Completion Fluids

Completion Fluids

Various types of fluids may be used for completion and work over
operations:

1. Oil fluid

 Crude oil
 Diesel
 Mineral oil

2. Clear water fluids

 Formation salt water

 Seawater
 Prepared salt water such as calcium chloride, potassium chloride or
sodium chloride salt and zinc, calcium, or sodium-based bromides

3. Conventional water-base mud

4 Oil-base
4. Oil b or invert
i t emulsion
l i muds
d
Completion Fluids

Three types of completion or workover fluids are:

1. Clear liquids (dense salt solutions)

2 Weighted suspensions containing calcium carbonate weighting

2.
material and a bridging agent.

3. Water-in-oil emulsions made with emulsifiers for oil muds.

Clear liquids have no suspended solids and can be referred to as solids
free fluids.

Weighted suspensions are fluids with suspended solids for bridging or

added density (Solids-laden fluids).
Completion Fluids

1. Solids-Free Fluids

Brines used in completion

p and workover applications
pp mayy be single-
g
salt brines, two-salt brines, or brines containing three different salt
compounds.

A. Single-Salt Brines

Single-salt brines are made with freshwater and one salt such as
potassium chloride,
hl d sodium
d chloride,
hl d or calcium
l chloride.
hl d

 Potassium chloride brines are excellent completion fluids for

water-sensitive
t iti f
formations
ti with
ith a corrosion
i rates
t are low.
l

 Sodium chloride brines are low cost and wide availability.

The density of 1.20
1 20 sg is achievable for this brine.
brine

 Calcium chloride brines are mixed at densities up to 1.39 sg.

 Sodium bromide has low corrosion rates even without the use of
corrosion inhibitors.
Completion Fluids

B. Two-Salt Brines

The basic ingredient

g of calcium chloride/calcium bromide brines
(CaCl2/CaBr2) is a calcium bromide solution that ranges in density to
1.72 sg.

The density of CaBr2 brine can be increased by adding calcium

chloride.

CaCll2/CaBr
/ 2 brine
b can be
b diluted
dl d by
b adding
dd a CaCll2 brine
b weighing
h
1.39 sg.

There is
Th i nott muchh off a crystallization
t lli ti problem
bl with
ith calcium
l i
chloride/calcium bromide brines at densities between 1.40 and 1.62
sg.

However, the heavier CaCl2/CaBr2 brines require special formulation in

cold weather applications.
Completion Fluids

C. Three-Salt Brines

Three-salt brines such as calcium chloride/calcium bromide/zinc

bromide brines are composed of CaCl2, CaBr2, and ZnBr2.

At high temperatures, corrosion rates in brines containing ZnBr2 are

very high.

For use at high temperatures, the brine should be treated with

corrosion inhibitors.
hb
Completion Fluids

2. Crystallization & Precipitation of Problems

A brine
brine's
s crystallization point is the temperature at which salt crystals
will begin to fall out of solution.

Crystallization and precipitation of insoluble salts can cause a number

of problems such as:

 A drop
p in a fluid’s density
y

 Plugged lines and pumps

To ensure crystallization does not occur in a brine:

 Determine the
h required
d crystallization
ll point off the
h fluid
fl d

 Check the actual crystallization point of the fluid

 Adjust the crystallization point of the fluid, as necessary

Completion Fluids

3. Determining Crystallization Point

Consider the temperatures

p at which the brine will be transported,
p ,
stored, and used.

For deep-water projects consider the seawater temperature at the

ocean floor.

4. Checking the actual crystallization point.

Three temperature values are used to describe a fluid's

crystallization point. These include the:
Completion Fluids

 First crystal to appear (FTC)

 True crystallization
temperature (TCT)

 Last crystal to dissolve (LCTD)

Note: The TCT is the API method

of describing crystallization point.
Completion Fluids

•Crystallization
P i t
Point
Completion Fluids

•Crystallization
Point
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5. Adjusting the crystallization point.

It may
y be necessary y to adjust
j the fluid's crystallization
y point by
p y
adding dry salts or water.

The addition of dry salts

For single-salt solutions, the addition of the same type of dry salt
lowers the crystallization point.

For two-salt brines with a crystallization point of 30°F, the

addition of a dry salt in general raises the crystallization point.

The addition of fresh water

 To single-salt
single salt brine whose density is above the eutectic point
lowers the density and crystallization point.

 To a two-salt system tends to lower the density and crystallization

point.
Completion Fluids

6. Completion/Workover Fluids

The corrosivity
y of a g
given completion
p or workover fluid depends
p on
its brine type.

Brines fall into two categories:

 Monovalent

 Divalent.
l

Monovalent brines generally show low corrosivity, even at

t
temperatures
t exceeding
di 400°F
400°F.

Corrosivity depends on the density and chemical composition.

Laboratory data show that the addition of calcium chloride lowers the
rate of corrosion, while the addition of zinc bromide rapidly increases
the rate of corrosion.
Completion Fluids

 Packer-Fluid Treatments

When usingg drilling

g fluid as a p
packer fluid,, the drilling
g fluid must be
conditioned to minimize corrosion under long-term, static conditions.

 Corrosive Agents

When working with completion or workover

fluids, the two corrosive agents to monitor are:

 Oxygen

 Hydrogen
H d sulfide
lfid
Completion Fluids

 Oxygen & Hydrogen sulfide

The solubility of gases in a liquid is directly related to the total

dissolved-solids concentration of that liquid.

The higher the dissolved-solids content, the lower the solubility of

gases in the liquid.
g q

Some products used as oxygen scavengers contain sulfides that

react with dissolved oxygen in fluids to form sulfates, eliminating the
corrosive effects of the dissolved oxygen.
Completion Fluids

In solids-enhanced systems, the most often used hydrogen-sulfide

scavenger is zinc carbonate.

The zinc reacts with the soluble sulfide ions to form zinc sulfide,
which is insoluble and precipitates.

In solids-free systems, soluble zinc bromide salt absorbs the

hydrogen sulfide.

Note:

In operations where hydrogen-sulfide contamination is expected,

offset
ff t the
th hydrogen
h d sulfide’s
lfid ’ acidic
idi nature
t b maintaining
by i t i i a proper
pH in the brine.

In a packer-fluid
packer fluid application where there is a static system with no
aeration of the fluid, the dissolved oxygen content is so low that an
oxygen scavenger usually is not required.
Completion Fluids

 Corrosion Inhibitors

A corrosion inhibitor is a chemical product that reduces metallic loss

when it is added in small concentrations to a corrosive environment.

Chemicals used as corrosion inhibitors include inorganic and organic

compounds.
p

The products recommended for treating corrosive agents in

completion and workover fluids are:
Completion Fluids

7. Drill - in fluids

Drill - in fluids are specially

p y designed,
g , non damaging
g g drilling
g fluids for
use in reservoir intervals.

They are formulated to maximize drilling performance as they

minimize formation damage, thereby preserving potential well
productivity.

A variety off fluids

fl d can be
b used
d as drill-
d ll in fluids,
fl d including
l d water, oill
and synthetic base fluids.

Fluid
Fl id selection
l ti d
depends
d on fformation
ti t
type, f
formation
ti fl id
fluids
composition, formation damage mechanism and completion method.

Most wells drilled with drill-in

drill in fluids are completed without cementing
are perforating a casing or liner through the producing zone.
Completion Fluids

Drill-in Fluid characteristics :

A. Formation damage
g control :

 The drill-in fluid should not contain clays or acid insoluble weight.

 The drill-in fluid should be formulated with acid soluble viscisifiers,

fluid loss materials and properly sized plugging agent.

 The
h filtrate
fl should
h ld bbe fformulated
l d to prevent clays
l in the
h producing
d
zone from swelling.

 Th
The filt
filtrate
t should
h ld bbe compatible
tibl with
ith fformation
ti fl
fluids
id to
t avoid
id
precipitate mineral scales.

 The fluid and filtrate should not change the wetting characteristics
of the formation.

 The filtrate should not form emulsion with formation fluids and
block the formation.
Completion Fluids

B. Drill ability :

The drill-in fluid should provide:

p

 Good hole-cleaning, lubricity and inhibition.

 Minimize hole enlargement and provide wellbore stability.

C. Compatibility with completion equipment and procedures:

 Particles should be sized for formation pore and be small enough

to pass through completion equipment.

 The fluid should be formulated with acid soluble, water soluble,

oxidizer degradable or solvent soluble materials, which will not
cause precipitates or emulsions.
emulsions
Completion Fluids

8. Oil base fluids

Oil base fluids are sometimes used as completion

p and workover
fluids.

These fluids are minimally damaging to certain formation and the

filtrate is also oil, so that sensitive clays are not affected.

The thin, low permeability filter cake also limits solids from invading
the
h producing
d zone.

Oil base fluids are often formulated with acid soluble bridging
/ i hti
/weighting agents
t so that
th t any residual
id l filt
filter cake
k or solids
lid can be
b
acidized for remove.
Completion Fluids

9. Water base fluids

Water base fluids are less frequently

q y used as²completion
p and
workover fluids and cover a variety of systems.

The term water base refers to systems that are formulated from
water or brine.

The aqueous phase can range from fresh water to a high

concentration off soluble
l bl salts.
l

Water base fluids can be divided into these categories:

 Conventional water base muds

 Clear water fluids
 Brine/Polymer systems
 Clear brines
 Foam
Completion Fluids

10. Formation damage mechanisms

A. Mechanically
y Induced Formation Damage
g

Formation pore can be plugged by solids contained in a drilling fluid

and cause formation damage.
g

The introduction of extraneous solids of either an artificial nature

(i
(i.e. weighting
i hti agents,
t fluid
fl id loss
l agents,
t or artificial
tifi i l bridging
b id i agents)
t )
or naturally occurring drill solids generated by the action of the drill
bit on the formation.
formation

Compressible and deformation solids (Hydrated clays) are the most

diffi lt to
difficult t remove.
Completion Fluids

B. Chemically Induced Formation Damage

 Clay induced formation damage associated with the reaction of low

salinity or fresh invaded fluid filtrates with potentially reactive clays
(swelling clays or mixed layer clays).

 The precipitation of solids, asphaltenes caused by an

incompatibility between introduced hydrocarbon fluids and in-situ
hydrocarbon fluids resulting in a destabilization and precipitation of
asphaltenes.

 The formation of insoluble precipitates caused by the blending of

incompatible drilling and completion filtrates with in-situ foreign
waters.
Completion Fluids

 The generation of high viscosity stable water in oil emulsions in

the near wellbore region caused by the invasion of incompatible
water-based filtrates resulting in the formation of an emulsion block.

 Wettability
W tt bilit alterations
lt ti associated
i t d with
ith the
th use off invert
i t drilling
d illi
muds or other muds containing high concentrations of polar
surfactants or materials.
materials Near wellbore wettability alterations can
reduce the relative permeability of oil significantly and increase
relative permeability to water,
water causing a dramatic change in the
water-oil production characteristics of a given completion.
Biologically Induced Formation Damage.
Damage
Completion Fluids

C. Biologically Induced Formation Damage

 Secretion of high molecular weight polysaccharide polymers to

form plugging bio-films.

 Propagation of sulphate reducing bacteria (A classification of

anaerobic bacteria which do not require
q oxygen
yg to survive)) and the
resulting metabolisation of sulphate present in naturally occurring
formation or injection water to toxic hydrogen sulphide gas.