Comp Let Ions and Workover Fluids PO Chapter 8

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Chapter 8 Completion and WorkoverFluids

Functions, requirements, selection criteria

Formation damage considerations

Oil fluids, practical applications

Clear-water fluids, practical applications

Clay, emulsion, and wettability problems

Viscosity, fluid loss, and density control

Maintenance of clean fluids

Conventional drilling fluids

Aerated fluids

Perforating fluids, packer fluids

High density brines .Filtration

Function-Requirements-Selection Criteria

By definition a completion or workover fluid is a

fluid placed against the producing formation while con-

ducting such operations as well killing, cleaning out,

drilling in, plugging back, controlling sand, or perforat-

ing. Frac fluids are sometimes considered to be work-

over fluids. Similar materials are used to build viscosity

and provide fluid loss control; however, frac fluid re-

quirements are significantly different than for workover

fluids. See Chapter 8, Volume 2, Fracturing, for a dis-

cussion of frac fluids. Packer fluids, discussed later in

this chapter, remain in the well for an extended period;

thus stability and corrosion are important concerns.

Basic completion and workover fluid functions are

to facilitate movement of treating fluids to a particular

point downhole, to remove solids from the well, and to

control formation pressures. Required fluid properties

vary depending on the operation-but the possibility of

formation damage should always be an important con-

cern. In certain operations, such as sand consolidation

or gravel packing, sandface or perforation plugging is a

prime concern.In recent years several new fluids and fluid han-

dling systems have appeared, most due to the recogni-

tion of the high risk of reducing the productivity, orcompletely plugging certain sections of the producingzone, through contact with a foreign fluid. In some

situations, a good question may be, "Is it reallynecessary to kill the well to accomplish the desired

operation?"

If it is necessary to kill the well, these points

should be considered in selecting a workover or com-pletion fluid:

Fluid Density-Fluid density should be no higher

than needed to control formation pressure. With reason-

able precautions a hydrostatic pressure of 100-200 psi.

over formation pressure should be adequate. Balanced

pressure workovers are ideal from the standpoint of

formation damage and, with proper equipment to con-tain the surface pressure, are practical for some opera-

tions.

Solids Content-Ideally, the fluid should containno solids to avoid formation and perforation plugging.

As a practical limit, so'lids content should be less than

25 ppm. Figure 8-1 shows plugging of Cypress sand-

stone (450-md brine permeability) with saltwater fluids

containing various sizes and concentrations of solids.

Particles greater than 5micron size caused significantly

more plugging than particles less than 2 micron size. In

both cases plugging occurred within the core pore chan-

nels.

Particles larger than about one-half the averagepore diameter should quickly bridge at the entrance to

the pore. These larger particles are probably not detri-:mental if they are removed by backflow or degraded byacid or crude oil.

Particles which plate out to plug the face of the

formation or a perforation obviously obstruct opera-



8-2 PRODUCTIONOPERATIONSNOL.

Well Completions, Workover, and Stimulatio

Lagend

. .. . A Bay wate. f il te, ed through 2.6. a Bay wate, fllte",d through ,

o C Pl'<Mluc.dwater un" ' • • led

• II water unlrealedIO~--~-----L ~ ~ __-L__~

o 0.02 0.04 0.06 0.08 0.10

Volume Injected, gaVper f

o 100 200 300

Pore Volume

400 500

FIG. 8-1-Permeability reduction in Cypress sand-stone cores. 7 Permission to publish by The Society

of Petroleum Engineers.

tions, such as sand. consolidation, gravel packing, or

squeeze cementing.

Filtrate Characteristics-Characteristics of the

filtrate should be tailored to minimize formation dam-

age considering swelling or dispersion of clays, wetta-

bility changes, and emulsion stabilization. Many timesthis means that the fluid should contain the proper

surfactant as well as the proper electrolyte.

Fluid Loss-Fluid loss characteristics may have to

be tailored to prevent loss of excessive quantities offluid to the formation, or to permit application of "hy-

draulic stress" to an unconsolidated sand formation.

Bridging at the formation face by properly sized acid-soluble particles (calcium carbonate) is a desirable ap-

proach to fluid loss control. Sometimes, oil soluble resin

particles orwater soluble salt crystals may substitute for

the calcium carbonate. In either case colloidal particlesare also required for an effective seal.

Viscosity-Related Characteristics-Viscosity-re-lated characteristics, such as yield point, plastic viscos-

ity, and gel strength, may have to be tailored to providfluid lifting capacity required to bring sand or cutting

to the surface at reasonable circulating rates. Lab tesshow that many viscosity builders cause permanent r

duction in permeability. This can be minimized by car

ful polymer selection, hydration and filtration alonwith adequate fluid loss control, where necessary, t

limit invasion.

Corrosion Products-The fluid should be chem

cally stabI~ so that reaction of free oxygen with tubula

steels is minimized, and that iron in solution is seque

tered and not permitted to precipitate in the formation

A reasonable upper limit on corrosivity for a completioor workover fluid is 0.05 lb/rr (about 1 mil) per work

over. For a packer fluid, the corrosivity target should b

about 1 mil per year, but 5 mils per year is considere

to be an acceptable upper limit.

Mechanical Considerations-Rig equipment

available for mixing, storage, solids removal, and circulating is often a factor in fluid selection.

Economics-The most economical fluid commen

surate with the well's susceptibility to damage shoul

be selected.

Formation Damage Related to Solids

There are two basic approaches to minimize forma

tion damage due to solids entrained in the completionfluid.

Complete Solids ./:lemoval-To be effective, fluiin contact with the formation must not contain an

solids larger than 2 micron size. These points are in

volved:

• Eliminate solids to the greatest extent possible

through the use of 2-micron absolute rated sur

face filters, backed up by other measures to mini

mize solids pickup downstream from the filteri.e., control of oxygen to minimize iron oxide

careful use of thread dope, removal of rust, scaleetc. from downhole tubulars using Hel, IPA, o

sand scouring techniques.

• Accept loss of fluid to the formation and, as

practical matter, movement of very small fine

into the formation. The quantity of fines is lim

ited by minimizing differential pressure into thformation. Removal of fines from the pore sys

tem after the job is maximized by returning th

well to production through gradual increases i

flow rate.



C omp le tio n a nd Work ov er F lu id s

• Accept possible difficulties in removing largeparticles from the hole due to low 'viscosity and

carrying capacity. Many times velocity can besubstituted for viscosity in lifting particles. A

rising velocity of 150 ftlmin should be sufficientto remove formation cuttings or sand even with

1.0 cp viscosity clear saltwater.

This velocity is within the limits of many workover

pumping systems: i.e., a circulating rate of 5 bbllmin

gives 150 ftlmin annular velocity with 27/S-in. tub-

ing inside 7-in. casing or 2 3/8-in. tubing inside 5

1/2-in. casing. A no-solids viscosity greater than 1.0 cp

may be possible with filtered crude oil or perhaps brine

viscosifiers having no residue.

Complete Fluid Loss Control-To be effective,particles must not be allowed to move past the face ofthe formation into the pore system. These points are

involved:

• Stop all solids at the formation face by carryingin the workover fluid solid particles properly

sized to bridge quickly, and colloids to maximizethe effectiveness of the seal.

• Remove formation-face plug after the job bybackflow-andlor by degradation of the calciumcarbonate solid particles and colloids with acid.With certain limitations resin solids dissolvable

in crude oil, or graded rock salt dissolvable in

unsaturated water, could be used rather than cal-cium carbonate.

• Accept the possibility that after the job pressuredifferential needed to unplug all sections of the

zone will not be available and that it will not be

possible to contact all the plugged section of the

formation with acid due to bypassing tendencies.

The optimum approach depends on specific well

conditions and operations. For certain critical opera-

tions such as sand consolidation and gravel packing

through. perforations, the "complete-solids-removal"

approach often provides highest productivity and mini-

mum cost.

Oil Fluids-Practical Application

Crude Oil-Availability makes crude oil a com-mon choice where low « 8.3 Ib/gal) density is required.

Density considerations may make it particularly desir-

able in low-pressure formations. A low-viscosity crude

has limited carrying capacity and no gel strength and

thus should drop out non-hydrocarbon solids in surface

pits. See Figure 2-11A, Chapter 2, Reservoir Considera-

tions inWell Completions, for correlation of oil viscos-

ity vs. API gravity and temperature. Crude obtainedfrom the stock tank has usually 'weathered enough to

reduce (but not eliminate) the fire hazard. Oil is not

recommended as a packer fluid except for special cases.

(See Packer Fluids discussed later in this chapter).

Loss of oil to the formation is usually not harmful

from the standpoint of clay disturbance or from satura-

tion effects, as might be the case with water in a low

pressure formation. Ithas no fluid loss control; thus, any

entrained fine solids could be carried into the pore

system.

Crude oil should always be checked for the pres-

ence of asphaltenes or paraffins that could plug theformation. This can be done in the field using API fluid

loss test equipment to observe the quantity of solidscollected on the filter paper.

Also, crude oil should be checked for possibility of

emulsions with formation water. Techniques of the API

RP 42 test (visual wettability and emulsion breakout)

are suitable for field use. If stable emulsions are formed,a suitable surfactant should be added.

Diesel Oil-This is often used where a low densityclean fluid is required. It may even be advantageous to

work under pressure at the surface where the density ofdiesel oil is not sufficient to overcome formation pres-

sure.

Depending on hauling and handling practices, die-

sel oil should also be checked for solids. Emulsion and

wettability problems should not be a factor if the diesel

is obtained at the refinery before certain motor fuel

additives are included. Diesel oil is quite expensive

compared to crude oil.

Clear Water Fluld-Practical Application

S ou rce of W ater

Formation Saltwater-When available, forma-tion saltwater isa common workover fluid since the cost

is low. Ifit is clean, formation saltwater should be ideal

from the standpoint of minimizing formation damage

due to swelling or dispersion of clays in sandstoneformations.

Although saltwater from surface separation facili-

ties is frequently considered to be natural water from the

formation, it often contains treating chemicals, fine

particles of oil, clay, silt, paraffin, asphaItene, or scale,



8-4 PRODUCTION OPERATIONSNOL. 1

Well Completions, Workover, and Stimulation

and it therefore may cause appreciable formation

damage. (Fig. 8~1).

Even filtered formation saltwater may contain oil

treating surfactants (cationic emulsion breakers) which

may cause wettability or emulsion problems. Field

checks can be run using API RP 42 procedures.

Seawater or Bay Water-Due to availability, it is

often used in coastal areas. Again, it frequently contains

clays and other fines that cause plugging.

As shown in Figure 8~1, untreated bay water caused

serious plugging of Cypress sandstone cores. Depend-

ing on the salinity of bay water, it may be necessary to

add NaCl or KCl to prevent clay disturbance.

Prepared Saltwater-Fresh water is often desir~·able as a basic fluid due to the difficulty of obtaining

clean sea or formation water. Desired type and amount

of salt is then added. Where clean brine is available at

low cost, it may be preferable to purchase brine rather

than mix it on location.

Salt Type, Concentration for Prepared Fluid

Practicalities-From the standpoint of preventing

formation damage in sandstones due. to disturbance of

smectite or mixed-layer clays, the prepared saltwater

should, theoretically, match the formation water in cat-

ion type and concentration.

It is difficult to match formation brine, however,

and laboratory results show that 3% to 5% sodium

chloride, 1% calcium chloride, or 1% potassium chlo-

ride will limit swelling of clays in most formations. In

practice these concentrations are often doubled.

Limitation of CaCI2-In certain formations so-

dium smectite can be flocculated (shrunk) by contact

with calcium ions even in low concentrations. Thus, the

clay may become mobile, bridge in pore restrictions and

cause permeability reduction,

Where this is the case, 1% or 2% potassium chloride

should be used rather than calcium chloride since the

potassium ion will prevent swelling; in addition, low

concentrations will not flocculate the sodium smectite.

Additional objections to the use of calcium chloride

result from the observation that field mixed solutions of

CaC12 usually exhibit pH ofl o~10.5 which may disperse

formation clays. CaCI2. is also incompatible with some

viscosifiers and many formation saltwaters.

Extreme Water Sensitivity-In some very water

sensitive formations, 2% ammonium chloride brine

(while quite expensive) seems to stabilize formation

clays. Some small number of sand formations shouldnot be contacted by water of any ionic characteristics.

Emulsion-Wetfabillty Problems

When the brine fluid base is clean fresh water,

wettability and emulsion problems theoretically should

not be a concern. However, even here contamination

from anyone of many sources often occurs.

Field Checks-Best practice dictates that the ac-

tual work over fluid be checked to insure that it does not

form a stable emulsion with the reservoir oil or that it

does not oil-wet the reservoir rock.

This is particularly true where formation saltwateris used, or where corrosion inhibitors or biocides are

used. Field checks can be run using the simple tech-

niques of the API RP 42 Visual Wettability and Emul-

sion Breakout tests.

Prevention is the Key-,,-Usually an unsatisfactory

emulsifying or wettability situation can be corrected by

the addition of a small amount (0.1%) of the proper

surfactant.

As a general rule, workover fluids for sandstone

formations where productivity is important should con-

tain the proper surfactant to prevent any possibility of

emulsion in the formation and to leave the formation

around the wellbore strongly water-wet,

Viscosity Control-Fluid Loss Control

A number of additives are available to provide

"viscosity, " thereby increasing the lifting, carrying, and

suspending capacity of the fluid. In the Bingham plastic

representation of viscosity, "plasticviscosity" relates to

flow resistance between particles as well as the viscos-

ity of the continuous fluid phase; and "yield point"

relates to suspending capability when the fluid is at rest.

Completion fluid viscosity builders are all long

chain polymers or colloids. They also providefluid loss.

control by an indepth plugging mechanism which ex-

tends some distance back within the radial pore system.

Under high shear long polymer molecules straighten out

and can move some distance through the pore system.

However, as velocity decreases in the radial flow system

away from the wellbore, these molecules coil up, in-

creasing viscosity and apparently acting as much larger

molecules.Plugging is subsequently reduced by back-

flow and. degradation, but this process is usually not



Completion and Workover Fluids 8-5

complete, and formation damage remains. Thus, any use

of viscosity builders must be carefully justified.

Ideally, fluid loss control should be obtained

strictly by a bridging mechanism at the face of theformation. This can be done effectively by use of prop-

erly sized particles. Particles larger than one-half the

pore size should bridge at the pore entrance. However,

a range of particle sizes is required to reduce bridgepermeability. Colloids or "plastic particles" are neededto complete the plug and further reduce permeability.

The bridge should form and stabilize quickly to mini-

mize movement of fines into the pore system. Again

fluid loss control materials obviously plug pore

spaces-and removal is not nearly 100% effective.

Thus, they must be carefully justified.'

Viscosity Builders

Both natural and processed polymers are used in

completion fluid formulations. Among them are: guar

gum, starch, hydroxyethyl cellulose (HEC), car-

boxymethyl cellulose (CMC), and biopolymer (xan-than). Appendix H of Chapter 8, Volume 2, Fracturing,

contains a detailed discussion of oilfield polymers.

Natural Polymers-Guar gum is a hydrocolloid

that swells on contact with water to provide viscosity

and fluid loss control. A filter cake is deposited, which

may interfere even with squeeze cementing. Figure 8-2

shows plugging resulting from injection of about twentypore volumes of unbroken guar gum into a sandstone

core. Permeability regain after backflow was only 25%.In a radial flow system, reduction in productivity would

I I II E I I ~

],000 t-=:~-l-i'o.1_l!l o~

f-;:;~~:t::~ ~'Et:> .1' ' '

500 - - - : a - + -aI : I

1 1I I i

25% of original

I I per~bjlily

glOO_! . . . . . .

i --

~ 50

o fI Ii

: I . Ir-~i ,---

._ _ - - _ -

II

~- -~0 =± -:-- 1-- -- '----

-=t. 1 1 :- - _ .~4- c : - - - : - - -5 1·.....

0 100 200 300

Cumulative injection, pv

FIG. 8-2-Unbroken gusr gum_8 Permission to pub-lish by The Society of Petroleum Engineers_

depend on the depth of the reduced permeability zone

back from the wellbore. If, for example, the depth of

damage was 12 in., productivity would be reduced to

about 65% of the undamaged productivity.

Guar gum usually contains from 5-15% impurities.

Guar gum stability is affected by changes in pH. It forms

an insoluble floc in contact with isopropyl alcohol.Currently guar gum is not recommended for workover'fluids. .

Starch primarily is used to provide fluid loss con-

trol. Other polymers may be needed for carrying capac-ity. Overall cost of starch fluids is significantly lower

than guar gum or other polymers, but higher concentra-

tions of starch are required. Starch has no inherent

bacterial control. Permeability loss due to plugging issignificant; thus starch is losing popularity.

Xanthan provides good carrying capacity and fluidloss control. Viscosity at low shear rates, less than 5sec'", is significantly better than HEC at similar poly-

mer loading. High temperature stability is also betterthan HEC. Gel strength properties provide stable sus-pensions of calcium carbonate bridging (or weighting)particles, but may make removal of undesirable fine

solids more difficult. Xanthan is not completely re-

moved by HCI acid. Recovery of coiled Xanthan mole-cules from the formation pore system is difficult, thus,

significant plugging may result.

Processed Natural Polymers-BEC(hydroxyethyl cellulose) has many desirable properties

and is currently a commonly used viscosifier-but it

must be properly hydrated. Itprovides:

• Good carrying capacity for hole cleaning.

• Good flUid loss control (in combination withbridging solids),

• Low gel strength to drop out undesirable solidsin surface pits.

• Is degradable in HCl-or with enzyme or oxi-dizing breakers.

Unbroken HEC (without bridging particles) causes

significant permeability reduction even after backflow.Damage is not asgreat aswith unbroken guar. Acid-bro-

ken HEC (Fig. 8-3) shows little fluid loss control (with-out bridging solids) but complete permeability regain.

CMC (carboxymethyl cellulose) of the commercial

grade used in drilling fluids should never be used incontact with aproducing zone, due to irreparable forma-

tion damage. Insoluble products are formed in contactwith trivalent ions.



8-6 PRODUCTIONOPERATIONSNOL.1

We ll C omp le tio ns , Wo rk ov er , a nd S timu la tio n

ii'

Cumulative injection, pv

l 'OOO§~~~100% of original~ermeability

500~ ... .. .. ."";----f- ~ --:f I)

i\.. -;- .~ I ..-

: I---"'~ :1 1 i I

i 'i

I----i-----I-----.-+----+-+----t--rt---.-.-~

~-+·-----_l_-+--I +----++1--- f--+- ----

o~-~I~--_r--,,----~;__.+--oI-r--~

_.:---+.--_.+.---:r+-- rl-.. - -- t- ~ .~-" -.",.I I I I- - - - - - - r - : - - - - + - - - r _ . - - H E C I 7 d r · l < Y & r ' C . I I U ~ O · r - - - -

20~--~----L-~~--~~--~--~c-~o 100 200 300

FIG_ 8-3-Acid-broken HEC_B Permission to publishby The Society of Petroleum Engineers_

Fluid Loss Control

Due to unregained permeability loss, most currently

available viscosity builders should not be used withoutproper bridging particles to prevent movement of the

viscosity colloids into the formation pore system,Bridging particles must meet two criteria:

• Form a stable, low-permeability bridge quickly,

• Be removable by degradation or backflow.

Calcium Carbonate-This material is available in

several size ranges as shown in Table 8-1. For most

formation pore sizes "200 mesh" particle range should

be used. CaC03, if contacted by HCl, is completely

soluble.

.TABLE 8-1

Calcium Carbonate Particle Sizes

Diameter-Microns

Designation mean maximum

3_ 2 18

160

420

M ic ro (4 00 m e sh )

F in e ( 20 0 m e sh )

M e dium (7 0 m e sh )

60

213

Used in conjunction with HEC to provide colloids

for carrying capacity-and to further reduce the perme-

ability of the "bridge"--excellent fluid loss control isprovided with almost perfect permeability regain-if

particles are contacted with HCl acid.

Figure 8-4 shows results of lab tests using an unfil-tered bay water (136 ppm fine solids) with 5,%NaCl, 1.0

lb/bbl HEC and 10 lb/bbl CaC03. Bridging was almost

immediate, fluid loss control excellent, and after contact

with HCl acid regain was 93%.

It should be noted that in a field situation acid

contact with the bridged CaC03 cannot always be as~

sured, and some permeability loss may remain.

In gravel-packing at least partial backflow of "200

mesh" bridging solids through the pack is possible with10-20 mesh gravel. Backflow probably would not occur

through a tight pack of 20-40 mesh gravel.

Oil Soluble Resins-These are available in graded

size ranges needed for effective bridging action. While

quite effective in brine water fluids they are quickly

50 0

J = = t=t-~ ."

~~;;;; ~~~;;;:.;; ~.~i ~ EL-. ,~l m~"_

I - " "

. . . . . . -

! " I x "Completion fluid(composed of HEC,

unfiltered bay water,

and calcium carbonate)

0

1

~idtreati

1,000

100

5

o 10 0 200 300

Cumulative injectton. pv

FIG_ B-4-ldeal fluid loss control and permeabil ityregain in lab test. 8 Permission to publish by TheSociety of Petroleum Engineers_



C omp le tio n a nd Wo rk ov er F lu id s 8- 7

removed by low oil concentrations (2%). Also, tempera-

ture stability is a concern since some resins tend to melt

even at relatively low temperature.Within these limitations, the use of oil soluble res-

ins appears to be a suitable approach to the problems of

effective fluid loss control with effective permeability

regain.

GradedRock Salt-Where saturated salt fluids are

used, graded rock salt with HEC can provide effective

fluid loss control.

Field Applications

To facilitate field use, several suppliers combine

polymer viscosifiers and graded calcium carbonate into

one-package completion fluid systems. Polybrine from

M-I and Solukleen from BrineAdd are typical of these

systems. Solukleen contains oil soluble resin rather than

CaC03. Usually 1-4 lbslbbl of these products are re-

quired to prepare a satisfactory fluid. HEC-I0 is avail-

able where solids are not desired for fluid loss control.

Polybrine is a prepared mixture of polymers with a

low concentration of 200-mesh calcium carbonate par-

ticles. All components are acid soluble. In 8.5-10.0

lb/gal brine (KCl, NaCl or CaCli! 1.0 to 4.0 lblbbl

Polybrine provides Marsh Funnel viscosity of 33 to 50

sec/qt and API fluid loss of 13-18 cc. Aluminum

stearate (0.25 to 0.50 lb/bbl) must be added to brineprior to mixing Polybrine to prevent foaming.

Mixing or hydrating polymers must be carefully

done to obtain reasonable viscosity and to avoid

microgels or fish eyes. See Appendix 4C, Chapter 4,

Sand Control, for detailed recommendations. Briefly.

starting with freshwater pH should be lowered to 4-5,

after which polymer should be added and dispersed

through about 10 circulation cycles. The pH can then be

increased to 8-10 to initiate the hydration process.

Shearing by circulating through a choke device, or com-

mercial shearing devices (again about 10 cycles ) should

complete the hydration. Over shearing will significantly

reduce viscosity, whereas, with under shearing, micro-gels will remain. Thus, the shearing period should be

monitored by filtration tests or other means.

A satisfactory calcium carbonate fluid can be pre-

pared by adding 5 to 15 lb/bbl of 200-mesh calcium

carbonate to solids-free salt solution containing 0.25 to

0.50 lb/bbl Xanvis. This should provide effective seep-

age control, and sufficient viscosity to circulate out sand

or silt. Higher concentrations of polymer may be re-

quired to lift large cuttings or shale if the rig circulatingcapacity is limited.

In well killing, an effective technique is to circulate

a "pill" (10-15 bbl) of fluid containing a high concen-

tration of polymer and calcium carbonate particles. This

establishes an initial bridge. Polymer and particle con-

centration can then be reduced. When and if additional

cleaning orchip lifting capacity is needed, another pill

can be circulated. .

Loss of circulation problems can usually be solved

by the pill technique using additional polymer for car-

rying capacity with a coarser grade of calcium carbonate

to bridge.

Salt Solutions if Increased Density is Needed

Table 8-2 shows the approximate density range of

solids-free salt solutions:

TABLE 8-2

Density Range of Salt Solutions

Dens it y ( Ib lg al ) Saft solutions

B.S. 9.78.S. 9.B

9.B-11.0

11.0-11.711.7-15.0

15.2-19.2

Po ta ss ium ch lo r id e

Sodi um ch lo r id e

Sodi um ch to r id e -c a lc lum chl or id e

Ca l ci um ch lo r ideC a lc ium c hlo rid !H :8 tc lum b rom id eC a lc ium c hlo rid e- ca lc ium b rom id e, z in c b rom id e

Potassium chloride can be mixed to provide den-

sities up to about 9.7 lb/gal at 85°F, as shown in Table

8-3.

TABLE 8-3

Density of KCI Fluids

%KCf fb Kef pe r bbf Sp Gr o f solution Dens it y I b lg a/

1 3.52 1.0046 8.37

2 7.03 1.0110 8.42

3 10.56 1.0175 8.48

4 14.08 1.0239 8.53

6 21.12 1.0369 B.64

8 2B.16 1.0500 8.75

10 35.20 1.0633 8.86

15 52.79 1.0966 9.15

20 70.39 1.1328 9.44

25 ~7.9B 1.1670 9.72



8- 8 PRO DUCTIO N O PERATIO NSNO L. 1

W e ll C omp le tio ns , W o rk ov er , a nd S tim u la tio n

Sodium chloride can be mixed to provide densities

up to 9.8 lb/gal. Figure 8-5 shows quantities of water

and salt required for 100 barrels of solution. Sodium

chloride-calcium chloride mixtures can provide densi-

ties from 10.0 to 11.0 lb/gal. Calcium chloride could be

used alone, but addition of sodium chloride reducescost. Material requirements are shown in Figure S-6.

Calcium chloride can be used for weights up to

11.71b/gal with material requirements as shown in Fig-ure 8-7. Dry calcium chloride is available intwo grades,

77% and 95%. The 95% minimum is preferred since

fewer unidentified solids are included.

Formulations of calcium chloride and calciumbromide can provide solids-free fluid densities up to ,

15.0 lb/gal. Use of zinc bromide can increase solids-free fluid density to 19.2 lb/gal. Mixing tables for high

density brines are shown in Appendix SA.

10.000

Ii

I.500

i§

~z 5.000!l

2.500

. . . . . . . . . .- ..................ater

- . . . . . . . . . . . . . . . . . . .1"----

Sodium chloride /95% . . l t)

//

V

V

/8.0 8.5 9.0 9.5 10.0

105

s

i95 j

8

i:is

. 111

85

FIG. 8-5-Material requirements for preparing so-dium chloride solutions.

Solutiond.... ~y.Pili at 60 f

Formation Damage-Laboratory core flow testsapparently do not show unfavorable fluid/rock interac-

tions with heavy brines-CaCI2. CaBrv'ZnBr2 or

CaClvCaBr2"ZnBr2' Recovery of heavy brines can beslow due to high viscosity. Even though reaction with

formation materials does not appear to be a serious

problem, incompatibility between CaCl2 completionfluids and formation brine can result in damaging pre-

cipitates. This problem is more severe if the formation

brine contains significant sulfate or bicarbonate concen-

tration. Ca(OHh and CaC03 might be precipitated due

to a temperature increase. These salts are acid soluble,

thus, reduction of pH tends to prevent precipitation.

Mixing of high density brines with seawater (high in

804) should be avoided.

Crystallizatlon-Since salt solubility varies with

temperature, each brine formulation will have a mini-

mum temperature at which it can be used. This crystal-

300

--~-- _~r

High-test flake

/ calcium chlor ide[9S,,"C>CI)

/'/

Y

I "' - . . . . . . . . . .Sodium chloride

(lOO%NoCIj

100

50

o10.0 11.0 12.0

Solutiond.~.lty. PPlat 60 F

~~

40~1 1: g"l::S

30 3 !"iii

"

FIG. 8-B-Material requirements for preparing cal-cium chloride-sodium chloride solutions.



Completion andWorkover Fluids 8-9

N

C 3(tI

Q

e f t .oo r §25f : : : g'0020.!:!~

-;;;.!:! 15'C.c

c:m 10:::Io

~

" ' " t-, . . . . . . . . . .~ . . . ~

J

1/'

/I

L

Jo8.0 10.0 12.0 14.0

100c:

800:;::::::I

60"0UJ

:: 0.!:!

00~I:::W

iii: =

: : ac o

W Uo 80:00«I "

-e 40J:::I

E-:::IE 0EW._ a.£E:2~

k4

~ -,. . .V<, . . . .

i " " ' I o o . . ~

~II'

V+-V/

/

c

120 : 8_':::I

100die-III«1-: = 0

90 :c:cm.!:!

8000~

Solution density, ppg at 60°F

20

15

10

5

o8.0 10.0 1 2.0 14.0

Solution density, ppg at 60°F

FIG. 8-7-Material requirements for calcium chloride solutions.

lization temperature (Fig. 8-8) is the temperature at

which salt crystals first form as the brine is cooled.

Lower crystallization temperatures can be obtained by

using higher percentages of the more soluble salt. Most

brines can be cooled to temperatures well below the

crystallization point before the quantity of precipitated

salt interferes with routine handling. Crystals redissolvewhen the brine is heated above the crystallization tem-

perature. Heating of some fluids in the surface storage

tanks may be necessary. .

Corrosivity-Toxicity~afety-When mixing

high concentrations of CaCI, CaBr2, or ZnBr2' precau-

tions should be taken to keep the dry chemical dust out

of eyes and lungs. Rubber protective clothing should be

worn to prevent skin damage. Considerable heat may be

generated, thus, precautions should be taken to prevent

bums. CaCIrCaBr2 brinetoxicity is low enough to

allow use of these solutions in marine waters. ZnBr2 can

be toxic to fish, which limits its use in offshore areas.

Onshore, precautions must be taken to avoid contami-

nation of water supplies. CaC12-CaBr2 brines are alka-

line, whereas ZnBr2 brines are slightly acidic and

therefore more corrosive. Figure 8-9 shows corrosion

rates of high weight brines inhibited with 0.4% Corban

333 (Dowell). Oxygen solubility decreases as brine den-

sity increases; thus, oxygen scavengers are not needed

in heavy brines.

Viscosity-Heavy brines have inherent viscosity

(3-20 cps). If more viscosity is needed HEC can be

~2 ! +2

: : : : I

~Q

EC IIt-

1~acf2jI d~\"", '1)

.

~r ,/v,f,;

o _ L ~ ro ' 1 \ I

\cacf2V

15

+60

+40

-20

-60

8 9 10 11 12 13 14

FIG. ~.8-Crystallization temperature of salt solu-tions. Permission to publish by Gulf Publishing Co.

Density, pp g



8-10 PRODUCTIONOPERATIONSNOL.1

We ll C omp le tio ns , Wo rk ov er , a nd S timu la tio n

15r-------------------~--------~

----- 17.6 Ib /ga l CaCI2• CaBrz ,ZnBr2 Br ine

............... 15.0 Ib /g al C aC I2• CaBt2 Brine

-.-.~ : 11 .6 Ib /ga l B rine

. .'. . . •~/./

",. . . .~.. ",

. . . . . . . . . . . . . . . . ,. . . ~ - - . ~

Temperature , O F

FIG. 8-9-Corrosion rates of weighted brines inhib-ited with 0.4% Corban 333, based on 30 day expo-sure of NBOcoupons. Courtesy Dowell.

added, usually in concentrations of 0.25 to 1.0 lblbbJ.Polymer hydration is slower in high density brines.

Rapid agitation is important and heat may be needed.Too rapid addition will cause clumping. All polymer

should be added over one circulation since dispersion in

previously thickened brine is more difficult. Brines'

thickened with HEC can be thinned by addition of an

oxidizing breaker such as calcium hypochlorite.

Cost-Heavy brines are very expensive. A 15.0lb/gal CaCIrCaBr2 brine costs about 25 times more than

a 10.0 lb/gal CaCI2 "new" brine. An 18.0 Ib/gal CaC1r

CaBrrZnBr2 brine costs over 80 times more than a 10.0Iblgal CaCI2 brine. Fluid recovery and reuse must be

considered to minimize cost. Measures to avoid acci-

dental contamination or loss of brines in transport must

be taken. Closed tanks inay be needed to prevent hygro-scopic absorption of moisture from the air with atten-

dant loss of density. Fluid loss to the formation must be

considered.

.Minimum standards for reconditioned high-den-

sity brine (see Appendix SA) should go far:beyond merefiltration, depending on the previous use-history of the

specific brine batch, and the next intended applica-

tion.I8

, w! :i li ' · 1

, i i i

"

Iblgsl spgr /blgs/ spgr

8.5 1.020 0.35 0.042

9 1.080 0.29 0.035

10 1.201 0.26 0.031

11 1.321 0.23 0.028

12 1.441 0.20 0.024

13 1.561 0.16 0.019

14 1.681 0.13 0.D16

15 1.B01 0.12 0.014

Temperature Effects on Brine Density-As the

temperature of any water solution is raised, the volume

is increased, and density is reduced. Where minimum

formation pressure overload is maintained this effect

can be important. Table 8-4 can be used to make the

needed adjustment. The decrease in density is more

important in the lower weight fluids.

TABLE 8-4

Fluid Density Adjustment For.Downhole

Temperature Effect

Surface-messured density

L oss in d ens ity p er 1 00 'F

r ise i n a v er age c ir cu la ti ng

t emper at ur e a bove

sur fa ce-mea sur ed t empe re tu re

Use of Solid Particles to Provide Density-Cal-cium carbonate (200 mesh) can be used to obtain higher.

density fluids. Although viscosity and gel strength will

be needed to suspend the solid material, this approachmay be desirable where densities exceed 11.0 lb/gal.

Iron carbonate, barium carbonate, and ferric oxide

(all acid soluble) also can be used as weighting solids.

The following equations estimate the weight of solids

needed to obtain a certain fluid density and the resulting

increase in fluid volume.

Weighting material required:

W = K(Pj - Pi)

C - Pj

Increase involume: dVj = WI K

W =weighting material needed, lb/bbl of

initial fluid.

Pj=fluid density desired, lb/gal.

Pi =densityof available brine, lb/gal,

aVi =volume increase,bbllbbl initial fluid.

K, C =constants forweighting material (from

Table 8-5).



Completion andWorkover Fluids 8-11

TABLE 8-5

Solid Particles to Provide Density Increase

Density

Speciflc increase Equation

W eighting Gravity obtainab le constants

material spgr IblgslK C

Ca lc ium ca rbona te 2.7 3.5 945 22.5

I ron ca rbona te 3.85 6.5 1348 32.1

Bar ium ca rbona te 4.43 8.0 1551 37.0

Fe rr ic o x id e 5.24 10.0 1.834 43.7

Based on the above relations, 11.5 lb/gal CaCl2

brine would require 150 lblbbl of calcium carbonate to

prepare a 13.0 lb/gal fluid. Volume increase would be

16 bblliOO bbl of initial brine. Adequate suspension

qualities would probably require 0.5 to 1.0 lb/bbl poly-

mer. Settling should be checked before putting fluid inthe hole. If settling occurs, more polymer is required.

For effective fluid loss control some of the calcium

carbonate should be larger than the 200-mesh size

range. Suspension improves, however, as particle size

decreases. As an alternate approach initial fluid loss

control could be established with a "pill" of gradedcalcium carbonate, after which 200-mesh size range

could be used for density requirements.

Care and Maintenance of Clean Saltwater

Fluids

These points are important in the care and mainte-

nance of clean saltwater fluids:

• Dirty mixing and storage tanks or dirty vacuum

tanks are a common source of contamination to

a clean workover fluid system. Tanks must be

thoroughly cleaned before use.

• Workover rig tanks should be equipped withsumps and bottom baffles to contain settlings.

Suction should be about 18in. offbottom. Tanks

should have easily accessible clean-out plates.

Rounded comers aid cleaning.

• Settlings in workover tanks should be checkedhourly and cleaned as needed. Samples from the

pump discharge are helpful in checking for unde-

sirable solids.

• Dirty tubing strings are often a source of rust,scale, pipe dope, etc. They can best be cleaned in

the well by setting a wireline plug at the bottom,running a string of l-in., or coiled tubing, and

circulating HCI, IPA or simply water with about

1 lblgal frac sand for scouring. Ifa sliding sleeveis available above the packer, HCI can be circu-

lated to the bottom of the tubing, then reversed

out; however, a bottom tubing plug is desirable.

• A 4-iu'. cone desilter properly operated shouldtake out a high percentage of solids down to

10-20 microns, with decreasing percentage re-

moval of solids down to 2-3 microns.

• For situations where clean no-solids fluids are

critical (i.e., sand control), filters should beused. Two filter systems are commonly avail-

able: Cartridge, or pot units; and diatomaceous

earth (DE), or filter press units. Cartridge filters

using absolute rated pleated cartridges can do an

excellent job of removing almost all solids « 10

ppm). However, they are most cost effective

when the starting fluid has nomore than 100 ppm

solids.

Filter press units can handle starting fluid with

significantly higher solids loading (> 5,000ppm), but have difficulty reducing solids to the

< 50 ppm range. Solids bleed-through can be a

problem.

An ideal setup would contain a filter press inseries with a cartridge system downstream. SeeAppendix 8B for details of filtering. . .

• Shell work has shown that surface filtration

alone is not enough to insure a no-solids fluid

at the bottom of the hole. Fluid previously fil-

tered through a 2-micron nominal unit was circu-

lated through a tubing string having additional

filters at the top and bottom. The top tubing filter

remained clean, but the bottom filter consistently

plugged with chemically formed iron oxide, and

particulate matter from the tubing,i.e., pipedope, scale, and rust. .

• Laboratory work by Union has emphasized the

point that iron oxide particles are a serious plug-

ging material. The reaction between oxygen and

iron can be prevented by addition of sodium

sulfite (and cobalt sulfate as a catalyst) to scav-enge the oxygen and sodium citrate to sequester

the iron.



8-12 PRODUCTION OPERATIONSNOL.1

Well Completions, Workover, and Stimulation

Conventional Water-Base Mud

Economics and availability sometimes suggest use

ofwater-base mud rather than weighted saltwater where

weights above 11.5lb/gal are required. Water-base mud

contains clay thinners and dispersants and a high con-

centration of fine solids certain to cause irreparable

formation damage both in the pore system and on the

face of the formation,

Thus, water-base mud should never be used ex-

cept in zones to be abandoned.

In new wells the presence of mud can be avoided

economically by pumping the primary cement plug

down with saltwater or oil. Mud can be circulated out

before perforating using production tubing string; how-

ever, once mud solids are inside the production casingcomplete removal is difficult requiring long circulation

and filtering cycles and complex alternating pills of

surfactant and scouring fluids.

Oil~Baseor Invert-Emulsion Muds

These muds are usually less damaging from the

standpoint of clay problems than conventional water-

.base muds since filtrate is oil and very low filtration

rates can be obtained. Most oil-base systems contain

strong emulsifiers which may oil-wet the formation,

and blown asphalt which can plug the formation as well

as present an oil-wet surface. Thus; emulsion blockagecould be severe.

Some invert-emulsion systems utilize emulsifiers

chosen to minimize this problem. Perforating in

weighted oil muds could form mud plugs which would

not be removed by backflowing. The cost of oil-base

and invert-emulsion muds is relatively high, and usually

can be justified only in cases where formation clays

would be seriously damaged by conventional water-

base mud.

Foam

In low fluid level wells where circulation of solids-

free oil or water-base fluids would not be possible,

foams can be used for certain workover operations such

as washing out sand, drilling in or deepening. Depend-ing on the ratio of air to foam water circulated, flow

gradients as low as 0.1 to 0.2 psi/ft are possible.

Foam is a mechanical mixture of air or gas dis-

persed in clean fresh water or field brine containing a

small amount of surfactant. Surfactant type and concen-

tration should be selected to develop a stable foam with

the specific well fluids encountered.

Equipment requirements include an air compressor

or source of measured gas, mixing tanks for foamer

solution, a liquid pump, metering facilities for air andliquid volumes, and a foam generator to provide good

dispersion of the air in the foam solution.

Equipment needed to handle foam returns includes

a tubing rotating head or stripper assembly at the well-

head to divert the foam returns into a blooie line and to

a disposal pit. At the pit, a water spray system may berequired to break the foam. Aluminum Stearate acts as

a good defoamer.

Typical air compressor requirements are 500 to

1000 cfm at a pressure of about 500 psi. Water andfoaming agent are mixed and injected into the air stream

ata rate oflO to 20 gal/min. Foaming agent concentra-tions of 0.5 to 1.0% are typical. Bentonite or polymers

are added to the water to produce a "stiff foam" having

greater carrying capacity.

The prime advantage of foam is the combination of

low density and high lifting capacity at moderate flowvelocities. Bottomhole pressures as low as 50 psi have

been measured at 2,900 ft while circulating foam. Use

of foam in sand washing is justified on the basis of a

much faster operation and more complete sand removal.

Foam generated with natural gas or nitrogen has

been used in connection with coiled tubing or snubbing

equipment to clean out higher pressure wells without

killing them. Foam returns in these cases are directed

through the normal flowline system to production sepa-

ration facilities.

Being a compressible two-phase fluid, the rheology

of a foam system is complicated. Computer programs

are available to determine injection pressures, bottom-

hole circulating pressure, annular velocity, and. foam-lifting ability at various gas and foamer solution rates.

These programs consider liquid and gas entry from the

formation, temperature gradients, hole deviation, etc.

Perforating Fluids

Perforating fluids are not necessarily a distinct typeof fluid, but are distinguished here to emphasize the

importance of perforating in a no-solids fluid.

Saltwater or Oil-When absolutely clean, these do

not cause solids plugging of perforations, but if the

pressure differential is into the formation, fine particles

of charge debris will be carried into the perforation.

Acetic Acid-This is an excellent perforating fluid

for carbonates under most conditions. In the absence

ofH2S, acetic acid can be inhibited against any type of



Completion and Workover Fluids

steel corrosion for long periods at high temperatures.

Normally a ten percent solution is used. Acetic acid plus

H2S is very difficult to inhibit against embrittlement.Acetic acid will put iron sulfide and mineral carbonate

in solution. These may result in added corrosion prob-

lems.

Nitrogen-A short fluid column with a long nitro-

gen column has advantages as a perforating fluid in low

pressure formations, or where rig time or swabbing

costs are very high, orwhere special test programs make

it imperative that formation contamination be avoided.

Gas Wells-These can be completed economically

in "clean fluid" by perforating one or two holes, bring-

ing the well in and cleaning to remove as much wellbore

fluid as possible, then perforating the remaining zoneswith only a short liquid column in the hole (to prevent

gun swelling).

Packer F,uids

Criteria-Water~base drilling muds as used today

are not good packer fluids. An acceptable packer fluid

must meet two major criteria:

• Limit settling of mud solids andlor development

of high gelation characteristics.

• Provide protection from corrosion or embrittle-

ment.

In most wells the preferred and recommended

packer fluid is an inhibited clean (solids-free)

saltwater. It is not necessary that the packer fluid have

sufficient density to control the formation pressure;

however, this is often desirable. If the formation pres-

sure gradient is less than 0.51 psi/ft (9.8 ppg), then clean

inhibited sodium chloride is recommended. Ifthe for-mation pressure gradient is no higher than 0.61 psi/ft

(11.7 ppg), then clean inhibited calcium chloride should

be used.

With formation pressure gradients higher than .61

psi/ft careful consideration of many factors, including

well supervision, is required. Use of clean inhibitedsodium chloride, potassium chloride, or calcium chlo-ride should be considered even though it will not over-

balance formation pressure. In the event of a problem,

the well can be killed by circulating an adequate density

fluid. Although expensive, calcium bromide may be thebest choice up to a density of. 78 psi/ft (15 ppg). A high

density oil-mud may be justified in some areas.

Biocides are not needed in saltwater packer fluids,as long as the water does not contain sulfates or poly-

mers. Biocides are poison and must be handled with

care. Oxygen scavengers are of little benefit. The oxy-gen will be quickly expended on the tubulars with only.

minor corrosion. A corrosion inhibitor is recom-mended. However, if the cationic inhibition enters a

sandstone formation, oil wetting may result. Keeping

the pH above 1O~10.5will minimize corrosion.

Crude oil and diesel are not recommended even

on low pressure wells. Both are relatively expensive and

may be more damaging than clean saltwater. Also theyare flammable and messy to handle. Extra care must be

taken to avoid spilling oil or diesel on the ground or

water.

Water-base muds (especially those with barites)

should never be used as packer fluids due to the prob-

ability that solids will settle out and stick the tubing.Unless subsequent well work can be done

through-tubing, the tubing will have to be cut or backed

offup hole, and an expensive and hazardous wash over

operations made to remove the tubing and packer. In

addition to causing formation damage the water-base

mud will provide little protection in killing the well

since the mud will not be pumpable.

Oil-base muds (oil-mud) should be used only in

special circumstances. A high pressure sour gas well

in a sensitive area could be justification for its use.

Where water contact with casing or tubing is eliminated,

local cell electrochemical actions cannot occur, thus

corrosion or embrittlement is negated.

Well Killing

Circulation rather than bullheading (pumping in

with no returns) is the preferable way to kill conven-

tional completions. An adjustable choke should be used

on the tubing outlet to hold a stable backpressure on theformation when killing a wen by reverse circulation.

For single completions on a packer, the recom-

mended procedure is as follows:

1.Fill the annulus, and tubing, if feasible.

2. Equalize tubing andannulus pressure. Open circulatingport in tubing or punch hole in tubing above packer.

3. Pump slowly down casing-tubing annulus (114to 112

bbls/min)as wireline tools are retrieved to build up a

backpressure on formation.

4. After wireline tools are retrieved, pump at a constantrate of2·3 bbls/min to build up 200~300psi on tubing.

5. Maintain a constant pump rate and manipulate the

adjustable choke, controlling tubing returns to keep

casing pressure constant.



8·14 PRO DUCTIO N O PERAT IO NSNO L. 1

We ll C om p le tio ns , Wo rk ov er , a nd S tim ula tio n

· · · . l i .' . , . I .I , . .

; I T ;

:l H: x :~

I i i;

When circulation is not possible-bullheading a

non-damaging fluid is best if formation will take fluid

without fracturing. Here are three important points.

• For "bullhead" well killing the surface pressure

plus (fluid gradient times depth) should be less

than formation fracturing pressure.

• Itmay be necessary to have a surface pressureregulator to prevent over-pressuring.

• If it is necessary to fracture the formation, the

size of the resulting fracture can be minimized by

low injection rates and high fluid loss (no-solids

fluid).

:: i




References

1. Glenn, E. E., and Slusser, M. L.: "Factors Affecting Well

Productivity: I, Drilling Fluid Filtration; and II, Drilling

Fluid Particle Invasion into Porous Media," Trans. AIME

(1957) 210, 126 and 132.

2 . Monaghan, P. H., Salathiel, R. A., Morgan, B. E., and

Kaiser, A. D., Jr.: "Laboratory Studies of Formation Dam-

age in Sands Containing Clays," Trans. AlME (1959) 216,

209.

3. Black, H. N., and Hower, W. F.: "Advantageous Use of

Potassium Chloride Water for Fracturing Water-Sensitive

Formations," API Paper 850-39-F (1965).

4. Simpson, J. P., and Barbee, R. D.: "Corrosivity of Water-Base Completion Fluids," 23rd Annual NACE Confer-

ence, Los Angeles, CA (March 3, 1967).

5. Hutchinson, S. 0.: "Foam Workovers Cut Costs 50%,"

World Oil (Nov. 1969).

6. Christensen, R. J., Connor, R. K., and Millhone, R. S.:

"Applications of Stable Foam in Canada," Oilweek (Sept.

20, 1971).

7. Bruist, E. H.: "Better Performance of Gulf Coast Wells,"

SPE No. 4777, New Orleans (Feb. 1974).

8. Tutt le, R. N., and Barkman, J. H.: "The Need for Non-Dam-

aging Drilling and Completion Fluids," JP T (Nov. 1974)

p. 1,221.

9. Suman, George 0., Jr.: Sand Control Handbook, Gulf

Publishing Company, Houston, TX (1975).

10. Sparlin, Derry, and Guidry, J. P.: "Study of Filters Used

for Filtering Work over Fluids," SPE Paper 7005, Third

Annual Formation Damage Symposium (Feb. 1978).

II. LIfrey, W. T.: "Recommended Procedures for Utilizing

High Cost Non-Damaging Fluids," SPE Paper No. 8794,

Fourth Annual Formation Damage Symposium (Jan.

1980).

12. Sharp, Keith W .: "Filtration of O il Field Brines-A Con-

ceptual Overview," SPE Paper No. 10657, Fifth SPE Sym-

posium on Formation Damage Control (March 1982).

13. Scheuerman, R. P.: "Guidelines for Using HEC Polymers

for Viscosifying Solids Free Completion and W orkover

Brines," SPE Paper No. 10666, Fifth SPE Symposium On

Formation Damage Control (March 1982).

14. Morganthaler, L. N.: "Formation Damage Tests of High-Density Brine Completion Fluids," SPE 14831 (Feb.

1986).

15. Parks, C. F., Clark, P. E., Barkat, Omar, and Halvaci, M.:.

"Characterizing Polymer Solutions by Viscosity and

Functional Testing," Amer. Chern Soc. (Sept. 1986).

16. Houchin, L. R., Hudson, L. M., Caothian, S., Daddazio,

G:, and Hashemi, R.: "Reducing Formation Damage

Through Two-Stage Polymer Filtration," SPE 15408 (Oct.

1986).

17. Nebmer, W. L.: "Viscoelastic Gravel-Pack Carrier Fluid,"

SPE 17168 (Feb. 1988).

18. Foxenberg, W. E., Houchin, L. R., and Javora, P. H.:

"Optimizing the Quality of High-Density Brines for Maxi-

mum Performance and Economic Value," SPE 24784,

Washington, D. C. (Oct. 1992).



8-16 PRODUCTION OPERATIONSNOL.

WenCompletions,Workover, and Stimulatio

Appendix SA

High Density Brine Completion Fluids

Availability and use of high density brines in place

of drilling muds in completing and working over wells

in abnormally pressured formations has played a signifi-cant role in reducing formation damage. The cost of

these brines, however, dictate that after use in one well

application, the b~ine must be recovered, analyzed for

contaminants, and reconditioned for use in the next well

application. Filtration is a necessary-but usually not

sufficient-reconditioning procedure. "

The first step is to properly sample and analyze the

brine. Contaminants in a solids-free brine include any

foreign substance which may cause formation damage,

i.e., corrosion inhibitors, surfactants, chemical washes,

iron, fluid loss control agents, polymer viscosity build-

ers, drilling fluid constituents; as well as suspended

solids. All of these substances can be effectively re-moved.

Foxenberg, et al.,18 proposed the following mini-

mum quality standards for high density completion fluidbrine.

TABLE 8A~1

Minimum Quality Standards for High Densfty

Completion Fluids

Parameter Specification

color co lorless(1)

cla rity ctysta l clea r

odor none "

fore ign matter absent

NTU ( tu rb id i ty ) < 1 0 u nits

v i scos it y (y ie l d pt) :! > 1 1 b /1 00 s q It

iron <10ppm

zinc < 1 0 p pm

o th er h ea v y m e ta ls < 1 0 p pm (2 )

polysaccharides passes test (3)

compa tibility passes test (4)

a lka linity < 200 ppm as C03

sulfa te < 100 ppm

density as sp e ci fi ed ( 5 )

TCT /LCTD as specified (5)

sa lt assay as specified (5)

pH as spec if ied (6 )

calcium Imagnesium 100 ppm (7 )

( 1 )" B rf ne s c on ta in in g z in c s alt s ( zin c b rom id e) a re lig ht y e lJ ow -lo -am be r.

( 2) Z in c- fr ee b rin es .

( 3) A c id h yd ro ly sis f ollo w ed by c ol or d ev e lo pm e nt w it h d ip he ny lam in e

produces ho m or e th an a fig ht b lue color.

(4 ) C ald um c hlo rid e/b ro mid e b rin es m us t n ot p ro du ce p re Cip ita te u po n

5 0: 50 d ilu tio n w ith d is ti lle d ( or d eio niz e d) w a te r o r s to ck s pe cif ic at io n

f lu id s , I .e ., 1t.S p pg C aC Il; 1 5.1 p pg C aC I2; 1 9.2 C aB r2-Z nB r2.

(5 ) D en sity , T CT IlC TD (T ru e C ry sta lliz atio n T em pe ra tu re /L as t C ry sta l to

D is so lv e) a nd s alt a ss ay s pe Cif ic atio ns a re s et a t m in im um s ta nd ar ds

a cc or din g t o b rin e s p ec if ic f ormu la tio ns :

1 1.6 p pg C aC I2

%CaCb

TCT/Lcm

d en sit y :: 1t.6 p pg m in im um

38 w t % m in im um

34· F/ 45 "F m a xim um

1 4.2 p pg C aB r2

%CaBI '2

TCTI lCTD

density = 1 4. 2 p p g m in im um

51.5 W I % m in im um

O°F /S"F max imum

19 .2 p p g Zn -Ca lB r2

%ZnBr2

%CaBI2

remere

densi ty/BO° = 1 9 .2 p p g m in im um

52.80 w t % minimum

22.BO w t % maximum

10 "F /19 "F max imum

(6) The pH of a dense brine as measured by diese l immersion w ith a pH

me te r e le c tr od e Is s et a cc or din g to b rin e co mp os itio n a nd d en sity .

E xa mp le s o f s to ck flu id p H s pe cif ic atio ns a re g iv en :

10.0 PP 9 NaCI

12.5 pp g N aB r

1 1.6 p pg C aC I2

1 4.2 p pg C aB r2

1 9.2 p pg Z n~ Ca /B r2

1 7.0 p pg Z n-C a/B r:a -C I2 (8 0" T Cn

p H 6.5 -7.5

pH 6.5 -7.5

p H 6.5 -7.5

pH 8.5 - 7.5

pH 0.8 - 2.0

pH 3.0 -4.0

(7) S od iu m a nd p ota ss iu m b rin es .




TABLE8A-2

Mixing Schedule; Calcium Chloride--Calcium Bromide Brine

Quan ti ti es f or 1bbllbrine

14 .2 1b1gal cal ci um b rom ide b ri ne

Br ine densi tyPelletized (95%) calcium chloride 11.S lb lgal calcium chloride brine

Iblgal at GO°FFlake (95%) calcium b romide Pe/{etfZed (95%) ca lc ium Ch lor ide

water CaCI:! CaBr CaBrbrine CaC /2brine CaCI: ! pe l letsCrystallization

bb l Ib Ib bb l bb l Ibtemp er at ur e OF

11.8 .8281 189.81 16.28 .0507 .9429 6.1 51

12.0 .8206 184.73 32.57 .1016 .8857 12.1 52

12.2 .8129 179.66 48.86 .1524 .8286 18.2- 54

12.4 .8053 174.58 65.15 .2032 .7715 24.2 54

12.6 .7977 169.51 81.43 .2540 .7143 30.3 55

12.8 .7901 164.43 9771 .3048 .6572 36.4 55

13.0 .7826 159.36 114.00 .3556 .6000 42.4 5713.2 .7749 154.29 130.28 . .4064 .5429 48.5 57

13.4 .7673 149.21 146.57 .4572 .4857 54.6 5B

13.6 .7597 144.14 162.86 .50BO .4286 60.6 58

13.8 .7522 139.06 179.14 .5589 .3714 66.7 58

14.0 .7446 133.99 195.43 .6069 .3143 72.8 58

14.2 .7369 128.92 211.71 .6604 .2572 78.8 59

14.4 .7293 123.84 228.00 .7113 .2000 84.9 61

14.6 .7217 118.77 244.28 .7620 .1429 90.9 63

14.8 .7142 113.69 280.57 .B128 .0858 97.0 65

15.0 .7066 108.62 276.86 .8637 .0286 103.0 66

N OT E: B rine s in this de ns ity ra ng e ca n b e m ixe d in s ev era l w ays a nd the for mula tio n liste d is n o! ne ce ssa rily th e p re fe rre d for mula tio n ..

TABLE8A-3

Mixing Schedule

Calcium Chloride--Calcium Bromide-Zinc Bromide Brine

Quan ti ti es f or 1b b l b ri ne

Br ine densi ty5 6. 7% z in c b romid e

Crystallizatfon19.7% ca/c/um bromide 53% calcium brom ide 9 5% cal cium c hl or id e

I blg al a t S O °Fbrlnebbl brine bbl pel/etslb

temperature O F

15.2 .024 .866 103.3 62

15.4 .071 .B26 9B.6 59

15.8 .119 .783 93.5 59

15.B .167 .741 88.4 57

16.0 .214 .699 83.4 54

16.2 .263 .656 78.3 52

16.4 .310 .613 73.2 50

16.6 .357 .572 68.2 47

16.8 .429 .508 60.6 4017.0 .442 .449 90.0 40

17.2 .495 .421 72.2 38

17.4 .561 .380 51.8 38

17.6 .619 .339 40.4 45

17.8 .667 .296 35.3 44

18.0 .714 .254 30.3 43

18.2 .762 .212 25.3 41

18.4 .810 .169 20.2 35

18.6 .857 .127 15.2 28

18.8 .905 .084 10.1 23

19.0 .952 .043 5.1 18

19.2 1.000 16

N OT E: B rine s in this d ens ity ra ng e ca n b e m ix ed in s ev era l w ay s a nd the fo rm ula tion lis te d is not ne ce ss arily the p re fe rre d form ula tion .



8-18 PRODUCTION OPERATIONSNOL. 1

We ll C omple tio ns , Wo rk ov er , a n d S timu la tio n

Appendix 88

There are two basic filtration processes for remov-

ing solids from a liquid. Depth filtration removes solids

by causing them to plate-out within the filter media.Surface filtration causes solids to plate-out on the outer

face of the filter media. A third mechanism, cake filtra-

tion, results when the filter is fully loaded from either

of the first two mechanisms, and continues as long as

the buildup of solids or filter cake remains permeable.

Cartridge filters are designed to use either thedepth mechanism (wound cylindrical cartridge) or the

surface mechanism (pleated cartridge). Wound car-

tridges have a broad range of pore sizes, relatively small

surface area, and are given an arbitrary nominal ratingby their manufacturer. They consist of wound yarns or

resin-bonded fibers that increase in density, thus offer-

ing smaller pore openings, toward the center. Larger

solids are trapped in the outer layers and progressivelysmaller particles lodge nearer the center. Pleated car-

tridges are only a few layers thick, have a narrow range

of pore sizes, relatively large surface area, and are given

an absolute rating based on the diameter of the smallest

hard spherical particle that will be retained under speci-fied NFPA test conditions.

Beta ratio is defined as:

B = Influent Particle Count GreaterThan SpeciJiedSize

Effluent Particle Count Greater Than Spectfiedsize

Beta ratio is converted to removal efficiency as

RE % = 100 [B - I]

B

Beta Ratio Removal Efficiency %

10100

1,0005,00010,000

·m ln lm um r ec omm en de d

90.099.099.90*99.9899.99

For a given pleated cartridge the Beta ratio varieswith particle size. Figure 8B-l shows Beta ratio curves

Filtration

for 0.5, 2.0, 5.0, 10.0,20.0, and 50.0 micron cartridges

from one manufacturer. Each cartridge has a different

Beta ratio for a given particle size, i.e., the 10 micron

absolute cartridge should remove 99% of the 2 micron

size particles.

Figure 8B-2 shows an ideal fluid cleaning system

wherein fluid returns from the well are taken over a

shale shaker, through a particle settling tank overflow-

ing into a residence tank, then pumped through thefiltration section, consisting of two banks each contain-

ing two filter pots. The first and second banks containnominal filter cartridges with 50micron ratings, and the

second contains 2 micron absolute rated cartridges. Thepots in each bank are manifolded such that one can betaken out of service to change filters while fluid contin-

ues to flow through the other.

The diatomaceous earth (DE) filter, orfilter press,is designed as a cake filter. The cake consists of dia-

toms, skeletal remains of microscopic aquatic plants,

which are porous, rigid, chemically inert and insoluble

in oilfield completion fluids. Ideally, they form a highly

permeable stable incompressible filter cake. The DEfilter press contains a series of canvas covered plates,Figure 8B-3, which are precoated with the DE clay

(1I8-in. thick) by fluid circulation to form the initial

cake. When the filter is put in service to initiate thefiltering cycle, solids removed from dirty fluid become

part of the cake. DE is usually added continually to

maintain filter cake permeability. The filter cycle ends

when the cake builds up to the point where flow is

reduced or differential pressure increased to a limiting

level. The plates are then opened, the cake removed

from the canvas sleeves and the cycle begins again.

Solids loading inmost completion fluids is difficult

to predict beforehand, but usually is more than 100 ppmand may vary over a wide range depending on the nature

of the operation. This means that a cartridge filter sys-

tem alone may not be economic if a 2 micron output

fluid is desired.

Filter press systems are good for reducing solids

concentration to 50 ppm even though input solids may

be in the 1,000 ppm range with slugs carrying 10-20,000

ppm. They do not provide specific micron size cutoff,

i.e., 2 micron, and efficiency is operator dependent.




B

et

a

R

a

t

I

o

05 10 20 50 Abs~Rating

FIG. 8B-1-Beta ratio curves for 0.5, 2.0, 5.0, 10.0, 20.0, and 50.0 micron cartridges.

5000 • ,~

J'

t l~

•~ •_ •_~ _I

"I

J,

1 1 -Jr ,

JIf

~~J

FILTEREDBRINE

TANK

CENTRIFUGALPUMP

1000

500

100

Pa rt ic le S iz e , M ic ro ns

2 MICRONABSOLUTE

50MICRON CENTRIFUGALNOMINAL PUMP

RIG PUMP

FIG. BB-2-Typical cartridge filter system.

BRINERESIDENCE

TANK

PARTICLESETTLING

TANK



8-20 P RO DU CTIO N O PER AT IO NSN OL. 1

We ll C omple tio ns , Wo rk ov e r, a n d S timu la tio n

FIG, BB-3-DE filter unit (Pal/ Well Technology).

The ideal system consists of a filter press unit in

series with a downstream absolute cartridge unit.

Variables that affect filtration performance include

flow rate, viscosity and surface area. Flow density, i.e.,

flow rate per unit filter area (gal/minlft2), that provides

optimum filter efficiency for 1 cp freshwater is about0.5 to 0.7 gal/minlft2. However, as fluid viscosity in-

creases flow density for optimum efficiency decreases

significantly.

Quality control of filtered fluids requires measure-

ment of solids in the effluent. Gravimetric analysis ismore accurate, but requires laboratory conditions, For

field use turbidity, recorded as NTU (Nephelometric

Turbidity Units), is a practical measure of fluid clarity.

Turbidity is measured with a Turbidity meter whichdetects the scattered intensity of an optical beam di-

rected through the solids-containing fluid. Turbidity

measurements are roughly proportional to the mass of

entrained solids,which is not necessarily total sus-

pended solids (ppm). Recorded versus circulation time,

NTUs can indicate when fluid cleanup has reached apoint of diminishing returns.

The Turbidity meter gives only qualitative results.

Where more definition is required it can be calibrated

by use of millipore filter tests.




Appendix B e

Commercial Completion Fluid Products

Listed below are products available from one service company (Dowell

Schlumberger) for use in completion, workover or gravel packing. Similar

materials are available from several other suppliers.

Product Name Description or Use

A-181-bisulfite oxygen scavenger

B-19-Xanvis gelling agentB-20-Xanvis breaker,. inorganic peroxide

D-47-defoamer '

F-68-Eze FloG-2--non-ionic surfactant foaming agent

H-15-15% HCl HEC breaker

J-164-HEC-IO gelling agentJ-168-soluble bridging material

J-211-lgs., CaC03

J-212-HEC, 19s., CaC03J-213-HEC, lgs., CaC031arge particles

J-214-CaC03J-218-ammonium persulfate HEC breakerJ-237 and J-275-liquid oil soluble fluid loss additive

J-285-ammonium chlorideJ-287-sodium bicarbonate, buffer

J-369, J-419-high weight brine thickenerJ-462-Pennpac gelling agent amine liquid

J-463-Pennpac gelling activatorL-I ~ritric acid, iron/pH control

L-62--nitrilotriacetic acid (NTA)-iron pH control

M-3-sodium carbonate, bufferM-76, M-133, M-155-water soluble, cationic bactericide

M-I17-potassium chloride

M-129--oxygen scavengerS-54, S-55~alcium bromide brine or dry sacked

Shellflo-S-liquid gelling agentDOWCIDE G-sodium pentachlorphenate bactericide

Comp Let Ions and Workover Fluids PO Chapter 8

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Transcript of Comp Let Ions and Workover Fluids PO Chapter 8