Completion Brine Challenges
for HTHP Applications
Presentation Overview
1. Brine Fluids & Properties
2. Displacement of Drilling Fluid
3. Brine Compatibility
4. Fluid Loss Control
5. Packer Fluids
6. Safety
2
Presentation Overview
6. Safety
Very important topic
Detailed considerations required
Subject for another discussion
3
Completion and Workover Brine
ZnBr2
Zinc
CaBr2 - ZnBr2
CaCl2 - CaBr2
CaBr2
CaBr2
Calcium
CaCl2 - CaBr2
CaBr2
CaCl2
CsHCO2
Formates
KHCO2
NaHCO2 - KHCO2
NaHCO2
NaBr
Sodium
NaCl - NaBr
KCl
8
NaC
l
10
12
14
16
Density, ppg
4
18
20
22
Are Crystallization Temperatures Important ?
Completion & Workover Fluids
Density
(ppg)*
CaCl2
(wt %)
CaBr2
(wt %)
TCT
(OF/OC)
*1.50 g/cc
12.5
12.5
12.5
12.5
34.40
32.20
22.84
00.00
10.80
13.13
20.55
41.55
60
44
15
-33
15.6
6.7
-9.4
-36.1
PCT Testing Apparatus
• Dual Piston
Pumps
• Rated
20,000+ psi
Environmental Chamber
Temperature to - 40°F
Optical View Cell
Rated to 20,000 psi
7
HPHT Hydrate Curves
30,000
10.0 ppg CaCl2
25,000
Pressure, psi
10.0 ppg CaBr2
20,000
8.33 ppg Water
15,000
Hydrate-Forming
Zone
10,000
Hydrate-Free
Zone
5,000
0
0
Green Canyon Gas
8
20
40
60
Temperature, °F
80
100
120
Calsep PVTsim
PCT
Density
(ppg)*
versus
CaCl2
(wt %)
Hydrate Potential
CaBr2
(wt %)
TCT
OC)
(OF
*1.50 g/cc
12.5
12.5
12.5
12.5
34.40
32.20
22.84
00.00
10.80
13.13
20.55
41.55
60
44
15
-33
PCT
9
15.6
6.7
-9.4
-36.1
Hydrate
Protection
Density Correction Calculation
D(C) = D(M) * [1 + Ve (T(M) - T(C) )]
D(M) = 16.4 ppg @ 85OF
D(C) = ? @ 60OF
V(e) = 2.52 * 10-4
D(60) = 16.4 * [1 + 2.52 * 10-4 ( 85 - 60 )]
D(60) = 16.4 * [1.0063] = 16.5 ppg
Ve (* 104)
Density
(ppg)
2.80
12.0
NaBr
2.39
11.5
CaCl2
2.50
15.0
CaBr2/CaCl2
2.54
2.71
2.78
17.5
18.5
19.0
ZnBr2/CaBr2/CaCl2
ZnBr2/CaBr2/CaCl2
ZnBr2/CaBr2/CaCl2
Brine
Wellbore Pressure Profile
Well Parameters
18,000 TVD, feet
370 BHT, °F
16,000 BHP, psi
300 Overbalance, psi
70 Surface Temperature, °F
Surface Density Required, ppg = ?
Average Brine Density, ppg
=?
Bottom Hole Density, ppg
=?
Wellbore Pressure Profile
Depth - ft
Temp - oF
Density - ppg
Δp - psi
Total - psi
0
720
1,440
2,160
2,880
3,600
4,320
5,040
5,760
6,480
7,200
7,920
8,640
9,360
10,080
10,800
11,520
12,240
12,960
13,680
14,400
15,120
15,840
16,560
17,280
18,000
70.0
82.0
94.0
106.0
118.0
130.0
142.0
154.0
166.0
178.0
190.0
202.0
214.0
226.0
238.0
250.0
262.0
274.0
286.0
298.0
310.0
322.0
334.0
346.0
358.0
370.0
17.52
17.48
17.45
17.42
17.39
17.36
17.32
17.29
17.26
17.23
17.20
17.17
17.13
17.10
17.07
17.04
17.01
16.97
16.94
16.91
16.88
16.84
16.81
16.78
16.75
16.71
0.0
654.0
652.8
651.6
650.4
649.2
648.0
646.8
645.6
644.4
643.3
642.1
640.9
639.7
638.5
637.3
636.1
634.9
633.7
632.5
631.2
630.0
628.8
627.6
626.4
625.2
0
654
1,307
1,958
2,609
3,258
3,906
4,553
5,198
5,843
6,486
7,128
7,769
8,409
9,047
9,684
10,320
10,955
11,589
12,221
12,853
13,483
14,112
14,739
15,366
15,991
Hydrostatic Pressure at
18,000 feet
15,991 psi
Average Fluid Density in
Wellbore
17.10 ppg
Surface Density
at
70°F
17.52 ppg (17.5)
Density at 60°F
17.56 ppg (17.6)
Wellbore Pressure Profile
Zero vs 300 psi Overbalance
Hydrostatic Pressure at 18,000 feet
15,991 psi
Hydrostatic Pressure at 18,000 feet
16,291 psi
Average Fluid Density in Wellbore
17.10 ppg
Average Fluid Density in Wellbore
17.42 ppg
Surface Density at 70°F
17.52 ppg (17.5)
Surface Density at 70°F
17.84 ppg (17.8)
Density at 60°F
17.56 ppg (17.6)
Density at 60°F
17.89 ppg (17.9)
Temperature - Pressure Factors
12,000 psi from 76°F to 345°F
198°F from 2,000 psi to 12,000 psi
Density
827 bars from 24OC to 174OC 1
92OC from 138 bars to 827 bars 1
Expansion Factors
(lb/gal)
NaCl
9.42
2.54
0.24
1.98
0.019
CaCl2
11.45
2.39
0.27
1.50
0.017
NaBr
12.48
2.67
0.33
1.67
0.021
CaBr2
14.30
2.33
0.33
1.53
0.022
16.01
2.27
0.36
1.39
0.022
19.27
2.54
0.48
1.64
0.031
Three Salt
Two Salt
1
2
3
3
2
SPE 12490 Krook & Boyce
Three Salt = ZnBr2/CaBr2/CaCl2
Two Salt = ZnBr2/CaBr2
a * 104
vol/vol/°F
A
lb/gal/100°F
Compressibility Factors
Brine
b * 106
vol/vol/psi
B
lb/gal/1000 psi
Trapped Annular Fluid
Fluid
Installation
Trapped Annular Fluid
Fluid
Installation
Pressure Changes
with increase
Temperature
Trapped Annular Fluid
Go to production
Temperature
increases
Fluid
Installation
Pressure Changes
with Temperature
Fishbone Diagram
Spacers
– Mud
Crude Oil
– Brine
Gravel Pack /
Frac Gel –
- Brine
Brine –
Control
Lines
Brine –
Hydraulic
Fluid
Formation
Gravel Pack /
Fluid Loss
Water
Frac Gel –
Control Pills
- Brine
- Formation &
- Formation
Form. Fluids
Fluids
Spacers
– Brine
Displacement
Perforation
Spacers
– Cement
Formation
(Clays)
- Brine
Mud
– Brine
Fluid Loss
Control Pills
- Brine
Mud Filtrate
- Brine
Gun Type
- Brine
Frac/Gravel Pk
Pre-Pack
Acid –
Formation &
Form. Fluids
Well Control
Fluid Loss
Control Pills
- Formation
Rock
Fluid Loss
Brine –
Control Pills
Elastomer - Sand Control
Oil
Gas
Tubing
Inhibitors –
Tubulars
Brine –
Tubulars
InsulGel –
Tubulars
Screens
After Syed Ali, Chevron
18
Displacement Considerations
Displacement Spacers
Size and weight of each spacer
Depth of well & circulation time
Spacer effective at BHT ?
Effective when contaminated with mud ?
How much mud contamination can be tolerated ?
21
Weighted Displacement System
Field Example
Spacer
Volume,
bbl
Base Oil
75
Separate mud from cleaning fluids
17.5 ppg Barite
50
Barrier spacer, offset density of base oil
12.0 ppg Barite
300
Improve hydraulics (563 bbl WS, 5-7/8”x41/2”), cost for SOBM or WBM
12.0 ppg HDWCF Type 1
125
Based on CaBr2 Brine
12.0 ppg HDWCF Type 2
125
Based on CaBr2 Brine
12.0 ppg
Viscous Pill
100
Separate spacer train from the 10.5 ppg
CaBr2 completion brine
Brine
SPE 99158
Comments
10.5 ppg CaBr2 completion brine
Wellbore Cleaning Tools
Enhancements to clean wellbores
Surface Filtration Equipment
Fishbone Matrix
Spacers
– Mud
Crude Oil
– Brine
Gravel Pack /
Frac Gel –
- Brine
Brine –
Control
Lines
Brine –
Hydraulic
Fluid
Formation
Gravel Pack /
Fluid Loss
Water
Frac Gel –
Control Pills
- Brine
- Formation &
- Formation
Form. Fluids
Fluids
Spacers
– Brine
Displacement
Perforation
Spacers
– Cement
Formation
(Clays)
- Brine
Mud
– Brine
Fluid Loss
Control Pills
- Brine
Mud Filtrate
- Brine
Gun Type
- Brine
Frac/Gravel Pk
Pre-Pack
Acid –
Formation &
Form. Fluids
Well Control
Fluid Loss
Control Pills
- Formation
Rock
Fluid Loss
Brine –
Control Pills
Elastomer - Sand Control
Oil
Gas
Tubing
Inhibitors –
Tubulars
Brine –
Tubulars
InsulGel –
Tubulars
Screens
After Syed Ali, Chevron
Formation Oil Compatibility
Surfactants in High Density Brine
Blank
Surf 1
Surf 2
Surf 3 Surf 4 Surf 5
Surf 6 HyPerm
` NoMul
Non-Emulsifying Surfactant Technology
Mini Oil-Compatibility Test Method
Crude Oils (6-15% wax & 4-14% asphaltene) / 15.4ppg Brine
(inhibited + non-emulsifier) @ 180oF
Before
mixing
After
mixing
10 min.
20 min.
30 min.
1 hour
3 hrs.
5 hrs.
7 hrs.
24 hrs.
Formation Water Compatibility
15.4 ppg Cesium Formate
Optimized Formulation #2
Formation Water @ 70°F
15.4 ppg Cesium Formate
Optimized Formulation #2
Formation Water @ 180°F
Significant
amount of
settled solids
Significant
amount of
settled solids
Significant
amount of
settled solids
Significant
amount of
settled solids
Clear
15.6 ppg Zinc-Based Brine
Formation Water @ 70°F
Clear
Clear
Clear
15.6 ppg Zinc-Based Brine
Formation Water @ 180°F
Clear
Clear
Clear
Principle Characteristics
Concentration, mg/L
Chloride
Bi-Carbonate
Sulfate
Sodium
Potassium
Calcium
Magnesium
Barium
Strontium
147,000
470
200
90,600
500
8,930
1,500
208
215
pH
7.33
Clear
SPE 103209
Downhole Debris
Case History #4
Packer Plug
Retrieval Tool
SPE 112479
Zn5(OH)8Br2·H2O
Fishbone Matrix
Spacers
– Mud
Crude Oil
– Brine
Gravel Pack /
Frac Gel –
- Brine
Brine –
Control
Lines
Brine –
Hydraulic
Fluid
Formation
Gravel Pack /
Fluid Loss
Water
Frac Gel –
Control Pills
- Brine
- Formation &
- Formation
Form. Fluids
Fluids
Spacers
– Brine
Displacement
Perforation
Spacers
– Cement
Formation
(Clays)
- Brine
Mud
– Brine
Fluid Loss
Control Pills
- Brine
Mud Filtrate
- Brine
Gun Type
- Brine
Frac/Gravel Pk
Pre-Pack
Acid –
Formation &
Form. Fluids
Well Control
Fluid Loss
Control Pills
- Formation
Rock
Fluid Loss
Brine –
Control Pills
Elastomer - Sand Control
Oil
Gas
Tubing
Inhibitors –
Tubulars
Brine –
Tubulars
InsulGel –
Tubulars
Screens
After Syed Ali, Chevron
Darcy’s Law: Linear Flow
Q = [ K A (pe – pwf) ] / [ μ L ]
Where:
Q =
K =
Pe =
Pwf =
μ =
A =
L =
Production rate in liters/sec
Permeability, mD
Reservoir pressure, atm
Flowing wellbore pressure, atm
Viscosity in cP
Surface area in cm2
Length in cm
Radial Flow:
Q = 7.082 K H (Pe – Pwf) / [β μ (ln (re/rw)) +S]
Effect of Differential Pressure
Differential Pressure vs Fluid Loss
160
Fluid Loss, bph
140
500 mD
250 mD
120
100 mD
100
50 mD
80
60
40
20
0
0
200
400
600
Differential Pressure, psi
800
1,000
Non-Cross-Linked Solids-Free
Fluid Loss Control Pills
12.5 ppg Sodium Bromide + Viscosifier
Viscosity, cP a@ 100 1/sec.
1000
100
Thermally Enhanced
Pure NaBr
10
100
150
200
250
300
Temperature. °F
350
400
450
Sized Solid FLC Materials
Calcium Carbonate, CaCO3
Salt, NaCl
Oil Soluble Resins
Solid Bridging Materials
Against Formations
Particle Size For Effective FLC
50
Particles 1/2 Pore Size
Particle Size, Microns
45
Particles 1/3 Pore Size
40
Particles 1/7 Pore Size
35
30
25
20
15
10
Formation Sand
5
0
0
1
2
3
4
5
6
Permeability, Darcy
7
8
9
10
Fishbone Matrix
Spacers
– Mud
Crude Oil
– Brine
Gravel Pack /
Frac Gel –
- Brine
Brine –
Control
Lines
Brine –
Hydraulic
Fluid
Formation
Gravel Pack /
Fluid Loss
Water
Frac Gel –
Control Pills
- Brine
- Formation &
- Formation
Form. Fluids
Fluids
Spacers
– Brine
Displacement
Perforation
Spacers
– Cement
Formation
(Clays)
- Brine
Mud
– Brine
Fluid Loss
Control Pills
- Brine
Mud Filtrate
- Brine
Gun Type
- Brine
Frac/Gravel Pk
Pre-Pack
Acid –
Formation &
Form. Fluids
Well Control
Fluid Loss
Control Pills
- Formation
Rock
Fluid Loss
Brine –
Control Pills
Elastomer - Sand Control
Oil
Gas
Tubing
Inhibitors –
Tubulars
Brine –
Tubulars
InsulGel –
Tubulars
Screens
After Syed Ali, Chevron
Brine Corrosion Rates
N-80 Steel, 30 Days, MPY, No Inhibitor
Density
Brine Type (ppg)
70°F
150°F
250°F
300°F
350°F
NaCl
10.0
0.5
1.5
0.2
0.1
0.1
NaCl/NaBr
11.2
0.4
0.7
0.1
0.1
0.1
NaBr
12.4
0.3
0.4
0.1
0.1
0.1
CaCl2
11.6
0.1
0.2
0.7
0.9
1.9
CaCl2/CaBr2
13.6
0.3
0.9
1.6
1.6
3.0
CaCl2/CaBr2
15.1
0.1
0.5
2.4
2.9
6.6
Corrosion Data, Zinc Based Brines
N-80 Steel, MPY, Inhibited with NaSCN
HyCal III
250°F
350°F
400°F
Density (ppg)
30 Days
30 Days
180 Days
15.5
16.5
17.5
18.5
1.9
1.2
5.3
2.4
7.1
7.6
7.9
9.9
1.6
3.1
5.7
6.2
Casing & Tubular Applications
Mild Environment
J-55
N-80
P-110
SSC concerns
(medium PSI & temp.)
L-80
C-90
SSC concerns
(high PSI & temp.)
C-100
C-110
Wet CO2
13% Chrome &
0-5% Ni & 0-2% Mo
22-25% Chrome &
5-7% Ni & ~3% Mo
16-25% Chrome &
35-60% Ni & 3-16% Mo
Wet CO2 & little H2S
More Corrosive Environments
1999
2001
13Cr 110ksi
2003
13Cr 95ksi
Standard Uninhibited Zinc-Based Brines
Standard Brine Formulations
C4130 Coupons
Corrosion Rate, mpy
90
80
70
350°F
60
300°F
50
40
30
20
10
0
17.0
17.2
17.4
17.6
17.8
18.0
Brine Density, ppg
18.2
18.4
Advancement for Zinc-Based Brines
Brine Formulations
Corrosion Rate, mpy
90
80
C4130 Coupons
350°F, Standard
70
60
350°F, Modified
50
40
30
20
10
0
17.0
17.5
18.0
Brine Density, ppg
18.5
Iron Pillar
On the outskirts of Delhi, this 7.3 meter high
pillar was forged from a great number of
hammered billets over 1,600 years ago.
It is 6.5 tons of 99.72% pure iron.
48 cm diameter tapers to 29 cm at the top.
It shows no sign of corrosion.
Iron Pillar
“Misawite", a
compound of
iron, oxygen
and
hydrogen,
forms the
protective
shield.
Protective film
has grown just
one-twentieth
of a millimeter
thick.
43
44