8/17/2019 SPE-21696-MS

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S

Society

of Petroleum Engineers

SPE 696

 rtificial Lift Methods for Marginal ields

K Kahali, R Rai, * and R.K. Mukerjie, * Oil & Natural Gas Commission

•SPE Members

Copyright 1991, Society of Petroleum Engineers, Inc.

This paper was prepared for presentation at the Production Operations Symposium held in Oklahoma City, Oklahoma, April

7 9 1991.

This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract s U b ~ i t t e d by the author(s). Contents of parer,

as resented have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The matenal, as p r e s e n e d ~ does no necessanly re ect

  nposition the Society of Petroleum Engineers, its officers, or members. Paperspresented at SPE meetings are subject to publication review by   d l ~ o n l Co mltteesof the SOCIety

of Petroleum Engineers. Permission to copy is restrictedto an abstractof notmorethan300 words.

l u s t r a t i o ~ s

may not be copied. The abstract should contain conspIcuous acknowledgment

of where and by whom the paper is presented. Write Publications Manager, SPE, P.O. Box 833836, R,chardson, TX 75083-3836 U.S.A. Telex, 730989 SPEDAL.

also doubtful

and

reservoir

limits

are to

be

established

by extended production tes ts · The

d r i v ~ mech?nism is no mally

depletion

with f?st

decllne ln

reserVOlr

pressure necessltatlng

pressure

maintenance/water

injection

in

th e

very f i rs t year in many

cases

lf feasible. The

self flow period

is

generally very small

necessitating

application

of art i f iclal l i f t

right from th e

begining

of the field

development.

Al l these

parameters

effect

th e

economlCS of marginal

field

development

needing cheaper production technologies.

The

convent ional f ixed

platform has

not been

favoured

fo r

development of such

field since

i t

has

many

demerits

:

-

The

time between the

decision

to

develop the field and f i rs t oil

production

is

typically four

to

six

years.   involves

major

capital

outlays

fo r an extended

period

before

any cash flow

is

generated.

This

t ime becomes very

important

when

the results of production tests

effect

the

futur e geo logi ca l

models

and drilling of

other

dependant

wells.

I t has

therefore

been the endeavour of

a

cQIlll:>any

to put the

wells

on

extendea production through early

production systems.

Fixed rigid

platform is

extremely

capital intensive Oecause of the massive

size

of

structures. Decreasing the

top

side

loads for smaller

fields does

no t

result

in

p ~ o p o r t i o n l

decrease

in

the

size of

th e platform

and hence cost. This

is

Oecause upto

8 of the

mass

of th e structure

is

acting to

resist

th e environmental

forces

-waves,

current

and wind.

The capital

cost

is

a major

dictating

factor for

  v l ~ n t

of marginal fields.

Fixed

platform

is s ite specific.

When a field

is depleted

a

fixed

structure

becomes a major

l iabil i ty for

marginal   f ie ld whicfl may only produce

  BSTR CT

Production from offshore

fields

has been

dominating in the

past

and will continue

to

dominate

ln th e future.

I t

is e ~ e t e d that

more

than 5 of the production

win come

from

the deeper waters. Most

of

th e

new

discoveries

in

th e Indian offshore have been

marginal

in nature

i

. where economics

dictate selection

and app

ication

of production

systems.

As

a part

of the

develoIXOOnt,

many

wells

are

being cQIIIPleted subsea. Due to

th e

marginal nature of

th e fields

the

self flow

from

these wel ls

has been minimal ,

necessitating

application

of art i f icial

l i f t

at

th e earliest

ana

in

many

cases

right

from

th e

begining.

In

th e

p re sent study

an

attempt

has Oeen

made

to

evaluate

the suitability

of th e

available

l i f t

systems with

special reference to i ts

application

in

marginal

fields

of

Indian

Orrshore.

Also some case histories of

app li cat ions o f

different art i f icial l i f t modes

have been reviewed which provide important

parameters to evaluate their suitability

and

th e

field

proven technology.

References and illustrations

at

end of paper.

INTIDOUC1 ION :

The marginal fields

are

normally

smaller

fields. The

most simple definition

has

been

given as

 one that

is

on

the borderl ine

between

economic to develop and

not

being economic to

develp . The

word  marginal has

certainly acqUired

th e

COnnotatlon

of

 non

conventional implying that the conventional

technolqgy for developing

offshore

fields may

not

be

feasible

and cheaper hardware

designs

ana

systems need to be aaopted. Marginal fields

have many

technical

limitations. Normally

the

geological and recoverable

reserves

ar e lower.

Some of the marginal and small fields

of

our

country are as shown in table 1. The

permeability

and thickness

is

also lower making

wells

of pqorproductivity. There

are

many

instances of marg

inal

fields

where not only

productivity is

a problem bu t recovery

factor

is

---------_._----

597

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 RTIFI I L LIFT METHOD

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M RGIN L

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SPE 2

fo r a few

years. All these necessitate

completing wells subsea

rather than

platform

completion.

The

depression in th e

crude market

during

1986 onwards has pushed

many

small and

isolated pools

below commercial

threshhold.

trowever, with

th e

Gulf

crisis

since

August 1990

1

this

scenario is

changing. As a

result

of thIS, th e

concept of early production

system was evolved. Todate IlOSt

early

production systems ar e

floaters,

semi-

submersibles and jack-up

production

platforms

with wells completed subsea. Subsea completion

ha s become a feature of marginal

field

development schemes and

i t is

p art ic ul arl y t ru e

of

th e

North Sea, offshore Brazil and in

some

Indian

offshore.

The

r ea sons inc lude th e

relatively low

cost

and its retrievability

which

allows

economical

production

from

marginal fields.

ARrIFICIAL

LIFT

Selection of

one

s ~ i f i a r t i f i c i a l l i f t IlOde

fo r marginal offshore field is one

of

th e

IlOSt oomplex tasks. There are

four

t ~ s of

l i f ts

coffiIlOnly

considered fo r

any

field,

ie . Rod Pumping, Electric Submersible

  ~ s

 ESP), Hydraulic

turbine

and

j e t

pumps

and Gas L ift.

Rod

Pumping

Rod

PUIllRing is

normally no t

considered

fo r offshore

applications

mainly because,

i t r eq ui re s l ar ge s ur fa ce structure

- with

high

dead weight which is one of th e IlOSt

limiting

factors fo r

offshore.

  nstallat ion·

of

subsurface safety valve is no t P9ssible.

  t

is

a low volume

moae

making unsuitable fo r IlOSt

offshore

wells.   o w v r ~ in

some

cases i t is

considered for depletea field production.

Problems in

obtaining

reliable and regular

measurement

of

bottom

hole pressures,

eliminating cheaper wire line technics,

problem in handl Ing wax, sand, corrosive

fluids

and o i l s

w it h h ig h

GOR and unsuitability

in higher

inclination

and h ig he r w el l depth

all t o ge th e r e l im i na t e this IlOde of 11ft

fo r

application

in offshore and

s ~ i l l y

fo r

subsea completions.

However,

hydraulic

rod pumping

unit

ha s been installed

in

offshore platform completed

wells

because of

i ts smaller size and

su itab ili ty in lif ting

low

,production rates

and low

s uc ti on p re ss ur e

requuement.

The f irs t case history

has been reported by

Pickford [1] fo r

application

of hydraulic rOd

pump in OUter COntinental Self

by

Philips

Pet roleum Co. located

4. 8 km. offshore

Southern

Santa

Barbara County in about 50 m.

water

depth. The

o il

of 26

degree

API was

produced from w el l d ep th s ranging from 823 to

1615 m. with peak production rate of 5087.4

m3/D

 32000 bbl/D). Earlier gas l i f t was

Installed

which

was sub sequ en tl y r epl aced

by

hydraulic

rod

pump

when total

production

dropped

down

to 222.5 m3/D  1400 bbl/D). The

compact and

l i ght

weight hydraulic

unit

was considered optimum mOde for these low

rate

wells and f i rs t unit

was

installed

in

December 1984

as

a

p ilo t

and

subseqtlently

3 IlOre

units

were installed

in

1986. During

21

months of t r ia l production downhole pump

was

pulled

once and

there was

problem of

gas locking. The average production rate was

3.97 to 6.83

m3/D

 25 to

43 bbl/D).

The

wells

had maximum deviatIon of

41

degree

and dogleg

of 7 degree per

30

m. lOO

feet).

  t

was

concluded that

th e pumps

performed

sa t i sfa c t ori l y. The wells were

platform

completed. No case history

ha s

been

reported so fa r fo r

application

in subsea

completed

wells.

Also no

case history is

avaIlable fo r

application

of

progressive

cavity

rod pump  screw pump). But due to t he r ec en t

success

In onshore fields fo r low rate

 9

applications  lower than 150 m3 D), this

type

of

11ft is likely to

qualify

fo r applicati9n

in

depleted

platform

completed wells In

o ffsh ore a re as due to i ts compactness, low

weight and low

X-mas

tree

load.

Electric Submersible Pumps (ESP)

ESP suits th e best fo r

high

liquid production

rate

h ig h w at er

cut,

low

gas

liquid

ratio

and

shaliow depth.

But

i t ha s severe

limitations

fo r application

in offshore and

fo r

subsea

wells -because

of i ts

low

mean

time between

repairs MTBR),

high

repair cost  as i t

requires work-over rig deployment and

complete replacement) and

large

starting

current. The

performance

of ESP is also

influenced by gas, sand, wax,

corrosive

fluids

i

hi gh t emp er at ur e

etc.   t requires

s ~ i

~ l e t i o n and

christmas

tree fo r

subsea wells

as shown

in

figure 1. The

major problems have been with

cable

join

faIlures

1

at

christmas tree and   ~ IlOtor, and

pump

f?11ures due

to i ts

less

flex ib ili ty in

productIon r ate.

Dudley [2] provides information 9n

performance of

ESP

installed In

Montrose field North

sea, 209

Kilometre

east of Aberdeen,

Scotland

operated by

AI OOO  UK

•  Ibtal 15 producing wells completed

with

ESP/y-tool/TCP

a t

a

depth

of

about

2350

to

2650 meters

have been producing about 318

m3/D

 2000 bbl/D)

liquid

with water cut of

about 60 from a very low

pressure reservoir.

A

permanently installed work over rig handles

all

work-over Jobs

since ESP suffers

from

large

work

over job requirements.

Nolen [31

further

confirms that ESP

suffers

from nigh energy requirement and high

repair

costs

because

of : i ts

frequent break-down.

Lochtef4] mentions that

averaga MTBR is

normally one year for ESP which

further

reduces

in

case of subsea

wells. In another

case ESP has

been used with

floating d rill in g vessel for

testing of heavy o il (6 to 12 deg.

API)

from

o ffs hore ex plo rato ry

wells as

reported

by

Crossley [5] • Few IlOre cases have been

reported by

Visser[6].

These are

some

sporadic cases of platform completed wells with

no noteworthy case reported for subsea

application

so

far.

However,

th ere are large

number of

case

histories on

successfu

  ~ l i t i o n of ESP in

many

onshore

fields.

Hydraulic

Je t

Pump

The main

merits

of Hydraulic Je t

Pumps[7,8,9] have been good flexibility on

rates, use in deviated

wells,

retrieva bility if X-mas tree is designed fo r

th e

same) and deeper well depth

applications.

  t

has been used

in

5486 m (180UO

feet)

depth

in

SOuth Louisiana. The J e t pumps ar e better

as

compared to

positive

displacement

  ~

hydraulic

pumps or ESP for c as es

of

fluid prOducing sand,

corrosive fluids

and high GOR

wells.

  t

ha s

however,

very

low

MTBR

 about six IlOnths),

requiring

frequent replacement.   t requires a

high

pressure

power fluid.

The

power

fluid

may

be o il

or

water. Water is favoured in

offshore as

power

fluid

due to

safety

and

environmental

reasons.

But

corrosion

and

scale formation ar e problems with water and

oxygen

scavanger,

corrosion

and

scale

inhIbitors

need to be used. SOlid content of

power

fluid i s

very important

fo r

pump l i f e .

  t

is usually about 10

ppm

fo r o il of 30-40

degree

API

and

about

15 micron fo r water as

power fluid fo r normal_pumP l i fe The pressure

r ~ u i r e m e n t

of

~ e r fluid

is over 206.8 ba r

 3000

p si).

The

offshore

subsea well

completions w ill

r ~ u i r e dual or

tripple

p?rallel string depending upqn us e of Qpen or

closed

system. Normally

dual

  o ~ l e t i o n

is

adopted for offshore applications. The

power fluid rate is normally

1. 5

to

2 times

th e

produced

fluid rate. Therefore, th e

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KIS OR K H LI R M SHISH RAI R K MUKERJIE

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production rate is restricted due to

addition

of

 

fluid,

mainly because

th e

production

s tr ing s iz e

is r e s ~ r i c t e d

due

to

aual CO DPletion. However,. th e

production

string

has to

carry bom

th e

produced

and power fluids together r ~ i r i n g

i ts

handli '19 capacity from 2. 5 to 3

times

th e

productlOn

rates.

Further,   fluid

bandling

a t deck level i s also important.

In case of

subsea tree i t becomes l10re

cdllPlex when

access

i s

required

fo r

proouction,

annulus

and

pressurised

~ r

fluid

(figure 1). In rel1Dte sat tel i te

locations

the pressure loss in

th e

power

fluid

l ine

i s

to o great to provide an economic solution

for subsea application.

Hydraulic Turbine

Pump

Hydraulic turbine pump is

one of th e latest

developments. '1tlis bas main merits

of

having

higher MI'BR (about 2

years).

High pressure

power fluid

lS

used

to drive turDine

 

motors which is used to drive centrifugal

pump a t

down

hole to pump

produced

flUld.

I t

is considered more reliable, flexible

and

robust

form

of

downhole

purgp as

mentioned I;>y Manson [10] • The power fluid

may

be

well fluid

crude o i l

or

water. Power

fluid

may

be of fow pressure

high

flow rate or

high

pressure low rlow rate. The completions

are

generally

similar

to

hydraulic

je t

pump.

The

main l i m i t a ~ i o n s of th e

 

have been

i ts

low gas handling capacity (about 2 a t

intake pressure), the higber i nt ak e p re ssur e

requirement

(noramally

aoove bubble

win t

pressure)

and mininum produced fluid

haooling

rate

of

about 167 m3/day (1050 bbl/D). The

average

cost of th e

pump in

1990 i s

repqrted

to be

about

U8 205 thousancrfor 318 m3/d (2000

bbl/l;» production rate. This

excludes

conpletion

cost.

'1tle

other

arrangement

fo r

transporting QQWer

fluid

and handllng power

and produced rluids together

at

deck level is

similar to th at of th e je t pump. Over 25 to 30

wells

have

been

put on thlS ~ y p e

of l i f t mode

so far , bu t mostly

fo r water

production.

However, this ha s been applied in offshore

and

subsea

wells

so

far.

Gas

Lif t

Gas

Lif t

is

th e

most

common

type

of

l i f t

used

in th e

onshore

offshore and

subsea

wells. There is no t a big impact on

subsea

tree

design

fo r instal l ing

ga s

l i f t (figure 1). Gas

l i f t

fo r subsea

well in North sea has

been

standardised

J y adding another SCSSV

on short tubing

extension

on

annulus

passage

a t

tubing

hanger level.

The

gasl i f t

lS not favourable

in case of

l i f t ing

heavy o i l

due to high

solution

in the conditions

of low

formation

GLR ana where ga s is no t

available in th e f ield. Gas l i f t is

favourable

fo r

offshore locations mainly

because

of

i t s

rate

flexibil i ty, high MTBR

retr ievability,

need of conventional

weI

caTQ'2letion, no

problem

with sand abi l i ty

to

haoole

corrosive fluid,

sui tabi l i ty

at

high

tenperature, high

GLR,

water

cut

etc .

several

case histories are available fo r application

of

ga s

l i f t in offshore and subsea wells.

Gas

Lif t

was

installed

in th e

Argyll

f ield

[5 11]

UK

Block - 30/24 located 320

Kilometres (200 miles) offshore in

th e central

sector of North sea. The

design

was aimed a t

simultaneously l i f t ing from th e

five

subsea

wells

a t an

mjection

rate of

28317 m3/day (

1 million standard f t /0) pe r

well

and a aual

~ § i j ~ s o ~ 3 i ~ i d   f u n i r i l i o ~ y ~ f ~ a ~ a s ~ ~ i 1 D )

206.8 ba r (3000 ps ig was installed and

hooked up in Septemor 1985 on Deep

Sea

Pioneer

  l o t i ~ System.

Since then

adai tional wells

have been pu t on

ga s

l i f t and pEi rforming

satisfactorily.

Because of

high

injection

pressure and low sea

bed

tell'iprature,

care

bas

been

taken to prevent hydrate

599

formations.

Gas

l i f t

is

therefore,

a

major

contender

fo r

every

offshore/subsea

application.

EXPERIENCE IN INDIAN FIELDS

Gas

l i f t

ha s

been

selected

as prime

mode

of

ar t i f ic ia l l i f t fo r

major

Indian offshore

fields

in

th e

Arabian sea. Already about 30

wells are operating in Bombay High

and over

150

wells

will

become

9PErative

by

th e end

of

1991.

Gas

l i f t

has

been

selected

as

th e

prime mode fo r

most of t he o th er fields of

India. '1tle experience in

onshore

also

ha s

been

verY encouraging

fo r

this mode of

l i f t

which

is

selected

as th e dominant

mode

of l i f t in l10St

of

the f ields.

Electrical Submersible Pumps were installed in

three offshore platform completed wells

of

Indian o ff sh ore in the Arabian sea in Apil 1989

as

a pi lot R D project. The average colJPletion

cost was

about

US   150 thousand

per

well. The

pumps were supplied by Canco-Reda

Inc.

The

reservoir p re ssur es o f t he se wel ls were

about

89.6

bar

(1300 psi) and ~ t t o m hole

temperature

of

about

115°C.

(240

F).

The water

cut in

the two wells were about 3 and about

60

in

the

third well.

The problem started

during

th e testing

af ter th e installation,

due

to

failure of

electr ical feed through

connector (sea

board make).

After

replacement,

th e

wells

were

put

on

production.

But withm two months arter

putting

on

production, th e transformer

of

one

well

was

burnt

and electrical

f eed through connector

of

other wells went wrong.

Since

then th e

wells

have been closed. The

production

from

these

three

wells

with

ESP

has

been 82, 294

and

89

cubic

meter (514, 1849 and 561 bbll

of

o i l

respectively.

The experience

of

these

pi lot

applications

have

no t

been

enco1,1raging.

 

will re@ire rethinking fo r i t s

appllcation in any ot:her

Indian

offshore

fields unless

some technical

breakthrough is achieved fo r minimising

th e fai lures

and reduction

in

requirement

of

work

over

jobs due to

high

work over cost .

There is no

experience

for

hydraulic

turbine / j e t p ~ s either in onshore or

offshore ln

India.

No case h i s t o ~ y

is

available for i ts

application

in ofrshore

specially

in subsea wells.

In one

of

th e onshore fie lds in India, three

major

modes ie . ga s l i f t sucke r rod pumping and

electr ical

subnersible p1JllIps have been

put

on

several

wells. In order to

analyze

th e

performance, a detailed study was

carr

le d

out

by t he autno rs . For ESP.

46 well

samples

were prep?red. I t was observed that average

MI'BR lS abou t

8 months. For

39

of th e

cases

the MTBR is about

3.16

l O n t h s ~ fo r 37 cases,

th e

MTBR

is 7.65 months and ror 24 cases i t

is 16.8

months.

The maximum MTBR was as high

as

60 months fo r

one

well. About 44.8%

failures

were

due

to current cable leakage

at cable joints, 16 due to motor defect, 27

failures

due

to pump and bleeder valve

problems and in 12 rai lures th e

reason could

no t

be established. The

average

coefficient

of

exploitation (ie. the ratio of

~ r t i n g time to

actual

calendar t ime) was

0.72

WhlCh indicates that

about

26

of

th e

time,

th e

wells

were

idle.

Further,

i t

was

reflected that ESP motors/pl,UllPs were only

replaced

and

never repaired. I t

is

uneconomic to repair since there is no Indian

manufacturer fo r this system.

In case

of rod

pIlI 1ps, about 23 complete

well samples were

collected

where average MTBR

was l711Onths. In

10 cases

i t was 35 months,

30

cases,

MTBR

was

23.5

months, 18

cases ic

was 16 months, 12 cases i t was less than

9 l1Onths. The average

coefficient of

exploitation was

0.53 indlcating that about

4'n

of

th e time t he well was idle mainly

due

to   ~ r fai lures. About

25

of the cases

th e failure was rod snapping,

28

cases

due

to

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  R

M RGIN L FIELDS

SPE

 

pump

jamming/gas

locking

and

in

47 cases the

reasons were

not

recorded.

In th e

case of

gas l i f t th e

average

MTBR was over

60

months.

only

a few

records

were

available

to

indicate

wrong gas

l i f t valve

operation.

Many

wells

have

not failed

even

after i t s

ini t ial

installation

and

operation of five to

eight

years.

th e coefficient

of exploi ta tion

was

therefore nearly

100   .

SE LEX TION

OF

MODE

OF

LIFl'

FOR XD M RGIN L

OEESHORE HELD :

on the western and

eastern coast of India,

a number

of marginal structures

have been

discovered

 Table

1). Of

these,

XD oil bearing

structure

IS

located at

about

65

KIn from

Bombay

High. ' he water

dE pth is

about

90 m. The

early

prodUction system

consisting

of the

semi submersible based

floating

production facili ty (FPF) was

commissIoned

in

June 1989 with two subsea

wells,

well

no. 2 and 3 connected by subsea

f lexible l ines

to

th e FPF.

The well

no. 2

is

~ r f o r t e d in the

interval

of

2991-2988

m. am

completed with 2445

1778

nIn. (9

5/8 -7 )

l iner

and 889

mm. (3

1/2 ) tubing. The FPF is located

just above

this well. In

last

testing in

December 1989

the well

produced 192 m3/day (1209

BOPD)

with GOR of v V and no

water at

flowing

THP

of 240 psi

at

FPF. The ini t ial

reservoir

pressure

was 288.4

ba r

(4183

psi)

and

PI is 3.84

m3/D/Kg/cm2

(1. 7 bbl/D PSI) • However,

subsequentlY th e

well ceased after

pogucmg for about six mnths.

The other

well, well

no. 3

is

perforated at

2919-2914

m.

and nas

similar

CX?J Pletion. The

well

is

at

a

distance

of

3

Kilametres 1.875 miles)

from

th e FPF

and

is

connected

with

flexible

pipe.

During

the

ini t ial testing this

well

praouced

163 m3/day (1025 bbl/D)

with GOR of 64

vol/vol.

The flowing THP and bottom

hole

pressures

were 18.27

bar

(265

psi)

and 192.7

ba r

(2795

psi ) respect ively.

The Init ia l

reservoir

pressure

and

PI

were 291.8

ba r

(4233

psi}

and

1.62 m3/D/Kg/cm2 (0.718 bbl,lD/PSI)reSpE ctlvely.

The

well

ceased

to

flaw

subsequently

after

2

mnths of production

due

to

paraffin

deposition

in the flowline/tubing.

The

flowline

was

then flushed

out

and

th e

well was pu t

on production. The

l as t t es t

data

indicated

FTHP

of 12.13 bar (175

psi)

with a

rate of

125.9

m3/D

(792 bbl/D) and a GOR

of 41 V/v

and with no water

cut.

Another

well, well

no. 4 which

is

coll1pleted

subsea

at

a

distance

of

2.4

Kilometres 1.5 miles) from th e

FPF

has similar

history.

The

well

no. 2 and 3 were

analysed.

The

tubing

intake curves (TIC)

were prepared  figure

3&4).

  t

was concluded that both

the wel ls

were

at

the borderline

of

self

flow

ceasure

during

ini t ial testing.

This

is

evident

from

figure

3 & 4

that the intersection

of TIC

wi th Inf low performance

relationship

curve

(IPR) is in the unstabilized

flow

region of

TIC

and

decline in th e

reservoir

pressure will

result in no

intersection

between

th e

two

curves.

The faster

decline in

flowing

THP

and flow

rate

confirmed

that th e field

is

producing under

depletion drive

and

ceasure

of self

flow

in

a

short ~ r i o d is

expected. The well

behaviour

also indicated

marginal nature

of

the field

whose

ini t ial

estimated geo logi ca l re se rve

is

about 13,000

million

kg. Tne

analysis

of

inflow and outflow ~ r f o r m n e curve

further

indicated that

the wells

need

art i f icial

l i f t

right

at

this

stage

and

higher

stabilized flow

could

be

obtained

by

increasing

th e GLR, ie . by

in jec ti ng gas .

There was no

increase in the GOR since the

reservoir

pressure

was

above

the

bubble

point

pressure

which

is

about 82.39 bar (1195

psi).

The

general

field

parameters are given

in

th e

table

no.

2.

 

For

selection of

art i f icial

l i f t

i

was desired that art i f icial

l i f t

system

should have high

MTBR

since frequent work

over ri g d e p l o ~ n t is

very costly. Also

i

should be a field proven technolqgy

fo

subsea

application

with

minimum Irodiflcation

to the

normal subsea tree and

flowlines.

The

field is

expected

to

have

fast decline in

reservo ir p re ssure.

Also

th e l i f t

system shoul

be flexible

fo r handling variations in rates

reservoir

pressures

and

GOR. The wells

hav

shown low

prouction

rates,

possibily

o

paraffin wax

deposition.

Therefore, need o

Inhibitor injectIon also exists. Few

mre

wells are

being

drilled in this field

which

is

kept

in

view while

designing. Abov

factors

along

with

characterIstics o

the

l i f t

systems

outlined

earlier

therefore,

narrowed

down the choice

to

ga

l i f t since other

systems have

not

bee

tested fo r

subsea wells. The

injection

pressue

has been _preffered

at

about 137.

bar

(2000 PSI) fOr

better

operationa

flexibility

and

single point Injection

Oonsidering 5

wells

in

operation,

total cQIl ?ression

capability

of 15

thousand m3/day (5.29 mIllion standard

f t

/D

with discharge

pressure

of about 151.7

ba

(2200

psi)

is

being

considered for

ga

l i f t

in this field. The

compressor

is to

be

pu t

on

FPF

and 101.6 mm

(4 m.) flexible

gas

injection

line

is considered

adequat

fo r

gas

l i f t

operation

with

dual

X-mas

tree in

this

field.

xpy Structure

This structure

is located at

about 18

km in

the in the east

coast

of Ind ian Offshore

The field

is

being

developed with 4 legged

well production platform

and onshore based

proceSSIng

facili ty. FOur exploratory well

have been dril led. Well 1 produced o il

a

the

rate of 155

m3/D

(980 bbl/D) with

GOR of

13

viVo The

reserVOIr

pressure is 366 bar (5310

psi) at

3450

m. The other general

field

parameters

are

given in

th e

table 3.

Afte

reservoir

simulation

study i t was

found

that

th e

reservoir

pressure declined down to

172. bar (2500 psi}

within

one year

o

production

and

artifiCIal l i f t is requIred a

th e

end

of the f irs t year i tself. Afte

analysis of

a ll

available

Irodes

of l i f t

as

explained

earlier,

gas

l i f t

was

selected

for

implementation.

The

compressed

gas

from

land

based

 facility

will

be

transported

through

203

mm. (8 in.) pipeline to th e platform

and then

will

be

injec ted in to t he wel ls .

These

studie

however confirm

that

although

gas

l i f t

is

bette

suited at th e

Iroment

for these

margina

fields, the ill1proved and

cheaper

Irode

of l i f

has not

been

rorth

coming

to replace

gas

l i f

specially for

low potential

wells.

SUMMARY

AND

CONCLUSION

1.

Several

marginal fields have been

discovered in Indian

offshore.

The

need

fo r

art i f icial

l i f t in

subse

completed

wells of

XD which

is

presently

producing

with FPF

is

already

established. Further, for XPY

s t r u t u r e ~

th e

requirement comes

after

one

year

or

production.

2. AIrong the

available l i f t

Irodes,

case

histories are only

available

fo

application of gas l i f t in

th e

subsea completed

wells.

Also,

technically

and economically

i t

is suitable

and

flexible system

fo r

i ts

application

to XD

and XPY structures.

Thererore,

ga

l i f t

has

been planned

fo r

application

WIth

small

skid munted

compreSSIon

facili ty

to be

placed at

floating

processing

facili ty presently operating in the

XD

area.

In

XPY struccures, to

reduce cost

o

development,

land

based

processing

8/17/2019 SPE-21696-MS

5/9

SPE  2 696

KISHORE KAHALI RAMASHISH RAI R MUKERJIE

5

3.

faci l i ty

and injection ga s compression

faci l i ty is being

developed

with well

platform, in th e

fie ld.

Although, ga s l i f t at the moment is

finding

i t s

appllcaEion in Indian

marginal f ie lds ,

no other economic and

flex

iDle mode ha s

been

coming f or th s pe cia lly fo r low

potent ial sunsea wells.

ABBREVIATIOOS

ESP:

Electr ical submersible

pump

MTBR : Mean time between

repair

IPR:

Inflow ~ r f o r m a n c e

relationship

GLR: Gas l iquid ra t io

  water cut

R F R N S

1.

2.

3.

4.

5.

6.

7.

8.

9.

10 .

I i

Pickford, K.H.,  Hydraulic Rod-Pumping

Units in

Offshore

Artif ic ia l Lif t

Applications , SPE Product ion Engineering ,

 ay

1989.

Dudley,

R.W.

,

 Reperforation

of

North

Sea

Electr ic

Submersible-Pump

Wells

With

An ESP/Y- lbol/ KP Sys tem , SPE Production

Engineering, May 1989.

Nolen, K.B., Analysis of

Electrical-

S u ~ r s i 9 l e - P u m p i n g S y s t e m s ,

SPE Production

Engmeenng, May

1989.

Lochte,

Glen

E.,UNDP Consultant to

I

8/17/2019 SPE-21696-MS

6/9

 P

696

TABLE 1

I JI po rt an t M ar gi na l

Fields

o f

ONGC

Field Date o f Area

Estimated

Status o f

i

isoovery

  Sq . KIn

GeoJ.9gical o i l

Developnent

 II

  billlon kg)and

 

tas reserve

 

million m3)

 

7 wells h av e b ee n

d r i l l e d .

• • • • •1

XDl

1976

20

30.16 F e a si b i l i t y

 

study

being

carried

o u t

 

13.55

 

XD

NA

SMALL

4 ~ l o r t o r y wells h av e b ee n

put

on  

uction to EPS. Wells completed s u b - s e a ,

 

ater depth - 80

m.

 

Apr

O il

-

6.57

3

wells

h av e b ee n

dri l l e d.

i

 

XB78

84 6

 

Gas - 2000

th e f ield is to b e d ev el op ed  

11

May'85

O il - 2.32

 

XB74

13.6

11

 

Gas -

2539

' he f ield

is

to

b e d ev el op ed

 

11

 

1

XB34

Ju l 8 7

3. 6 O il - 1.71 To

be

developed

 

Nov'87

2.86

4 ex p lo r ato r y w el ls

have

been d r i l l e d

 

i

XB72

5

 

Water Depth : 50 m. .

 

XB79

Mar 87

3

2.6 1 ex p lo r ato r y w el l

dr illed

water Depth : 50

m.

XB8

Aug 87

3. 5 1.04

1

ex p lo r ato r y w el l

dr illed

 

small

canbined

1 ex p lo r ato r y w el l dr illed

 

XC

NA

 

11

XCA XCD

Water Depth : 35

m.

 

small O i l - 7 to 8

1

ex p lo r ato r y w el l

dr illed

 

XCD NA

 

cOmbined 1

Exploratory

wei1

dr illed

 

11

XSD1

NA

small

 

XSD1 XSD4

11

 

O il

- 3. 0

1 Exploratory well

dr illed

11

 

XSD

NA

small

 

XRI1A 1987

small 14.0

  e i ~   v ~ with

tripod

and land

 

ba s

g r o c e s s i ~

facil i ty

 

Water epth - 1 m.

11

 

XPY

1988

small

e i

d e v e l o ~ with

production

~ l a t f o r m

 

and an d b a se d g : :o c es s in

g

fac i l i y

 

small

Water depth - 8 100 m.

 

BR2

1980

12.0

Under

deve10pnent

11

 

BR3

1980

small

10.4

Under deve10pnent

11

11

 II

 

BR4 1980 small 3.2 Under developnent

 

602

8/17/2019 SPE-21696-MS

7/9

T LE 2

sane

Important Parameters

of

 

Structure

S 696

Oil API Gravity: .

Gas

Gravity :

Bottan Hole Tellperature

Pour

Point : .

Wax   w t:

39 API 0

0. 9

 

at

754 nun of

mercury

and 29.6 C

l5g C

12

C

9.0

T LE

3

General Fluid Parameters

Water

Depth :

Average Reservoir

Pressure

:

 after one

year

of

production

Well

Depth :

Crude API :

Average Productivity

Index

Gas Gravity air=l :

Pressure

maintenance

85

to

123 m. 28o-405 f t .

172.4 ba r  2500 psi

3450 m 11316

ft

48 degree

3.48 m3/day kg/cm2

0.8016

By water

injection

TUbing Head Pressure

 

i .

Sub

s ea wel ls

34.47 bar  500

psi

i i . Deck

level platform

: 24.13

ba r

 350

psi

of wells cx:mpleted at platform : 8

Subsea : 2

Maxm Liquid product ion Rate/well 318 m3/D 2000 bbl/D

TOtal Injection Gas Rate : 85016 m3/D 3 milliOn std ft3

Injection Gas

Pressure

: 68.94 ba r  1000 psi

Reservoir Tenp :

122

0

C

  5t

F )

Reserve

: 22 bil l ion

kg

6

8/17/2019 SPE-21696-MS

8/9

PRODUCTION

TREE

PRODUCTION TREE

WITH G S

LIFT

FIG.i.

PRO U TION TREE

WITH  OWNHOLE

HYDR ULIC PUMP

HVDRAUL 11-----J

PUMP

t

PRO U TIOft

PRODUCTION TREE

WITH ELECTRIC

SU MERSI LE

PUMP

I L T R I ~

 U

t

PRO U TION

SPE 21

TREE

SCHEM TICS

FOR

NORM L PRODUCTION RTIFICI L LIFT

8/17/2019 SPE-21696-MS

9/9

S 2 69

Pressure psl)

5

r-------------- -- ------

4

2

45

. GLA VIV

 

100

- - 150

- -

30 0

  IPA

W at er c ut 3 l > ; Tublng-3   2 In.; THP-240

pSi

O ~ . L . L l

o

5

5 2 25 ·S

35 4

LIquid Aate bbI/D)

Flgure-2

TIC

for Well 2. Field XD

Pressure PSI)Thousands

5

- - 150

  IPA

GLA VIV

 

100

- -

30 0

45

20 0

S I i t M ~ - - - . . . . . - - - - - - - - - - - - - - _ i

Water

cut-3 l>

;

TUblng-3 1/ 2

In. ;

THP-265

psi

O L . .L

o 6

6

2

26

36

LIquid Aate bbI/D)

F ig ur e S

TIC for W el l S .

Field

XD

6 5