Brines and Other Workover Fluids

Brines and Other Workover Fluids
•
•
•
•
•
•
•
•
Purposes
Selection
Filtration needs
Placement
Fluid Loss Control
Cleanup and Displacement of Muds
Limitations
Alternatives
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1
Purposes of Brines
1. Mud displacement prior to cementing,
2. Debris removal,
3. Controlling formation pressures during completion
and intervention operations,
4. Enabling repair operations as a circulating or kill
fluid medium,
5. As packer fluids,
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2
Purposes of Brines (cont.)
6. In some stimulations as base fluids;
7. Enable cleanup of the zone prior to running screens;
8. Reduce friction while running screens & equipment;
9. Avoid damaging the well after completion,
stimulation, or repair;
10. Allow other well operations to be conducted.
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Will Circulating a Well Really Clean It Out?
• Not necessarily.
• Clean-out efficiency depends on:
– Ability to remove the solids from returning fluids,
– Fluid hydraulics - the flow rates in every section,
– Ability to disperse, then lift solids out of the well,
– Ability to effectively remove the dope, mud cake,
residues, etc., from the pipe walls.
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Returns from a cleanout scraper run – dope, wireline grease,
rust, mud, etc., are common components.
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Selection of the Brine
•
Must Satisfy:
1. Well control at every phase of the operation.
2. Must be able to filter the brine to 5 to 10 microns with
beta of 1000.
3. Compatibility with the formation, well equipment and all
operations and fluids.
4. Corrosion and scale dropout must be controllable.
5. Cleanup requirements from the formation
6. Cleanup and disposal requirements at the surface
7. Cost and availability to fit the well.
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Brine Types and Respective Density Ranges
Brine Type
Chloride Salt
Chloride Salt
Chloride Salt
Bromide Salt
Mix
Formate Salt
Formate Salt
Formate Salt
Formate Salt
Formate Salt
Chloride Salt
Bromide Salt
Mix
Bromide Salt
Mix
3/14/2009
Mix
Brine Formula
Density Range (ppg)
NaCl
8.4 - 10.0
KCl
8.4 - 9.7
NH4Cl
8.4 - 8.9
NaBr
8.4 - 12.7
NaCl/NaBr
8.4 - 12.5
NaHCO2
8.4 - 11.1
KHCO2
8.4 - 13.3
CsHCO2
13.0 - 20.0
KHCO2/CsHCO2
13.0 - 20.0
NaHCO2/KHCO2
8.4 - 13.1
CaCl2
8.4 - 11.3
CaBr2
8.4 - 15.3
CaCl2/CaBr2
8.4 - 15.1
World Oil, Modern Sand
ZnBr2
12.0 - 21.0
Face Completion, 2003
ZnBr2/CaBr2
12.0 - 19.2
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ZnBr2/CaBr2/CaCl2
12.0 - 19.1
Lower Density Fluids
Nitrogen gas
water foam
kerosene and diesel
20o crude
30o crude
0.1 to 2.6 lb/gal
3.5 to 8.3 lb/gal
6.7 to 7.1 lb/gal
7.8 lb/gal
7.3 lb/gal
Most low density fluids are not be usable because of
migration, flash point, or stability issues.
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Displacement and Pill Design
• The displacement must be designed to obtain
effective mud removal (dispersement and lift)
& water wetting of casing.
• Keys:
– disperse and thin the drilling fluid
– compatibility with the following fluids (brine, acid, cement,
etc.
– lift out debris and junk
– water wet pipe
– remove pipe dope effectively
– displace the mud
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Source: Wellcert
9
Brines for Displacement
1.
A thinning base fluid flush.
2.
An effective brine transition system must further thin and strip the mud
and create wellbore displacement.
3.
A carrier spacer must sweep out the solids and clean any coating from the
pipe or rock that could cause damage problems.
4.
A separation spacer must do the final cleaning and separate the residual
mud from the brine.
5.
The brine must sweep the spacer out. At this point the well should be
clean.
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Cleaning and Transition Spacers
Spacer Type
Function
Minimum
Annulus
Coverage
WBM
OBM
Base Fluid
Thin & mud
condition – start
dispersement
250 to 500 ft
Water, and
some brines
Base oil
(composition
varies)
Transition
Mud to spacer,
500 to 1000’
cuttings removal
Viscous pill
Viscous Pill
Wash
Clean pipe
500 to 1500’
Water+ WBM
surfactant
Oil + OBM
surfactant
Separation
Separate wash
from completion
brine
500 to 1000’
Viscous pill
Surfactant gel?
Some water
gels if compat.
Completion
Fluid
Completion fluid Fill
Completion
Fluid
Completion
Fluid
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Brine Flush Contact Times
9-5/8” casing in 12-1/4” hole, annular area = 0.3 ft2
Pump Rate,
bpm
Annular
Velocity,
ft/min
Barrels
Pumped
Column
Length, ft
Contact
Time,
minutes on
one foot.
8
150
200
3743
25
10
187
400
7486
40
12
225
400
7486
33
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Flow profile in a well with decentralized pipe. Note That most
of the flow comes along the top of the pipe. This affects
cleanup and residence time of the fluid on the wellbore. The
lower section of the wellbore may remain buried in cuttings
and never have contact with any of the circulated fluids.
Major flow area
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Displacement of the annulus to displace fluids and mud cake depends partly on velocity.
The annulus changes as casing replaces the drill string. As the annular space decreases –
velocity for any rate increases in the smaller area and the back pressure on the bottom hole may
also increase.
Circulating down the casing and up the small annulus
can produce very high friction pressure and raised
BHP.
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Displacement Considerations
• Well control is key consideration in selection of
the pill sequence.
• In many cases, it is only possible to get thin, light
fluids into turbulence
• Pumping fluids to displace oil based fluids
without suitable surfactant/solvent packages to
disperse the mud can result in sludges that are
insoluble except in aggressive solvents
• For deepwater wells, low temperatures can
impact surfactant effectiveness
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Carrying Capacity
• Pills in turbulence lose carrying capacity if
the annular velocity drops below that
required for turbulence (e.g. entering
larger diameter pipe such as a riser)
• In high mud weight, the risk of inducing
barite sag needs to be considered if mud
is thinned (displacement pills thin the mud
to the point it can no longer support barite)
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LEARNING
• As depth and hole angle increase, the minimum pill
volume (based on largest annular hole length)
should increase to allow for contamination, e.g.:
– If MD < twice TVD, annular fill length > 80 m (260 ft),
– If MD > twice TVD, annular fill length > 125 m (410 ft),
• Contact time (the time that critical points in the well
are exposed to the pill) depends on reaction of
surfactant/solvent to mud. For surfactant pills, plan
for contact times of greater than 4 minutes for best
results.
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BEST PRACTICES AND
DESIGN CRITERIA
• Good mud thinning fluid is continuous phase of the mud:
– for water based mud pumping 50 bbl (8m3) of water
as the first displacement pill will effectively thin mud,
– 50 bbl (8m3) of the mud base fluid can be pumped in
the case of oil based muds. (check oil compatibility)
• Before any displacement, the compatibly of the spacers
with the mud and the ability to water wet steel surfaces
should be checked at ambient and bottom hole temp to
confirm compatibility.
• In deep water, tests at lower temperature will be needed
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BEST PRACTICES AND DESIGN
CRITERIA
• All tests should be done on field mud samples to
ensure mud is effectively sheared and has
representative particles/cuttings
• Water wetting surfactants are generally effective
>3% vol/vol concentration, little additional benefit
is obtained above 10%.
• Solvents and mechanical or hydraulic agitation
are required to remove sludges and pipe dope
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Displacement
• Displacement of mud from an annulus is
complex. The main driving forces:
– time of contact
– flow rate and frictional forces
– density
– mechanical agitation
– pipe centralization
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RISKS AND ISSUES
• Fluid Interface area increases w/ hole angle
• In deviated wells the eccentricity of the
displacement string may reduce displacement.
Pipe rotation and/or reciprocation is needed.
• At low temperature (<40oC/104oF), OBM is very
viscous ( synthetic based muds are worst),
circulating to warm the annular contents
reduces the problem.
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RISKS AND ISSUES
• High circulation rates may be better (even in laminar
flow), they reduce the boundary layer thickness on the
casing wall. (Watch wash-out potential of soft sands)
• Turbulence is best, flow rate must be calculated allowing
for pipe eccentricity. A complete wellbore hydraulics
check is necessary.
• High rates (300 ft/min?) may reduce the fluff (80% of the
outer layer of the filter cake that does not contribute to
fluid loss control); sharply reducing the amount of solids
in the well without reducing fluid loss control.
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BEST PRACTICES AND DESIGN
CRITERIA
• High flow rates will always be better even if turbulence
cannot be achieved
• Pipe movement will improve displacement efficiency.
• Multi-function circulating subs should be used, currently
the best tools open by setting weight down, incorporating
a clutch mechanism to allow rotation.
• Do not stop displacement once pills enter the annulus
• Circulate to warm mud and fine up shakers (increase
screen mesh number) to reduce particles in the fluid
when possible, condition mud (reduce rheology).
• Use reverse circulation if possible when displacing with
lighter fluids.
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Muds, Cakes, Breakers and Particles
• Drilling mud is the best known particulate based fluid
loss control system.
• Particles are sized to bridge on the face of the
formation. Carbonate and salt are most common.
• Breakers are acid, oxidizers and enzymes.
• Filter cakes very effective in preventing losses as long
as over-balance pressure is maintained.
• Cakes are very sensitive to swabbing, but are never
completely removed..
• Tool systems sensitive to plugging by particulates.
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Particles – Damage?
• “Dirty” particles, unsized particles, debris and pipe
dope are severe formation damage problems.
• Protecting the perforations with the right particles
during a workover improves chances of well
improvement afterwards.
• The type of carrier fluid and the gels are v. important
Clear (no particles) brines are not always best solution
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Particulate Pill Displacement
• A spacer or displacement pill for displacing a
polymer system carring sized particulates
should be 0.2 to 0.25 ppg heavier and about
three times the low shear rate viscosity (at
0.06 sec-1) of the fluid being displaced.
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Data from a set of Alaska wells where the perforations were
not protected during a workover. No protection shows
significant long term damage.
PI Change, Perfs Not Protected
1.1 2.1
3.1
11
6 18.9
-40
15
9
5
13
-20
3
0
1
% Change in PI
20
0.3 0.5
7
PI of Wells
40
Short Term PI Change
Long Term PI Change
-60
-80
-100
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SPE 26042
27
When perfs were protected, that was little risk of long term damage.
PI Change After Workover - Perfs Protected
50
PI of wells
40
% Change in PI
30
1.2
0.3
3.1
4.6
8.4
20
10
Short Term PI Change
Long Term PI Change
0
-10
1
2
3
4
5
6
7
8
9 10 11
-20
-30
-40
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SPE 26042
28
Sized particulates, particularly those that can be removed, are much less damaging than most
polymers.
Kill Pills: Summary of Overall Effectiveness in
Non Fractured Wells
10
Sized Borate Salts
(4)
Cellulose
Fibers (3)
% Change in PI
5
HEC Pills
No Pills
0
-5
1
-10
2
Sized Sodium
Chloride (12)
3
4
5
No Near Perf
Milling (8)
6
7
No Near Perf Milling
(6)
-15
Near Perf Milling or
Scraping (3)
-20
-25
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Near Perf Milling
or Scraping (10)
SPE 26042
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29
Formation Damage by Gels
• Gels
– Linear gels not recommended for high
overbalance or high permeability formations – too
much depth of damage.
– HEC is not always clean breaking.
– Breaker selection is critical to removing the
damage from a linear gel.
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Pill Vol. Required, bbl per ft of zone
Linear HEC Pill needed per ft of zone, 80 lb/1000
gal or 3.36 ppb
3
2.5
2
1 Darcy
1.5
500 md
250 md
1
100 md
0.5
0
1000
750
500
Overbalance Pressure, psi
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World Oil, Modern
250 Sandface Completion
Practices, 2003
31
Fluid Loss Rate vs. Pressure Differential for
Various Permeabilities
1 cp fluid,
Loss Rate, bbl / hr / ft of zone height
6
s = +5
5
4
500 md
250 md
100 md
50md
3
2
1
0
0
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100
200
300
Overbalance
Pressure,
psi
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400
500
Modified from World
Oil, Modern Sandface
Completion Practices,
2003
32
Breaker
• Breaker must stay with the part of the gel that
causes the damage
– penetrate to the distance that gel penetrates, or
– stop at the wall – with the gel wall cake.
• Breakers:
– Acid, internal breaker, or enzyme
– Many breakers adsorb or spend in the formation,
before they work.
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Brine Stability
• The stability of the brines at high salt loadings can be
very “touchy” with temperature drops causing salt
precipitation.
• Increases in temperature decreases brine density
and may leave the brine under-saturated to salt.
• Additions of gas, alcohol, some surfactants, shear
and reduction in temperature can lead to salt
precipitation.
• Salt may affect the way polymers hydrate or disperse.
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NaCl Brine Density Variance with
Temperature
100o C
20oC
17
The reduction of brine density
as it comes to equilibrium in
the well may explain why a well
can go from a no-flow
condition to flow within a few
hours after being killed.
16.8
Brine Density (lb/gal)
16.6
16.4
16.2
16
15.8
15.6
15.4
15.2
15
60
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110
160
210
GeorgeTemperature
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260
(F)
310
360
35
SPE 12490
Temperature Changes
GOM Seafloor Temperature
Sea Floor Temperature, F
35
40
45
50
55
60
0
Water Depth, ft
2000
4000
6000
8000
10000
12000
14000
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36
Temperatures in the Well?
Circulating or High Rate Injection?
30
40
50
60
70
80
90
100 110 120 130
0
30
40
50
60
70
80
90
100
110
120
130
0
Tubing
Undisturbed
Tbg Fluid
2000
Tbg Fluid
2000
Casing 1
Tubing
Undisturbed
Casing 1
4000
4000
6000
6000
8000
8000
10000
10000
BHST= 122*F
12000
BHST= 125*F
12000
14000
14000
BHTT= 86*F
BHCT= 98*F
16000
16000
Circulation pump rate = 8-BPM
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18000
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18000
37
Crystallization Temp
Salt-Out or “Freezing” Temperature of a Brine
Adding salt lowers
freezing point of water
until the point at which
additional salt precipitates
Eutectic Point
Salt Content
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Composition Determines TCT (true
crystallization temperature)
Density
(ppg)*
12.5
12.5
12.5
12.5
CaCl2
(wt %)
34.40
32.20
22.84
00.00
CaBr2
(wt %)
10.80
13.13
20.55
41.55
TCT
(OF / OC)
60/ 15.5
44/ 6.7
15/ - 2.8
- 33/ - 36
*1.50 SG
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Density Change with Temp Change
DDH = DS (1 + 0.000252 (TS - TDH))
What is downhole density (DDH) of a 16.4 lb/gal
surface density (Ds) brine (60oF) when downhole
temperature increases to 230oF?
DDH = (16.4) (1 + 0.000252 (60-230)
DDH = 15.7 lb/gal
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Formula from OSCA
40
There is a slight increase in density with applied pressure, usually about 0.1 ppg.
Brine Density Change with Pressure
2.4
Brine Density (g/cc)
2.2
ZnBr2/CaBr2 (19%
/wt)
ZnBr2/CaBr2/CaCl2
(37% /wt)
CaBr2 (45% /wt)
2
1.8
1.6
NaBr (54% /wt)
1.4
CaCl2 (65% /wt)
1.2
NaCl (70% /wt)
1
Typical change was 0.0015 g/cc
0
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1000
2000
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Pressure,
psi
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3000
SPE 12490
41
Temperature and Pressure Effects on Completion Fluids
Temp Expansion of Fluids
Expansion Coef.
Fluid System
Diesel
NaCl
CaCl2
NaBr
CaBr2
ZnBr2/CaBr2/CaCl2
ZnBr2/CaBr2
3/14/2009
Density, ppg
7
9.49
11.45
12.48
14.3
16.01
19.27
o
4
Pressure Effect on Fluids
Compression Coef.
o
vol/vol/ Fx10
lb/gal/100 F
3.8
2.54
0.24
2.39
0.27
2.67
0.33
2.33
0.33
2.27
0.36
2.54
0.48
At 12,000 psi from 76F to 345F
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o
vol/vol/ Fx10
6
lb/gal/1000 psi
1.98
0.019
1.5
0.017
1.67
0.021
1.53
0.022
1.39
0.022
1.64
0.031
At 198F from 2,000 to 12,000 psi
World Oil, Modern
Sand Face Completion,
42
2003
Brine Selection – Circulating
Density
•
•
•
•
Match density needs on both static (ESD) needs,
and circulating density (ECD) needs. Consider
friction effects on BH press while circulating.
Remember – brine must exert pressures in a
window between controlling pore pressure or shale
heaving and fracturing the formation.
Brine density changes with temperature (can drop
by >1 lb/gal) and a small increase with pressure
(0.1 lb/gal).
Carried solids add density to the brine – easily by
0.5 to 2+ lb/gal.
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Brines have small density changes due to temperature, pressure, and contamination; and larger
density changes due to suspended solids.
CaCl2 Brine in a 14,000 ft
Wellbore in 8,000 ft Water
Hydrostatic Pressure at TVD
BH Pre ssure - (psi)
ESD - (lb/gal)
11.35
Note: Fluid
Density is
Greater at the
Mud line than
at the Surface
11.45
0
11.50
4000
10000
True Vertical Depth - (ft)
4000
8000
6000
8000
10000
12000
12000
14000
14000
16000
10000
2000
2000
6000
5000
0
0
True Vertical Depth - (ft)
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Courtesy
of MI-LLC
11.40
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ESD
16000
Pres s ure
44
Adding solids to any fluid, either at the surface or
downhole increases it density. 0.5 to 2+ lb of solids
are common in cleanout with circulated fluids.
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Completion Fluid - Checklist
•
•
•
•
•
•
•
•
•
Is the formation liquid sensitive to liquid relative permeability effects?
Compatibility with formation? (clay and minerals)
Compatibility with formation fluid? (emulsion, sludge, foam, froth)
Tanks and surface equipment clean?(pumps, lines, hoses, blenders)
Are polymers breakable? How is breaker added?
Polymers, hydrated, sheared and filtered? Filter level? Beta rating?
Minimize the pipe dope?
Corrosion reactions understood?
Erosion potential understood?
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Special Case - Horizontal Wells
• Hole circulated to a large volume of fluid to stop
losses.
• Minimum amount of solids can be used where
internal tool sticking is a possibility
• Suspension of solids beyond 60o deviation is difficult.
• Penetration to furthest reaches of the well is
required – buckling considerations?
• Very sensitive to swabbing.
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Filtration and Cleaning
• Brine and ? (tanks, lines, pumps, etc.)
• Pickle the tubulars?
• NTU or particle count as a measure? How clean is
clean? = Avg pore throat x 0.2?
• Beta rating and micron rating important
• Tank arrangement when filtering (from dirty tank to
clean, not in a loop)
• Filter type
– DE or Cartridge (no resin coated cartridges)
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Filtration Ratings
• NTU - a turbidity indicator - can be mislead by natural color of
water. An NTU of 20 to 30 is generally clean.
• Nominal filter rating - estimate of the size of particle removed
- don’t trust it. Filtration efficiency improves with bed build-up
• Absolute filter rating - size of the holes in the filter. Filtration
efficiency improves with bed build-up
• Beta rating - a ratio of particles before filtration to after. A
good measure of filter efficiency.
• Suggestion – use a 5 to 10 micron rating with a beta rating of
1000 for most clear brine applications.
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Beta Rating
• Beta = number of filter rating and larger size
particles in dirty fluid divided by number of
those particles in clean fluid.
• Beta = 1000/1 = 1000 or 99.99% clean
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Filtration Considerations
• Very clean fluids have high leakoff rates
• Fluids with properly blended fluid loss control
materials added after filtration have a better
chance of cleanup than with the initial
particles in the fluid. Particles must be sized
to stop at the face of the formation.
• All gelled fluids should be sheared and filtered
– even the liquid polymer fluids.
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Microgels
or “fisheyes”
after straining
liquid HECfiltered
dispersion
a 200
mesh screen in a
Solid polymer
lumps or “Fisheyes”
andamicrogels
fromthrough
liquid HEC
polymer.
shear and filter operation for gravel pack fluid preparation.
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Scrapers and Brushes – Physically
Cleaning the Well
• Available tools
• Damage potential
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One very detrimental action was running a scraper prior to packer setting. The
scraping and surging drives debris into unprotected perfs.
Effect of Scraping or Milling Adjacent to Open
Perforations
20
% Change in PI
10
Perfs not protected by
LCM prior to scraping
0
-10
1
Perfs protected
by
2
LCM
-20
-30
-40
Short Term PI Change
Long Term PI Change
-50
-60
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SPE 26042
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Casing Scraper – Designed to knock off
perforation burrs, lips in tubing pins,
cement and mud sheaths, scale, etc.
It cleans the pipe before setting a
packer or plug.
The debris it turns loose from the pipe
may damage the formation unless the
pay is protected by a LCM or plug.
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Placement Methods
• Circulating – preferred – watch effective circulation density
(friction pressures)
• Spotting – watch density induced drift – 0.05 lb/gal difference
can start density migration.
• Bullheading - next to last resort.
• Lubricating - last resort.
• Consider coiled tubing for most accurate spotting
and ability to circulate fluids into place with
minimum contamination.
• Remember that fluid density differences of even 0.05
lb/gal will start density segregation.
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Fluid Loss Control
• Methods: viscosity, particulates, mechanical
• Best method? – depends on application and options
afterward.
– Viscosity based methods often leave polymer debris
– Particulates must be sized with small, medium and large
particles to build a tight cake at the surface. Don’t use
them in cased and perforated completions???
– Mechanical methods preferred, but not always practical.
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Fluid Loss Control Systems
fluid (pumped)
mechanical
gels (linear and x-link)
downhole valves
plugs
bridging particulates
micron particles
flappers (watch the throat
size)
resin particles
ball checks
larger mixed particles
Removal methods?
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Removal methods?
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In the Formation / At the
Formation Face (Not in Perf)
• Gels – high vis. limits the
fluid loss by pressure
drop.
– May not work in high perm
(>0.5 darcy).
– Temperature greatly affects
performance.
– Cleanup is a problem.
• Particulates bridge at the
formation face.
Particulates are very effective in controlling fluid loss, but are also very sensitive to
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Engineering
swabbing,
dissolving in carrier fluids
and
must
be sized for the formation pores
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62 and
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natural fractures.
Particulate Systems
• Sized carbonates and salts are most common.
Penetration depth = 0.125” (3mm)
• Do not use in most perforated completions unless
the perforations have been packed with gravel.
• Gravel pack tools and tools with close clearances
should not be exposed to particulate laden fluids.
• Gel carriers for particulates still require breakers.
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Considerations for Fluid loss
Control Selection
BHT
Formation sensitivity
to treatment fluids
Onshore / Offshore /
Deepwater
BHP
Treatment/completion
fluid types
Rig cost per day
Overbalance or
underbalance
Frequency and amount
of surge/swab loads
Rig equip available pumps, tanks, lines,
Vertical and horizontal Formation sand
permeability variations strength
All tubular sizes in the
flow path
Formation sand size
and pore throat size
Sand production and
presence of cavity
Mobilization time
available
Production rate
Producer or injector
Regulations on use and
disposal
Produced fluid types
Wellbore deviation
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through
the pay
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Natural or hydraulic
fractures present
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SPE 54323
Areas for Fluid Loss Control
•
•
•
•
•
•
•
In formation matrix
At the formation face
Inside the perf tunnel
On the fracture pack
Inside the casing (on
the perforation)
On a sand-back plug
In the gravel
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•
•
•
•
Inside the screen
Above the screen or in
the BHA
Inside the tubing
At the surface
Each location requires different plug
construction methods and removal
considerations.
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Cleanup
• Gel break and damage issues
• Fluid imbibition effects
• Other fluid unloading issues
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Cleanup
• How to remove from the reservoir (through the
fractures or the matrix). Is a surface/interfacial
reduction surfactant needed? Is gas needed? Is the
formation initially undersaturated to water (yes, it
can and does happen).
• From the wellbore – effective unloading is plagued
by well deviation and low flow rates from small
coiled tubing and other non rotating strings.
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Problems - unwanted foams during
backflow
• Foam is an emulsion where gas is the internal phase
(mist is an emulsion with gas as external phase).
Foams are used to unload brines – BUT the forms
may cause a problem at the surface.
• Foaming conditions
– some oils (ppm conc. of C6-C9organic acids and alcohols)
– diesel - (particularly bad and varies from lot to lot)
– some acid additives (emulsifiers, salts, inhibitors)
– XCD polymers (and others)
• Look for and destroy the stabilizer to break the foam.
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68
Brine Tankage Required
1.
2.
3.
4.
5.
6.
7.
8.
9.
Volume of prod. Casing – annulus & below packer?
Displacement volume of work string
Displacement volume of producing string including packers
Volume of manifolds, lines, hoses and pumps
Volume of transport tankage (usable)
Volume of filtering system (all tanks, lines and pods)
Volume of pill tank
Pickle flush volume
Spare volume for safe operation
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Special Topics
•
•
•
•
•
•
•
•
Alternatives to a clear brine
Gravel pack brines
Brine handling and preparation
Solids free gels
Corrosion
Hydrates
Best Practice Learnings
Toxicity
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Alternatives to a Clear Brine
• Emulsions, Foams, Muds
– Will it be stable?
– What will stop fluid loss?
– What will clean up or degrade?
– What will damage least?
– Can an oil be ever be used in a gas zone??
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Is mud a viable kill fluid for high
temp and high pressure wells?
• How much perm damage does it cause?
– Against the formation?
– In the perforations?
– In a naturally fractured formation?
– Against a gravel pack or screen?
• Is the damage reversible?
– If you have high wellbore pressures, some of the
mud damage is reversible - SOME!
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Fluids for Gravel/Frac Pack
• Water - low viscosity brines, low molecular
weight salts
• HEC - high molecular weight, water soluble
polymer, straight chain
• Xanvis - high molecular wt bio polymer, water
soluble. Branched chain, lower damage than
HEC?
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Water
• Advantages - no mixing, no breakers, high
leakoff, easier to get turbulence
• Disadvantages - low gravel carrying capacity
(+/- 2 ppg), more fluid lost, compatibility
problems?
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74
HEC
• Advantages: mixes easily??? (still must shear
and filter), easy to break??? (we’ve had
problems here), commonly available
• Disadvantages: lower leakoff rates, lower sand
carrying capacity than bio-polymers
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75
XC
• Advantages: shear thinning, higher leakoff,
good carrying capacity
• Disadvantages: said to wet some formations
(anionic), x-links with calcium and iron (water
composition more critical), harder to mix,
breaks rapidly above 125oF ?
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Brine Handling and Preparation
Min Filter Req
Brines
HEC
XC
5 to 10 mu
10 mu
10mu
Beta rating
B=1000
B=10-100
B=10-100
Shear Req?
N/A
2 bpm/1200 psi 2 bpm/600
Gravel Conc.
1-5 ppg
1-15 ppg
1-15 ppg
Breaker
N/A
acid, enz, ox
oxidizers
Brine Compat?
N/A
<15.5 ppg KCl & NH4Cl
Leakoff
excellent
fair
good
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Solids Free Gels
•
•
•
•
Surfactant gel
Requires clay control (early problems)
Breaks with oil
Not perfect, but generally better than gels.
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Breakers for HEC-Gelled Brines
Breaker
BHT
HCl
130 to 200F
Ammonium hypochlorite 130 to 200F
Enzymes
below 130 F
No Breaker Required? Above 200 F?
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Corrosivity
• In oxygen free environment, CaCl2/CaBr brines
exhibit very low corrosion rates if the pH is kept
between 7 and 10.
• Lime and magnesium oxide are used to increase the
pH of the brines.
• Use of sulfite oxygen scavengers in large
concentrations can potentially cause CaSO4 precip.
Use other methods.
• Biocide may not be needed in more concentrated
brines.
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Corrosion From Brines –example from Materials,
Corrosion and Inspection: http://upstream.bpweb.bp.com/mci/default.asp
Material
General
Corrosion
Low Alloy Steel
Y
13 Chrome
Y
Super Cr 13, etc.
Y
Pitting/Crevice
Corrosion
SSC
CL SCC
Relative
Failure Risk
Y
Low
Y
Y
Low/Med
Y
Y
Y
High
Alloy 450
Y
Y
Y
Med
17-4PH
Y
Y
Y
High
Duplex Stainless
Y
Y
Y
High
Austenitic
Y
Y
High
Super Austenitic
Y
Y
Low
Ni Alloys
Y
Y
Low
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HPHT Production Operations, March 16, 2005, EPTG, BP
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11
Hydrates and “Freezing”
• Sea floor temperatures
• Gas expansion cooling
• Is the brine naturally hydrate formation
resistant?
• Is it tolerant of antifreeze?
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Dense Brines Inhibit Hydrates
Hydrate inhibition by CaCl2 Brine
120.0
Hydrate Formation Temp °F
100.0
Hydrate equilibrium
pressure for pure water
calculated using
80.0
CSMHYD, VK 917 gas
15 kpsi
10 kpsi
5 kpsi
2.5 kpsi
60.0
40.0
Maybe
Solvent Needed
20.0
Safe
0.0
8.3
8.5
8.7
8.9
9.1
9.3
9.5
9.7
9.9
10.1
10.3
10.5
10.7
10.9
11.1
11.3
11.5
11.7
-20.0
-40.0
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Brine Density
lb/gal
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83
LEARNINGS
• Proper disposal required for all chemicals.
• Mixed displacement pills and mud have to be
separated from the mud and packer fluid for disposal
(zero discharge issues)
• Brine/Water/Acid pumped without
surfactants/solvents to displace oil muds (e.g. for an
inflow test) prior to clean up can form sludges, these
will not be broken down by subsequent clean up
pills
• Clean up pills containing surfactants can foam
during mixing (particularly when put through a
hopper) and during flowback.
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Viscosifier Learnings
• XCD/ biozan are preferred for mixing viscous pills
but do not work in calcium brines,
• HEC will not support solids.
• Polymers should be checked for suitability at the
anticipated temperature (thermal thinning an issue
particularly >135oC/275oF).
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LEARNING
• The use of a circulating sub to allow high flow rates is
recommended.
• As steel surfaces water wet, pipe rotation may not be
possible due to friction and displacement of solids
becomes much more difficult.
• Displacement must exceed solids settling rate and (e.g.
0.18 ft/sec for 40/60 mesh sand in water) not stop once
pills are in the annulus.
• Displacement optimized for smallest production casing
ID can leave bypassed mud in larger OD’s for tapered
casing strings.
• Reverse circulation is most effective if packer fluid is
lighter than mud (watch bridging potential)
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Many Brines are Sensitive to
Temperature When Viscosified
• Brine type sensitive – NaCl to ZnCl
• Temperature sensitivity is also affected by
concentration
• Liquid vs. dry polymer makes a difference.
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Stability of Dry HEC in Socium Chloride
260
Precipitation, Separation or Lost Viscosity
240
Temperature, F
Transition Zone
220
200
HEC Active and Soluble
180
160
140
8.6
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8.8
9
9.2
9.4
9.6
9.8
Sodium
Chloride
Density, ppg
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10
SPE 58728
10.2
88
Liquid HEC in Zinc Based Brines
260
240
Temperature, F
220
Transition Zone
200
180
HEC Active and Soluble
160
140
120
100
15
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16
17
18
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Zinc
Density, ppg
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19
20
SPE 58728
89
Brief toxicity data for standard test organisms.
Species
Algae
Invertibrates
Fish
3/14/2009
SPE 27143
Acute Toxic Threshold Concentration (mg/l)
Zinc
Cesium
Potassium
Sodium
bromide
formate
formate
formate
0.32
1600
3700
2000
1.6
340
300
3900
?
260
1700
6100
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