
Add blue methylene solution. After each addition of 0.5cc, swirl the content for
about 30secs.
Remove one drop of fluid with the glass stirring rod and place it on the filter paper.
The end point is reached when the dye appears as a blue ring surrounding the dyed
solids placed on the filter paper.
When the situation as described in step 8 occurs, shake the flask for an additional
2mins and repeat step 7. If the ring is again evident, the end point has been
reached.
If the ring does not appear, repeat steps 6 and 7. Continue shaking the flask for
2mins until a drop shows the blue tint.
Record the number of cc of blue used to reach the end step .
Results:
Cation exchange capacity (CEC)
MBT (Bentonite equivalent) in lbs/bbl
MBT (Bentonite equivalent) in kg/m
3
=
cc of methylene/cc of fluid
=
CEC X 5
=
CEC X 14.25
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
10.2.4
141 OF 155
0
Chloride Content Determination
Equipment Required:
•
•
•
•
Reagents:
1cc pipette.
1cc serological (graduated) pipette.
100-150cc beaker (or a white vessel).
Glass stirring rod .
•
•
•
•
Procedure:
Silver nitrate solution with known titration.
Potassium chromate indicator solution.
Sulphuric acid: N/50.
Phenolphthalein indicator solutions .
1)
2)
3)
4)
5)
6)
7)
8)
Place 1cc (or more) of filtrate into the beaker.
Add 2 or 3 drops of phenolphthalein.
If the indicator turns pink, add sulphuric acid drop by drop until the colour is
discharged.
dilute with 25-50cc of distilled water.
Add 5-10 drops of potassium chromate.
Titrate with the addition of silver nitrate until colour changes from yellow to
orange/red and persists for 30secs.
Record the number of cc of silver nitrate required to reach the end point.
If over 10cc of silver nitrate are required to reach the end point, repeat the test with
a smaller sample of filtrate .
Results:
Chloride gr/l
=
NaCl gr/l
=
(11)
cc AgNO3 (normality of solutions) 35.453
/(cc of filtrate)
(12)
cc AgNO3 (Normality of solution) 58.443
/(cc of filtrate)
Solutions and Conversion Factors:
Concentration of AgNO3 commonly required:
(11)
(12)
•
0.1N
Chlorides (Cl-) gr/l
Salt (NaCl) gr/l
=
=
(cc AgO3 x 3.545) / (cc of filtrate)
(cc AgNO3 x 5.844) / (cc of filtrate)
•
0.282N
Chlorides (Cl-) gr/l
Salt (NaCl) gr/l
=
=
10 x cc AgNO3 / (cc of filtrate)
10 x cc AgNO3 x 1.65 / (cc of filtrate)
•
0.0282 N
Chlorides (Cl-) gr/l
Salt (NaCl) gr/L
=
=
cc AgNO3 / (cc of filtrate)
cc AgNO3 x 1.65 / (cc of filtrate)
PM Cl
PM Cl
=
=
PE Cl
PE Cl
=
=
35.45
58.443
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
10.2.5
142 OF 155
0
Calcium Hardness Determination
Equipment Required:
•
•
•
•
•
•
•
Reagents:
•
•
•
•
•
•
1cc pipette
1cc graduated pipette
1cc serological (graduated) pipette
100-150cc beaker
Glass stirring rod
*Two 10cc graduated pipettes
*Hot plate
0.01 Molar EDTA solution
Buffer solution, pH 10
Hardness indicator (Black Eriochrome T or similar)
(13)
Sodium Hypochlorite, solution at 5.25%
(14)
*Galcial acetic acid
*pH paper strip
(15 )
* equipment and reagents required if filtrate is coloured
Procedure:
1)
2)
3)
4)
5)
Place 1 cc (or more) of filtrate into the beaker
Dilute to 30-40 cc with distilled water
Reach pH 10 with buffet solutions
Add an adequate quantity of indicator
Titrate with EDTA until colour changes from pink-red to light blue-blue.
Procedure for Filtrate Coloured
1)
2)
3)
4)
5)
6)
7)
(16)
:
Place 1cc of filtrate into the beaker.
Add 10cc of sodium ipochlorite and mix.
Add 1cc of acetic acid and mix.
Boil for 5mins. Maintain the volume by adding distilled water.
Verify if hypochlorite is totally discharged with the pH paper strip. If the paper strip
becomes white, boil for longer.
Cool the solution.
Continue as indicated from step 3 in the normal procedure .
Results:
Total hardness (gr/l Ca++)
(13)
(14)
(15)
(16)
=
cc 0.01 M EDTA x 0.4/cc of filtrate.
In the same cases, ipochlorite can be contaminated by calcium, verify.
Avoid all contact with your skin.
It is used only if coloured filtrate does not allow the evaluation of colour change.
The analysis must be carried out in a well ventilated placed. Do not breathe in vapours.
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
10.2.6
143 OF 155
0
Calcium And Magnesium Determination
Equipment Required:
•
•
•
•
•
Reagents:
1cc pipette
5 cc graduated pipette
100-150cc beaker
Glass stirring rod
10cc serological (graduated) pipette
•
0.01 Molar EDTA solution
•
Buffer solution: pH 10
•
NaOH drops or solution
•
Total hardness indicator (Black Eriochrome T or similar )
Procedure for Determining Calcium:
1)
2)
3)
4)
5)
6)
7)
8)
Determine the total hardness as described in the related procedure.
Record as ‘a’ the number of cc required.
Place a volume of filtrate identical to that required for determining the total
(17)
hardness .
Dilute to 30-40cc with distilled water.
Increase pH to 12 by using NaOH.
Add the calcium indicator (with calcine or calver II).
Titrate with 0.01 M EDTA until colour changes from green to pink-brown in case of
calcine, otherwise from pink to blue in case of Calver II.
Record as ‘b’ the number of cc required .
Results:
(17)
‘b’
=
cc of EDTA required for calcium
Calcium (gr/l Ca++)
=
‘b’ x 0.04/cc of filtrate
‘a’ -’b’
=
cc of EDTA required for magnesium
Magnesium (gr/l Mg++)
=
‘a’ - ‘b’ x 0.243/cc of filtrate
Also in this case, coloured filtrates may be applied.
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
10.2.7
144 OF 155
0
Alcalinity, Excess Lime, Pf, Mf, Pm Measurment
Equipment Required:
•
•
•
•
•
•
Reagents:
100-150cc pottery or plastic vessel
1cc pipette
2cc syringe
10cc graduated pipette
Glass stirring rod
10 cc serological (graduated) pipette
•
Sulphuric acid, N/50 (0.02 N)
•
Phenolphthalein indicator solution
(18)
•
Methyl orange (or bromocresol blue) indicator solution
Procedure:
•
Pf
1)
2)
3)
4)
•
Mf
1)
2)
3)
•
Pm
1)
2)
3)
4)
5)
Interpretation:
•
•
(18)
(19)
(20)
Place 1cc of filtrate into the vessel.
Add 2-3 drops of phenolphthalein solution.
If the indicator turns red, add sulphuric acid until the colour disappears (pH
8.3).
Report as Pf the number of cc of N/50 sulphuric acid required.
To the sample which has been titrate to the Pf end point, add 2-3 drops of
methyl orange (or bromocresol blue).
Titrate with N/50 sulphuric acid until colour changes (pH 4.3) from yellow to
pink with methyl orange or from violet to yellow with bromocresol blue.
Report as Mf the total of cc N/50 sulphuric acid required to reach
phenolphthalein (Pf) end point, and methyl orange (Mf) end point.
Place a syringe of 1cc of fluid into the vessel.
Dilute the sample with 25-50cc of distilled water.
Add 4-5 drops of phenolphthalein.
If sample turns red, titrate by adding N/50 sulphuric acid until the colour
disappears (Ph 8.3).
Report as Pf the number of cc N/50 sulphuric acid required .
(19)
Alkalinity
Pf = 0
2Pf < Mf
2Pf = Mf
2Pf > Mf
Pf = Mf
Excess lime:
mg/l of OH
0
0
0
340 (2Pf - Mf)
340Mf
CO3
HCO3
0
1220Pf
1200Pf
1200 (Mf-Pf)
0
3
kg/m
lbs/bbl
=
=
1220 Mf
1220 (Mf-2Pf)
0
0
0
0.742 x (Pm - Fw x PF)
0.26 X (Pm - Fw x PF)
(20)
It is required for deeply coloured filtrates and the colour will change from violet to yellow.
Quantity can be measured with Garret Gas train.
Fw represents the liquid fraction measured with a retort.
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
10.2.8
145 OF 155
0
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)
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
10.2.9
146 OF 155
0
Semiquantitative Determination Of Sulphurs (Hatch Test)
Equipment Required:
•
•
•
•
Reagents:
The apparatus consists of a sample chamber provided with a holed cap for
positioning the lead acetate paper disks
Lead acetate paper disks
25cc graduated cylinder
5cc graduated syringe.
•
Sulphuric acid, N/10
•
Alkaseltzer (or sodium bicarbonate)
•
Defoamer.
Procedures:
1)
2)
3)
4)
5)
6)
7)
8)
9)
(24)
Using the syringe take away 2.5cc of fluid filtrate .
Place the sample into the chamber by diluting with 22.5cc of fresh water.
Position a lead acetate paper disk on the top cap of the chamber.
Wet the chamber walls with a film of defoamer.
Add 1cc of N/10 sulphuric acid.
(25)
Place a tablet of Alkaseltzer (or a bit of sodium bicarbonate ).
Screw the cap containing the lead acetate paper disk.
Allow the tablet to be completely dissolved.
Compare the colours of lead acetate paper disk with the hatch colour standards. If
(25)
colours are too dark, the test must be repeated with a diluted sample .
Results:
•
(22)
(23)
(24)
(25)
Results are compared against the hatch paper and be multiplied by 10. Values are
in mg/l of H2S.
Garret gas train can also be applied for quantitative evaluation.
Complete gas kits are available.
Soluble sulphurs are determined with filtrate analysis, while total sulphurs with fluid analysis.
Coloration is altered if cement is present in fluid. In this case the test may result positive
even in absence of H2S. Calculations of the concentration must be carried out on the
dilutions made.
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
10.2.10
147 OF 155
0
Fluid Corrosivity Analysis
FLUID CORROSIVITY ANALYSIS
EQUIPMENT
•
•
Corrosion rings pre-weight 4.5” (AISI 4140)
Drill string
PROCEDURE
•
•
•
•
•
•
Insert a corrosion ring into the tool joint closest to the drill bit.
Insert rings at halfway and at the top end of the drill string.
To keep in situ at least 40 hrs and max. of 10 days.
Recover the test pieces, dry them off with a cloth.
Notice the original weight and serial number.
For each corrosion ring, record :
1)
2)
3)
4)
5)
6)
Phase and depth of the ring.
Seria number and original weight.
Date and time of installation in the string
Date and time of recovery
Mud type, pH, Temperature in/out, flow rate.
Description of any treatment with corrosion inhibitors.
Send the test pieces to and the report data to: Eni-Agip/Corm
RESULT
•
Speed corrosion
lbs/ft3/year
mm/year
Interpretation
<1
<0.6
Low
1-2
0.6 - 1.2
Moderate
2-5
1.2 - 3.1
High
>5
> 3.1
Severe
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
148 OF 155
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.
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
10.3.2
149 OF 155
0
Fluid Alkalinity Determination
Equipment:
•
•
•
•
Reagents:
Half litre glass jar with lid.
5cc syringe.
5cc graduated pipette.
Magnetic stirrer with 38mm stirring bar (1.5in) .
•
•
•
•
Procedure:
Xilene/Hysopropanole mixture: 50/50.
Distilled water.
Phenolphthalein.
Sulphuric acid: 0.1 regular (N/10) .
1)
2)
3)
4)
5)
6)
7)
8)
9)
10)
Add 100cc xilene/hysopropanole mixture to half litre jar.
Add 2cc fluid with the syringe.
Swirl the mixture until it is homogenous.
Add 200cc distilled water.
Add 15 drops of phenolphthalein.
Slowly titrate with 0.1 N sulphuric acid, while stirring rapidly with magnetic stirrer.
Titrate until red colour just disappears for 1min.
Let the sample stand for 5mins, if no red colour re-appears, the end point has been
reached.
If colour reappears, titrate until it disappears again. Repeat steps 6,7,8.
If a third titration is necessary, call the total value of acid the end point, even if the
colour re-appears a fourth time .
Results:
Fluid Alkalinity:
Pom
=
cc 0.1N sulphuric acid/cc fluid sample.
Pom
=
cc 0.1N sulphuric acid/2.
Excess Lime:
lbs/bbl
kg/m
3
=
1.3 Pom.
=
3.7 Pom.
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
10.3.3
150 OF 155
0
Fluid Chloride Determination
Equipment Required:
•
•
•
•
•
Reagents:
Half litre glass jar with lid.
5cc syringe.
5cc graduated pipette.
10cc graduated pipette.
Magnetic stirrer with 38mm stirring bar (1.5in) .
•
•
•
•
•
•
Procedure:
Xilene/Hysopropanole mixture, 50/50.
Distilled water.
Phenolphthalein.
Sulphuric acid: 0.1 regular (N/10).
Potassium chromate indicator.
0.282N silver nitrate .
1)
2)
3)
4)
5)
Lead the alkaline test as indicated in the previous form.
Be sure acqueous solution pH is less than 7 by adding 1-2 drops of N/10 sulphuric
acid.
(28)
Add 10 to 15 drops of potassium chromate indicator .
(29)
While stirring rapidly, slowly titrate with silver nitrate .
When the pink salmon colour stabilises for at least 1min, then the end point has
been reached .
Results:
Fluid chloride (mg/l)
Whole fluid chloride (mg/l)
(28)
(29)
(30)
(31)
=
=
(30)
1000 (cc AgNO3 * PM Cl-)/cc fluid sample required.
(31)
10000 (cc AgNO3 0.282N )/2.
A further addition of potassium chromate may be required.
Rapid stirring is required. It may be necessary, however that the stirring is stopped
to allow separation of the two phases to occur.
Pm Cl = PE Cl = 35.45.
The normal 0.0282 N reagent is calculated as follows: 1cc AgNO3 equals 10g/l Cl.
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
10.3.4
151 OF 155
0
Calcium Determination
Equipment Required:
•
•
•
•
•
Reagents:
Half litre glass jar with lid;
5cc syringe
5cc graduated pipette
10cc graduated pipette
Magnetic stirrer with 38mm stirring bar (1.5in )
•
•
•
•
•
Procedure:
Xilene/Hysopropanole mixture, 50%/50%
Distilled water
1N hydroxide sodium (NaOH) 1N
Calcium indicator (Calver II)
(32 )
0.1M EDTA
1)
2)
3)
4)
5)
6)
7)
8)
9)
10)
11)
12)
Results:
Add 100cc of 50/50 xilene/hysopropanol mixture.
Add 2cc of fluid with syringe.
Shake vigorously, until the mixture is homogeneous.
Add 200cc distilled water.
Add 3cc 1N NaOH.
Add 0.1 - 0.25gr calcium indicator (Calver II).
Shake vigorously for 2mins.
Let the sample stand to allow the separation of the two phases to occur. If a
reddish colour appears in the aqueous phase, calcium is present.
Place the jar on the magnetic stirrer and drop in the stir bar.
Titrate with 0.1 M EDTA.
When the colour changes to blue-green, the end point has been reached.
Record the number of cc of 0.1M EDTA required .
Fluid calcium (mg/l)
sample
Whole fluid calcium (mg/l)
(32)
=
1000 (cc EDTA
*
Normal EDTA PMCa++)/cc of fluid
=
1000 (cc EDTA * 0.1 40/2cc
=
4000 (cc EDTA) 2cc
This EDTA solution is ten times more concentrated than the solution required for water based
fluids.
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
152 OF 155
REVISION
STAP -P-1-M-6160
0
APPENDIX A - DRILLING FLUID CODING SYSTEM
This coding system describes the Eni-Agip drilling fluid coding system currently in use and
how the system can be used for further developments of drilling fluids.
A.1.
CODE GROUPS
There are three groups in the system:
1
•
•
•
2
3
The first grouping represents the base fluid, such as fresh water, sea water,
diesel, etc. The base fluid must be included in the full code.
The second grouping represents the base fluid system, such as
lignosulfonate, gels, polymers, invert emulsion, etc. The base system again
must be included.
The third grouping describes the base system more precisely by providing
further information: i.e. the water/oil ratio in an invert emulsion, the type of salt
in a brine and underlining the specific treatment, such as addition of polymers,
soltex, lignosulfonates. The third group is included only if relevant information
is applicable.
If there is one or more special treatments, only the most significant of these will be
included. For example, DS-IE 80 signifies a diesel base, invert emulsion drilling fluid, with
a WO ratio of 80/20. If this drilling fluid is relaxed, the code would be DS-IE RF, as
'Relaxed Fluid' is to be considered a more significant characteristic than the W/O ratio.
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
REVISION
STAP -P-1-M-6160
A.2.
153 OF 155
0
EXAMPLE CODING
Consider the development of a drilling fluid, as follows:
1)
The code for sea water fluid with prehydrated bentonite is:
SW
2)
During drilling, if the fluid is treated with light additions of lignosulfonate, its code will
be:
SW
3)
GE
LS
Again during drilling, the addition of lignosulfonate will characterise the fluid further
and the code will be:
SW
4)
GE
LS
Finally, if lubricants are added, the code will be:
SW
GE
LU
ARPO
IDENTIFICATION CODE
PAGE
ENI S.p.A.
Agip Division
154 OF 155
REVISION
STAP -P-1-M-6160
0
APPENDIX B - ABBREVIATIONS
B.1.
AR
FLUID CODE ABBREVIATIONS
-
1
2
3
Base Fluid
Base System
Specific Treatment
Air
AR
-
Air
(- -) -
Non Specific
FW -
Fresh Water
AT
-
Aerated
CA
-
Calcium Carbonate
SW -
Sea Water
BR
-
Brine
CB
-
Calcium Bromide
BW -
Brine Water
CL
-
Chromelignin
CC
-
Calcium Chloride
DS
Diesel
CT
-
Cationic Polymers
CL
-
Chromelignin
-
LT
-
Low Toxicity Oil
DE
-
Modified Tannins (Desco)
KA
-
Potassium Acetate
EB
-
Ester
DF
-
Drilling Fluid
KB
-
Potassium Base (KOH)
OF
-
Poltolefine
GE
-
Bentonite-Base
KC
-
Potassium Chloride
UT
-
Olio Ultra LT
GG -
Guar Gum
KF
-
Potassium Formiate
GL
-
Glycol-Base
GL
-
Glycol-Base
GY
-
Gypsum-Base
LI
-
Lime
HT
-
High Temperature
LS
-
Lignosulfonate
IE
-
Invert Emulsion
LU
-
Lubricants
K2
-
Potassium Carbonate
NC
-
Sodium Chloride
KA
-
Potassium Acetate
NB
-
Sodium Bromide
KC
-
Potassium Chloride
PA
-
Polyanionic Pol.(PAC)
KF
-
Potassium Formiate
PN
-
Na Polyacrylates
LI
-
Lime-Base
PC
-
PHPA
LS
-
Lignosulfonate-Base
PK
-
Agipak (K-CMC/PAC)
LW
-
Low-Solids
PO
-
Generic Polymers (CMC)
-
NOTE:
MM -
Mud-Misting
RF
MR -
Morex-Base
RM -
Rheology Modifiers
Relaxed Filtrate
OB
-
Oil Base
RX
-
Ht Pol. Mixtures
PA
-
Polyanionic Pol.(PAC)
SX
-
Soltex
PC
-
PHPA
TA
-
Tannins
PK
-
Agipak (K-PAC, K-CMC)
XC
-
XCD Polymer
PO
-
Generic Polymers (CMC)
VB
-
Viscosity Base
ZB
-
Zinc Bromide
QU
-
Quebracho-Base
SF
-
Foam-Base
SS
-
Salt Saturated (NaCl)
XC
-
XCD Polymer
The oil/water ratio of a fluid with an oil numeric value, such as O/W =
70/30, will be expressed only by the first ratio, i.e. 70, omitting the later
30 ratio.
ARPO
IDENTIFICATION CODE
PAGE
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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