8/10/2019 SPE-30086-MS

1/12

Society of Petroleum

Engineers

SPE 3 86

Formation Damage due t Losses ea based Brine and How Was Revealed

Through Post Evaluation Scale Dissolver and Scale Inhibitor Squeeze

Treatments

K.

Lejon, Statoil

as,

J. Tuxen Thingvoll, Statoil

as,

E.A. Vollen, Statoil

as, P.

Hammonds, Baker Performance Chemicals

Copyright

1995,

Society

at

Petroleum Engineers, Inc,

This paper was prepared for presentation

at

the European Formation Damage Conference held In The Hague, The Netherlands, 15-16

May

1995,

This paperwasselected forpresentation by an SPE Program Committee following review of informationcontained inan abstract submitted by the author s). Contents ofthe paper, as presented,

have

not

been

reviewed

by

the Society of Petroleum Engineers and

are

subjected to correction

by

the author s ,

The material, as

presented, does

not

necessarily

reflect anyposition of

the

Society

of

Petroleum Engineers

Its officers

or members Papers presented

at SPE

meetings are SUbject

to publication review

y

Editorial

Committees

of

the

Society

of

Petroleum

Engineers

Permission to copy

is

restricted to a n abstract

of

not

more than 300

words. illustrations

may not be

copied,

The

abstract should contain conspicuous acknowledgment

of where

and by

whom

the paper

is

presented, Write Librarian, SPE, P,O.

Box

833836. Richardson. TX 75063-3836, U,S.A. Facsimile 214-952-9435).

ABSTRACT

Calcium based brine has regularly been used during workover

operations

on

naturally completed wells without any sign of

for-

mation damage.

In

gravel packed wells which have seen severe

losses

of

Ca based brine production decline was observed.

Fur some

of

the gravel packed wells the production decline oc-

curred when bringing the well on production after completion,

whilst

in

others, the

loss in

productivity occurred after sea water

breakthrough.

I

In

order

to

increase productivity

and

confirm the relationship

be-

tween productivity decline and formation of CaS0

4

scale due to

losses of completion brine, scale dissolver treatments were car

ried out.

The use of dissolver chemicals resulted

in

mobilization

and re-

moval

of

several hundred kilograms

of

solids from the near well

bore area.

A post-evaluation strategy to provide information about the na-

ture, origin

and

location

of

scale was successfully implemented.

More importantly, the dissolver treatments resulted

in

increased

oil production.

The findings and lessons learned have had several important

im-

plications

for

gravel pack completions

an d w ell

treatments

in

Statoi .

INTRODUCTION

Solutions

of

high density brines

of

calcium chloride and calcium

bromide are extensively used

in

workover and drilling opera

tions. Normally, this practice does not produce any deleterious

effects. However, the potential for formation damage due

to re-

action between calcium-based brine and water present

in

t he r es -

ervoir exists and is documented through laboratory studies and

field experience

2

3

References

and

figures

at e nd of

paper

75

Unfavorable mixing ratios of Ca-based brine

and

sea

water, used

as

solvent for chemicals or

as

displacing fluid, c an a ls o pl Oduce

favorable conditions for precipitation of solids

and

subsequent

formation damage.

In

addition, oilfield waters will deposit sparingly soluble salts

eg.

CaC0

3

) due to either changes

in

physical conditions e.g

temperature, pressure) or change

in

chemical composition loss

of gas, mixing

of

waters).

Scale deposits

are

commonly calcium carbonate; barium,

stl on-

tium and calcium sulphates; and various naturally occurring

ra-

dioactive materials NORM). The latter

are

commonly

precipitated with the other sulphate scales.

Carbonate scales

are

easily removed

by

acid treatment

and

cal

cium sulphate with moderate difficulty

by

using converters,

In oilfield operations Sulphate scales a re mor e commonly treated

with non-acid dissolvers. These formulations

are

blends of

chelating agents, accelerators, dispersants and other synergists.

4

The chelants are capable of forming soluble complexes with

metal ions. The stability

of

these complexes

is

known to depend

on the chelating agent and metal, solution pH, temperature,

etc.

For dissolution

to

occur, the solubility of the complex

m us t e x-

ceed that of the scale

as

indicated

by the

equations:

CaS0

4

s)

H

Ca2+

+

SO

l

Ca

2

+

+

EDTN- H

Ca EDTAl

aq)

Also, the scale must furnish metal ions

in

solution for chelation

to

occur. The strengths

of

chelant metal complexes

may be com-

pared from values

of

their stability constants

as

shown

in

Table I

8/10/2019 SPE-30086-MS

2/12

2

Formation

Damage due to Losses of Ca-based Brine and

How

Was Revealed

Through

Post Evaluation of Scale Dissolver and Scale

Inhibitor

Squeeze

Treatments

SPE 30086

Table

1:

S tabi li ty C lns tant s (loglllK) If Meta l Chelant

ClIInplexes'

elapsed from the time

of

completion to the apperance

of

the pro

duction problems,

Definition

of

productivity index:

PI

Q 10 P

s

- P Ibhp) where:

A list

of

events and observations leading to the verification of a

causal link between observed productivity problems and losses

of completion brine is given below,

Metal Chelant

NTA

HEDTA

EDTA

DTPA

A1

3

+ 11.40 14.40 10.30 18,70

Ca'+

6.40 8.30

10,70

10,80

Fe'+

8,30 12,20

14.30 16.40

Fe

3

+

15.90

19,80 25,10

28,00

Ba'+

4.80

6,30

10,70 10,80

Sr'+

5.00

6,90

8,70

9.80

QIo

P

I'CS

P

lbhp=

Total fluid rate Sm

3

/d)

Reservoir pressure

bar)

Flowing bot tom hole pressure bar)

Chelants are of relatively high molecular weight in compal'ison

to metal ions and therefore are required in high concentrations

for substantial scale dissolution, The aminocarboxylate chelants

are active over a broad pH range,

The activity toward a part icular metal ion varies with pH. A

chelant can then be formulated to be somewhat ion specific in

dissolution, These chelants are also stable to hydrolysis at high

temperatures: an essential property for surviving downhole con

ditions without degradation, The aminocarboxylates have low

toxicity to marine organisms but are not readily biodegradeable,

Formulated products are not aggresive to elastomeric material

and show low corrosion rates, relative to acid, on metals used in

well completion. 4

Use of brines containing alkaline earth metal ions as solvents,

pre-tlush or overt lush should be avoided where possible, as

these ions reduce the efficiency

of

the dissolver treatment.

For optimum performance, the design

of

a scale dissolver

job

should be conducted on a well by well basis,

An effective scale dissolver treatment requires correct applica

tion as well as an efficient product, Improper application

of

an

efficient product has been shown to produce poor results.

6 7

The treatment may be a simple bullheading of tluids downhole,

or require diverting agents

01'

coiled tubing. for accurate place

ment. A typical sequence is outlined below,

WELL HISTORIES

During a period of less than six months several gravel packed

wells experienced a sudden and sharp decline in productivity,

The problems appeared shortly after seawater breakthrough or in

connection with scale inhibitor squeeze treatments.

It was soon realized that the problems could be related to heavy

losses

of

calcium brine during completion operation,

During most complet ion operations, the bulk part ot the brine

volumes used are backproduced during the clean-up period.

Brine still remaining

in

the formation, so-called lost brine , is

expected to return over the next few days together with oil and

produced water.

For the problematic wells, heavy losses

of

high density calcium

brine (150-1000 m

3

)

were recorded, The volumes lost are sum

marized

in

t ab le 2. For these wells, several months to a year

76

Q

Ilit

and Pres are measured values,

P

lbhP

is calculated using a well hydraulic prediction programme,

Production data input comprises tlowing wellhead pressure, total

tluid rate and water cut.

Well A showed symptoms typical

of

formation dam,lge due to

calcium sulphate scale:

In July 93,10 months after completion, the PI dropped

from 750

to

520 m

d bar

and further

to

95 Sm

3

/d/bar

in October 93.

The first produced water sample obtained had a Ca'+

content (2100 mg l five times higher than expected

compared

to

the level found in more tban 20

neighbouring wells (350-450 mg/l),

Production logging in October

93

verified reduced

productivity together with high Gamma Ray (GR)

readings

In well B, formation damage occured after scale inhibitor

squeeze treatment following sea water breakthrough:

A sharp increase

in

the Ca'+ level was recorded during

a 48 hours backtlow period after inhibitor squeeze (500

mg l before, 4200 mg l after (see figure 1)

Only

6

return

of

inhibitor was found. This is

significantly lower compared to previous squeeze

treatments (25 30%)

Production logging performed before and after the

treatment verified reduced productivity

During a short period, three more gravel packed wells experi

enced productivity decline that have been linked to residuals

of

calcium brine in the neal' wellbore area,

In Well C, breakthrough

of

produced water with high sea water

content (98 %)

11

month after completion had a dramatic effect

on productivity:

During a few months produced water rate decreased

significantly and eventually ceased completely

The productivity (PI) alsoclecreased and this trend

continued after the water production ended,

Wel l 0 produced only I

water after, compared to 18 before,

gravel pack operation. Analyses

of

pr lduced water showed a

threefold increase in Ca'+ after gravel pack operation (from 1612

8/10/2019 SPE-30086-MS

3/12

SPE 30086 K. Lejon, J. Tuxen Thingvoll, E.A. Vollen, Statoil,

P.

Hammonds, Baker Performance Chemicals

3

to

4462 mg/I).

In

this

well

tangible evidence

of

calcium sulphate

precipitation

was

found:

Scale particles found

in

the sand trap and

in

downhole

bailer were identified as CaS0

4

21-lp gypsum).

Well E was eventually added

to

the list

of

problematic wells.

This well produced dry oil prior

to

the gravel pack operation. A

short time after, both the production rate and wellhead pressure

started

to

decline table 3)

For well

E,

the drop

in

production rate

was

related

to

possible

precipitation of CaS0

4

due

to

use of seawater during gravel pack

operation

Table 3. Well E - Production data after completion operation

Date

Choke P

WII

UiI

Water

mm

bar

SmJ/d

cut

14.11.93 17

138 958 0

17.11.93 24.8 109

1.564 0

02:12.93 24.2

81

449 0

17.12.93 24.2

80 348 0

01.01.94 53.9 80 210

0

For all wells, except well B, the potential for sulphate scale

formation

was

evident due

to

high concentrations

of

sulphate

(eg. high sea water content) and high calcium.

High GR-readings readings are normally scen

when

sulphate

scales

of

barium

and

strontium are formed.

In

well A,

the pres

ence of sulphate scale incorporating NORM was detected. Thus

the observed formation damage could

be

due to both natural

formed barium sulfate scale and calcium sulphate

from

lost

brine.

In

well B,

no

increase

in

radiation was detected after production

decline indicating precipitation

of

calcium and inhibitor.

SCALE DISSOLVERTREATMENTS

In

order

to

remove the formation damage

and

restore

the

produc

tivity, scale dissolver treatments were carried out

in well A, C,

D

and E.

Well

A,

C and D

The dissolver treatments were carefully designed and carried out

according

to

the following procedure:

A scale dissolver formulation incorporating EDTA was

chosen from laboratory studies.

Solutions were bullheaded except

in

one operation well

D,

1st treatment) where coiled tubing

was

employed.

A spear

of

sea water (*) containing demulsifier and

scale inhibitor was pumped ahead of the scale dissolver.

Sea water containing scale inhibitorwas used

as

the

displacement fluid.

The shut in period was set to

48

hours

t

achieve

optimum reaction temperature and enough time for

chemicals

to

react.

To obtain the highest possible dissolution rate, sea

water was pumped every 4 hours during the shut

in

77

period to make sure that fresh dissolver contacted the

CaS0

4

scale

in

the near wellbore area.

Based

on

ideal conditions, the dissolver front

was

calculated to be displaced 2 m out from the wellborc.

(*)

Seawater was replaced by 2 KCI

in

the sccond

treatment ofwell D

WellE

In

order to reveal the nature

and

composition ofthc problem, a

diagnostic treatment with a very limited amount of dissolver

chemicals

was

planned. The results from this treatment provided

the basis for the decision

on

whether

to

initiate another

and

larger dissolver treatment.

15

m

3

of chemicals were initially pumped

down to the

perfora

tion interval

and 1/3

of the tubing

was

filled with chemicals.

Agitation

and

addition of

fresh

chemicals

to the

gravel

pack

was

then

achieved

by

pumping small volumes every 4 hours during

the 48 hour shut-in period, giving a 0.6 m radial displacement of

the fluids into the formation.

POST EVALUATION

OF

BACK- PRODUCED AQUEOUS

PHASE

Well A

The backflow profile was established

by

offshore monitoring of

pH

and level

of

scale dissolver. See Figure 2.

Based

on

these analyses, the sampling period

was

established.

Onshore analyses

for

ion compositions

were

carried out

on

the

same samples using Inductively Coupled Plasma Spectrometry

lCP) and volumetric titrations Mettler Auto Titrator).

The amount of dissolved scale

was

estimated t1 om material bal

ance calculations based

on

the percentage

of

formation water

and seawater/dissolver solution

in

back produced water

In

principle,

all

ions or species that do not take part

in

any physi

calor

chemical reaction during the dissolver process

can be used

as

indicators for the formation water content.

As no

such species

exist, a comprimise

was

chosen.

The concentration of magnesium ions (Mg

2

was selected as the

best indicator because sea water dissolver solvent) is

high

and

formation water low

in

magnesium. More importantly, there are

few

slightly soluble magnesium compounds,

and the one which

may be

present downhole MgC0

3

) is

relatively unaffected

by

EDTA

at

pH

8/10/2019 SPE-30086-MS

4/12

4 Forma tion Da ma ge due to Losses of C a- ba se d B r in e a nd H o w

Wa s

Revealed

Through

Post Evaluation of Scale Dissolver

an d

Scale Inhibitor Squeeze

Treatments

SPE 30086

Th e concentration of excess calcium ions throughout the back

flow period

is

not balanced by chloride or sulphate ions. The

surplus of Ca'+ ions is reported as calcium carbonatelcalcium

chloride CaCO/CaCI,).

(Bicarbonate was not included

In

the ion analyses.)

Th e

rationale for doing this is as follows:

Th e dissolver has probably dissolved some

CaC0

3

, bu t to as

cribe the whole surplus of Ca'+

to

dissolved

CaC0

3

is not realis

t ic based on solubility considerations.

Large concentrations of bicarbonate and carbonate wil l form

downhole due to the injection of the alkaline dissolver solution:

Th e

calculations are based on excess ions in backproduced water

phase and rate/volume of produced water.

In retrospect, it was realized that fewer samples than optimum

were taken during the.backflow and variations in the ion pattern

may not have been properly detected. An underestimate

of

the

amount of material mobilised and removed is therefore likely.

WellC

Fol lowing the disso lver t reatment a total number

of

34 water

samples were taken during a per iod of 200 hours. Analyses of

pH and scale dissolver

)

were carried out offshore. Ion analy

ses were determined onshore.

is not known

if

CaCI, exists in solution (aq) or as solid salt (s)

CaCI, (s,aq) + 2Na\aq) = 2NaCI (s) +

Ca \aq)

High concentrations of CO/ subsequently suppress the rate

of

dissolution

ofCaC0

3.

CaS0

4

is re turned at a constant level from 14 to 40 hours. The

presence of CaCO/CaCI, is again observed when the concentra

tion of chloride starts to climb (35-60 hours). This creates a fa

vorable condition for NaCI precipitation as suggested for well

A

Therefore the amount of CaC03 should be less than reported

830 kg).

Using the same arguments as for well A, the quantit ies of solids

mobilised and removed during the backflow period were deter

mined. Th e results are plotted in figure 5

The backflow profile in well C is different from well

A

The ma

jo r

part of the mobilised material is returned between 30 and 80

hours suggesting that the brine was lost further out in the forma

tion. Also, a larger amount

of

brine was removed in well C com

pared to well A

CO

2

(aq)

HC 0

3

'

C O / + 2 H P

CO, (oil)

CO, (aq) + OH'

HC 0

3

+ O H

is conceiveable that precipitation of sodium chloride will oc

cur when concentra ted ca lc ium br ine is mixed with alka line

EDTA solution containing sodium ions. This happens because

sodium chloride is much less soluble than calcium chloride

The reaction explains why dissolved quantit ies are reported as

CaCO/CaCI

2

Th e total quantit ies removed during the dissolver operation are

summarized in table 6

Dissolved material during the backflow period is shown in fig. 4

Th e

plo t shows a major peak equivalen t to 7000 mg/I (7 kg/m

3

)

of CaCI

2

which

is

observed be tween 1.5 and 2.5 hour s a fte r

opening the well. Later on, the level stays constant. Th e conen

tration of CaS0

4

in the return fluid is relativelyconstant over the

14

hour backf low period. This may indicate that the sulphate

scale i s evenly distributed from the gravel pack into the near

wellbore area.

WellD

Th e quantities of solids mobilised during the 10 hours backflow

per iod was de te rmined as decribed above for A and C, and the

results are plotted in figure 6.

Th e

plot shows elevated amounts

of

CaCI one peak appearing

a t 1-2 hour s and another broader peak at 4 -10 hours. A minor

amount o f C aS 0

4

is observed after 1 hour, but the bulk is pro

duced back after 4-10 hours.

A small amount o f B a S 0

4

is

mobilised after 2-3 hours. This sug

gests that the dissolved BaS0

4

was located in the gravelpack. At

that time both pH and dissolver return are at their highest level.

A large amount (peak) of CaCO/CaCI, is observed between 2.5

and 5.5 hours. This happens when the concentration

of

scale dis

solver in the return (and

Na

ions) is at maximum (38 ). Also,

this period starts with maximum concentration of Ca'+ and CI'

ions. The concentration

of

calcium continues

at

a high level

while chloride drops sharply, suggesting that the solubility of so

dium chloride is exceeded and NaCI salt is precipitated.

The disso lver t reatment also mobi li sed a constan t amount

of

BaS0

4

throughout the initial backflow period indicating that the

conditions were favourable high pH, sufficient concentration of

EDTA) for dissolving this hard and difficult scale. This also sug

gests that a significant amount of

CaC0

3

is dissolved

Prior to the disso lver t reatment , the produced water of well D

contained enhanced levels of Ca'+ (6226 mg/l compared to 1612

mg/I in the formation water).

If

cor recti on is made for the en

hanced Ca'+ levels, both the broad peaks of mobilised CaCl, dis

appear while the amount of CaC0

3

diminishes

figure

7). The

amount ofCaS0

4

and BaS0

4

remains the same.

The estimated total amounts of material removed during the

14

hour backflow period were:

1700 kg CaCI,

300 kg CaS0

4

6 kg

BaS0

4

45 0 kg CaC0

3

/CaCI,)

This indicates that the lost brinc CaCI/CaBr,) is located further

out in the formation than the CaSO/BaS0

4

scale, and that the

dissolver solution has not penetrated the area of lost brine. This

observation may also suggest that when CaS0

4

is

formed, sul

phate ions from the passing sea water /injection water picks up

78

8/10/2019 SPE-30086-MS

5/12

SPE 30086

K.

Lejon, J. Tuxen Thingvoll, E.A. Yolien, Statoil, P. Hammonds, Baker Performance Chemicals

5

Ca

2

ions from the br ine and move into, or to the vicini ty

of

the

gravel pack where deposition occurs.

The

second dissolver treatment in well D with limited volume of

solvent (EDTA) also removed some CaS0

4

and CaC0

3

in

addtion to iron. The backproduced aqueous phase was deficient

in

chloride ions, indicating that precipitation

of

NaCI may have

occured.

The analyses and post evaluation of the second dissolver treat

ment was somewhat difficult due to lack

of

analytical results

from the backflow period. Low water cut and formation

of

stable

oil/water emulsions made

it

difficult to obtain enough water for

ion analysis.

WellE

The

quantities

of

solids mobilised during the 22 hours backflow

period are presented in

figure 8.

The plot shows that the return

of CaS0

4

is minor during the first

4 hours, but later the content increases and reaches a constan t

level from 5 to 22 hours after which sampling was terminated.

As observed for well A precipitation ofNaCI has occured con

current with an increase

in CaCO CaCI

2

The bulk part of the

material mobil ised is bel ieved to be CaCI

2

based on solubility

considerations.

PRODUCTION IMPROYEMENTS

Well

A

As described in the previous chapter a relatively large amount

of

CaS0

4

scale was removed from the gravel pack or near wellbore

area.

In table 4, well tests before and after the dissolver treatment are

listed. An immediate increase

in productivity was observed, the

oil rate increasing from 2871 Sm

3

/d to 3465 Sm

3

/d. However ,

this inc rease on ly lasted a few days. 10 days la te r t he well tes t

showed an oil rate

of

2743 Sm

3

/d. In the foll owing weeks the

productivity showed a further decrease. Due to the short term ef

fect on productivity no data acquisition programme was carried

out

in

this well.

Despite the short effect

of

the dissolver treatment, the net profit

from increased oil p roduct ion more than balanced the opera

tional cost, including chemicals.

Table

4: Well A -

Production

data

before and a ft er

dissolver

treatment

Date W P

Qoi

Water PI

bar Sm

3

/d

u

Sm

3

/d/bar

14.12.93be

77

2.871

26.5

92

fore

06.0

I

94aft

77 3.465

31.2

177

er

12.01.94aft

75

2.743

34 88

er

79

WellC

The well was put on product ion at a rate

of

approximately 1000

Sm

3

/d. This rate was chosen to min imize any process prob lems

due to high concentration of spent dissolver fluid and high pH.

The

production rate was increased

in

s tcps over a period of 24

hours.

Before the scale dissolver treatment, the well produced with an

oil rate of 2900 Sm

3

/d at a wel lhead pressure

of

76 bar. After

the t reatment the well was producing 5700 Sm

3

/d at maximum

choke setting and a wellhead pressure

of95

bar.

During the sampling period wellhead pressure decreased from

94 to 84 bar and water cut increased from 2 to 15 .

A well tes t performed a week after the treatment , showed a loss

in productivity (PI) from

210

to 80 Sm

3

/d/bar. The production

data are given in table

5.

Further well tes ts 2 and 3 weeks later also showed a decrease

in

productivity, but the well was sti ll producing at a considerably

higher PI and rate than before the treatment.

Table

5:

Well

C -

Production data before and after

dissolver

treatment

Date

W P

Qoi

Water

cu t

PI

bar

Sm

3

/d

Snl d bar

02.11.93 76 2.900 0 31

before

24.12.93

95 5.700 1 210

after

30.12.94 84

3.960

80

after

To gather more information on how the t reament affectcd the

productivity it was decided to perform a PLT/BU. The most in

teresting findings are given below:

A PLT prior to the dissolver treatment gave a

contribution

of30

of

total flow from the lower

1/3 of

the gravel packed interval. The PLT after the treatment

gave an increase

in

contribution to 46 , indicating a

stimulation effect across the lower part of the interval.

All water production was coming from the lower

1/3 of

the gravel packed interval

PI , at a total rate

of 3000 Sm

3

/d, increased from 33

Sm

3

/d/bar to 128 Sm

3

/d/bar

Pressure drop across the gravel pack decreased form

93.9 bar to 22.4 bar.

As can be seen from

figure

9, the well p roduced at a higher oil

rate dur ing January - April 94 compared with the well test pet

formed prior to the treatment.

The benefical effect

of

the dissolver trcatmcnt is also reflected

in

the economic results.

The

operational cost for the treatment was

estimated to 100.000. As a comparison, the extra oil produced

during this period was worth about 40 million.

8/10/2019 SPE-30086-MS

6/12

6

Formation Damage due to Losses of Ca based Brine and How Was Revealed

Through

Post Evaluation of Scale Dissolver and Scale

Inhibitor

Squeeze

Treatments

SPE 30086

WellD

The first dissolver treatment

in

Well D gave an increase in well

head pressure that enabled the production rate initially to be kept

at the target rate

of

1100 Sm

3

/d, but shortly after the operation

the wellhead pressure started declining

Three months after the treatment the wellhead pressure was back

at the same level as before. The positive scale dissolver result

experienced in well E next section), triggered another treatment

in

well D using the same procedure and dissolver volumes as in

well E After the 2nd treatment the wellhead pressure was stable

at a high level for several months, maintaining the production

rate at the target of 1100 Sm

3

/d.

The results are summarized

in

table

7

Our study indioates that diagnostio treatments with

small dissolver volumes is as effective and durable as

large volumes.

Monitoring programmes and post evaluation strategies

for soale dissolver treatments are essential.

For

gravelpaoked wells, the brine system has been

ohanged to sodium bromide NaBr)

if

high brine losses

are expected.

AKNOWLEDGEMENT

The authors wish to thank the management of Statoil for pennis

sion to publish this paper.

REFERENCES

WellE

Production data in table 3 clearly show that well E experienoed

a dramatic decrease in productivity prior to the dissolver treat

ment. There was a conoern that the well oould be oompletely

blooked, thus preventing the pumping of soale dissolver

solution.

The treatment enabled the well to be produced at an oil rate that

was above the initial rate following the gravelpack operation, in

dicating that the gravel paok operation had oaused formation

damage that now was removed.

The wellhead pressure deolined slightly during the next 2

months, but thenstabilized. For the next 8 months no further de

crease in produotion rate or wellhead pressure was observed.

Remarkably, the limited scale dissolver operation resulted in a

full restoration

of

well produotivity. Aooordingly, it was decided

to design the seoond operation in well D the same way.

The results are summarized

in

table7.

CONCLUSIONS

The major reason for the deoline in produotivity in gravel paoked

wells has been confirmed to be due to heavy losses

of

calcium

based brine during completion operation. Breakthrough of sea

water has led to precipitation

of

CaS0

4

Use

of

sea water as sol

vent for scale dissolvers and scale inhibitors has also added to

the deleterious effects.

The observations and findings have lead to fol lowing conclu

sions and recommendations:

Formation damage is related to the volume of brine lost

during completion operation.

Lost Ca-brine during gravel paoking has been found to

be present in the formation after many months

of

produotion.

Loss

of

oompletion fluids during gravel paoking should

be minimised and monitored properly.

Laboratory compatibility studies

of

treating chemicals

should be initiated if heavy losses

of

completion brine

has occurred.

Use of soale dissolver has been identified as an effective

and economical method for repairing formation damage

related to sulphate scale.

80

1

2.

3

4.

5

6

7

Schmidt, T., and S0reide, F., Mineral Soale in

Gravelpaoked Wells , Paper no. 56, Corrosion 94,

NACE

Martinko, B., Investigation of Chemical

Compatibility

of

Fonnation Waters with CaCl

2

and

CaBr

2

Brines , NAFTA 44,

p

265-269 1993)

Ali, S A., Javora, P. H Guenard, J H and Kitziger,

F. W., Test High-Density Brines For Formation

Water Interaotion , Petroleum Engineer International

July 1994)

Paul, J.M., and B.D. Fieler, A new solvent for

Oilfield Scales , 67th Annual Conference, SPE no.

24847.

Chelant Stability Constants, Akzo Chemioals Ltd.

Produot literature.

Fieler, E.D., Applioation and evaluation

of

soale

dissolver treatment , paper 58, Corrosion

94 NACE.

Hunton, A.G., Improvements in Scale Dissolver

Formulation , Oilfield Chemical Symposium, Geilo

1994)

8/10/2019 SPE-30086-MS

7/12

ATTACHMENT

1

Table 2:

Calcium

Based Brine

Injected

and

Lost

During Completion Operation

Type

*)

Specific Lost Perforation length

Gravity

m

3

)

Well

A CaCl

2

1.38 1000 57 m

WellB CaCl

2

1.36

500 7 m

WellC CaCl

1.33 400-450

35 m

WellD

CaBr

2

1.68 450 27 m

WellE

CaBr

2

1.63 150 26m+15 m

*)

The brines contain both CaCl

2

and CaBr

2

.

Low density brine is low

in

CaBr

2

.

Hig h d en sity b rine is rich in CaBr

2

Table 6: Compounds Removed Precipitated **)

During

Dissolver Treatments

CaCI

2

CaS0

4

CaCO/CaCI

2

BaS0

4

SrS0

4

NaCI

Well A 1700 kg 300 kg 450 kg

5 kg 0 0

WellB

- - -

- - -

WellC

6 20 0 k g

280 kg 830 kg

okg 0 0

Well

D, no 1 *) 5.5 kg/m

3

1.2 kg/m

3

4 k g/m

3

I kg/m

3

0 0

Well D no 2 *)

1.2 kg/m

3

1.5 kg/m

3

8 k g/m

3

0 0 -15 kg/m

3

)

Well E *) -

5 k g/m

3

17 kg/m

3

0 0 - 3 kg/m

3

)

*) Total amount dissolved not determined because volume produced water was not recorded

**)

Precipitation

of

sodium chloride

Table 7: O il Production Improvements and Duration of Dissolver Treatments kg)

Q Q

Maximum Duration

Other

immediate effects

before)

after)

improvement

4)

Comments)

Sm

3

/d)

Sm

3

/d)

Sm

3

/d)

Well A

2871

3465

594 10 days PI increase: 92

to

77 Sm

3

/d/bal

WellB

- -

- -

No dissolver treatment)

Welle

2900 5700 2800 70-120 days PI increase:

3

t0210 Sm

3

/d/bal

Well D I

518

986 468

8

months

P

WH

inc re as e: 82 to 132 bar

Well E 3)

210 1542

1332 >8 months

PwHincrease: 80-136 bar

P

WH

Wellhead pressure

1)

First dissolver treatment, large dissolver volume injected, coiled tubing

2) Second dissolver job, small dissolver volume injected, pump job, bullheading

3)

Small dissolver volume injected, pump job, bullheading

4) Period of increased oil production

*)

O il r ate ke pt a t a bo ut 1 100 S m

3

/d due to production limitation

8

8/10/2019 SPE-30086-MS

8/12

ATTACHMENT

Figure

WELL

B: CalciumConcentration in Produced

Water

500

1500 - - - - - - t - - - - - - - - l l ~

3000 +--------------- ----{

4500

..

= = = ; = = = ; ~ = = ; j ~ = = = ; ; = = = = ; ~ ~ ~ ~ = T I

Iseve,ol

month,l 8

hours pe lool

~ ~ I

4000 l ~ ~ ~ = ~ I H ~ = = = = = : J -

3500 -1--------------.---1 \------_---\l.ill )..1JJlllJ - =L.- tl

Q

5 +----== - - =T-=----H

+

ij 2000

+-- - - - - - - - - - - -7J

N N ~ ~ ~ ~ ~ ~

g

Semple number

Figure

Well A Return Curves for

Scale

Dissolver and

pH

2nd y-axis

7

10,5

10

9,5

8,5

7

9 10 11 12 13 14 15 16 17 18

Hours

OL,....-- '--'- '--..l-_L---'-_..l-_L---'-_..l-_L----'-_..l-_-'---==----- --l Ill -.......

. .-----

o

40

35

30

15

25

20

15

.

10

8

8/10/2019 SPE-30086-MS

9/12

140.00

120.00

1100.00

80 00

i

60.00

40 00

] 20.00

0.00

20.00

Figure 3

WELL A : EXCESS ION CONCENTRATIONS

me/l

/1

0

1\

-...

@;]

\

-.

.

-

r ....

........

/

.-

=:::::

~

~

~

7

I I a

Ba

8 4

C[

11 111 5

1

2 4 6

Figure 4

WELLA: Compounds Removed During Dissolver Treatment

12000

10000

i

E

6000

B

l:j

4000

0

2000

1.5 2 75 3.25 3 75

Hours

83

4.75 5 75

7 75 11.17

14 75

8/10/2019 SPE-30086-MS

10/12

igureS

WELL

Compouuds

dissolved duriug dissolver treatmeut

4 y

12000 ~ _ A ~ j

10000

ll

8000 ~ ~ ~ ~ _ _ i

I

6000

+ - - - - - ~ - - - = = ~ = = ~ - y

4000 ~ V

2000

Hours

Figure

Well D: Compouuds Removed

Duriug Dissolver Treatmeut

12 00

10 00

8 00

l

6

e

6 00

rJ

-l:

g

4 00

2 00

0 00

0 5 1 5 2 5 4 5

Hours

8/10/2019 SPE-30086-MS

11/12

Figul c 7

Wcll

D:

Compounds Removcd Dul ing Dissolvcl

re tmcnt

Correction Made

for Enhanced Levels

ofCa

in Produced

Waler Prior to Treatment

12 00

10 00

;;,

i

g

8 00

]

J

6 00 -

+l

4 00

=

2 0 0

0 00

0 5

1 5

2 5 4 5

Hours

Fignl e 8

Wcll E: Componnds Removcd Dnl ing Dissolvcl re tment

10

90 00

.

80 00

1

__l _

_ _ ~ - - - - 1 - - - d . - - - - ~ - L - - - l - - - - - - - - - - - - - - . L - - - - L - _ _ - I

70 00 t - - - - - I - - - - - j , - - - - t - - -+ - - - \ -7

I

60 00

50 00

IcaC03fCaC1

2

1

]

40 00

J

30 00

i l

20 00

+l

10 00

l

0 0 0

C

-10 00

-20 00

1 1

- 30 00 - -- -

___- - - - . J _ _ ___ _ __ __ _ ___

_ _

_ _

_ _ _ ___ _ _ _

..J

0 5

1 5

4 5

Hours

85

10

13

16 19

22

8/10/2019 SPE-30086-MS

12/12

Figure 9

Well

Production

rates

5

50

I

I

4

7 J ~ 1 2 d l l Y S

/

355

Dissol ver treatment

25

55

5

r

: 45

4

35

S

3

25

.0

2

8

5

o

5

ys