Lecture11a_Basic Gaslift Sec 1 - Principles

7/28/2019 Lecture11a_Basic Gaslift Sec 1 - Principles

1/35

Gas Lift

Lecture 11a- Gas Lift, Section 1 - Principles

Recommended Texts: Handout and

rt c a t et o s,

Kermit E. Brown, Volume 2a

PennWell Publishing Co, Tulsa, OK, 1980

Akim Kabir

Senior LecturerDepartment of Petroleum Engineering

Curtin University of Technology

Slide 1Section 1 - PrinciplesAug 2008


2/35

Gas Lift

y s rt c a t ee e

Well quit

Production declines with depletion of reservoirenergy

Water cut increases Maximize production from naturally flowing wells

Note that this is different from gas injection for pressure maintenance

Injection of gas or water into reservoir to maintain reservoirpressure

Improve recovery

Slide 2Section 1 - Principles


3/35

Gas Lift

Pi

Qi Reservoir Pressure

,

artificial lift

is required to

a er u

WC1restore or

increase

pro uct onProductionProduction

time t1



4/35

Gas Lift

Gas lifting

Continuous

Chamber lift

Plun er lift?

Plunger Lift

Rod um in

Electrical Submersible pumping

Progressive Cavity pumping



5/35

Gas Lift

Continuous

Intermittent

A Continuous

Gas Lift System

Low Pressure gas

FTHPProduced Fluids + Lift Gas

Separator

High Pressure Gas

CHP

as t ompressor

Liquid

Slide 5Section 1 - Principles Pwf


6/35

Gas Lift

Open Semi-closed Closed



7/35

Gas Lift

Gas

vaves

closed All valvesclosed

Bottom valveopen

Fluid from formationhas built up above

Bottom valve opens andslug is propelled toward

Bottom valve closeswhen slug reaches the


the bottom alve. the surface surface


8/35

Gas Lift

-Production

as

Only bottomvalve is o en All valves

closed

Fluid from

formation has

All valves

below the slu

Valves close

when slugbuilt up abovethe bottom

open as slugmoves toward surface

reaches thesurface



9/35

Gas Lift

The injected gas aerates the fluid column and reduces

the density of the fluid

e ens y o e co umn re uce , o om o e

pressure gets lower and less reservoir pressure is

re uired to ush the l i uid to surface.

In other words the hydrostatic back pressure to thereservoir is reduced and the reservoir pressure can

overcome this reduced pressure and initiates the well to

flow.



10/35

Gas Lift

GL 'ed Dua l Com p le t ion - An Examp le

MIN I.D.STATUSSHORT STRING

DEPTH

Loca t i on :Wel l : XX

Wel lhead : MCEVOY DUAL (REFURBISHED)

Standard Wel l Type : X3123 7" LINER

DEPTHLONG STRING

M IN I.D . S TA TU S

Compl et ion Date : 1 .1. 2004

Max. Deviat ion : 43 deg @ 7131 f t

A ll De p th s in FT. AH.B THF

BTHF = 44 FT BDF (T6)Tubing : 3 .1/2" x 9.2 # New VAM, L80

Tubing tails: 2.7/8" x 6.4 #, NSCT, 2.3/8" x 4.6 # NSCT

f t . f t .

in

3.1/2" XXO-NIPPLE

3 .1 /2 "KBUG

3.1/2 " KB UG

3.1/2 " KB UG

3.1/2 " KB UG

3.1/2" XXO-NIPPLE 399437

1066

1759

2355

2856

BKR-5

BKR-5

DK-13 .1 /2 " K BUG4459

3.1/2" FLOW COUPLING3.1/2" FLOW COUPLING

2.8132.813

2.875

3 .1 /2 " K BUG5857

2.9102.910

3 .1 /2 " K BUG

3.1 /2 " K BUG

945

1667

DK-1

B K R - 5

3 .1 /2 " K BUG

3.1 /2 " K BUG

2230

2763

DK-1

B K R - 5

3.1/2" K B UG 4366B K R - 5

2.875

3.1/2" KB UG 5764B K R - 5

3.1/2" KB UG 6549DKO-23 . 1/ 2" K B U G6674

BKR-5

BKR-5

BKR-5

DKO-2.

X67043.1/2" X-NIPPLE (CAMCO)2.750

6737 9.5/8" RDH PACK ER (40-47#)

67732.7/8" CMD SSDCLOSED

V67 01 3.1/2 " C MD -S SD

68092.7/8" XN-NOGO NIPPLECHAM FERED BTM (CAM CO)

NO PLUG

2.313

2.205

2.750

3 .1/2 " LOCKABL E COLLET 6737

67473.1/2" x 2.7/8 X-OVER2.441

2.900

2.900

TOP OF T IE BACK PKR 6913

NO PLUGCLOSE

CLOSED7977 3.1/2" CM D-SSD 2.750

8013 3.1/2" x 2.3/8" X-OVER 1.901

8275

8277

8074

8080

8095

8161

8162

36 - Q1.0 - 8180 - 9196, 8214 - 8216

36 - Q1.5 - 8244 - 8246, 8254 - 8258, 8264 - 8274

SBS (4 " NU8RD)

4" WWS TELL TALE

3.250

3.423

OTIS 7 " WD 4 .5 " x 4 .0 "

4 " GPE

4 .1/2 " BLA NK CASING

4.5" LT C x 4 " NU8RD XO

4" WWS

4.000

4.000

3.875

3.423

3.423

8267 2.3/8" TBG SEAL ASSY 1.901

9.5 /8" CSG SHOE 7212

8285

8291

OTIS 7 " WD 4 .5 " x 4 .0 "

SB E

4.000

3.250

+ 15 SEAL UNITS SIZE:3.25"

2 .3 /8 " LOC TB G SEALAS SY + 1 5 S EA L UN ITS

I : "

1.901

OTIS 7" WD 4.5" x 4.0"

4 " GPE



4" WWS

4.000

4.000

3.875

3.423

3.423

10489

10485

10509

10572

10573OPEN2.3/8" XD-SSD 1.875

10683

10653

SBS (4 " NU8RD)

4" WWS TELL TALE

SB E

I " " "

3.250

3.423

3.000

10676

10678

10685

36 - S8.3/8.4 - 10588 - 10672

I : .

2.3/8" XN-NOGO BXP

2.3/8" x 6 ' PERF. PUP

2.3/8" W/LINE RE-ENTRY

GUIDE + DROP-OFFBULLNOSE

10753

10756

10764

2.3/8" X-NIPPLE

PXN PLUG

10717X 1.875

I . .. 106 7

36 - S9.3 - 10757 - 10772

36 - S10.1 - 10793 - 10822

4" GPE



4" WWS

4.000

3.875

3.423

3.423

10693

10708

10741

10742

SBS (4 " NU8RD)

4" WWS TELL TALE

BULL NOSE ASSY

3.250

3.423

3.403

10824

10826

10833

1.791

1.901

1.901


10891LANDING COLLAR

7" CSG SHOE

Designed BY :

DATE : 09 /08 /01 (MARLINE)

CHECKED: 10 /05 /01 (ESMERALDA)


11/35


12/35

Gas Lift

INJECTION GAS

No gas injection; Well is Dead

PRESSURE (PSI)500 10000

Dummy

Fluid Level

500

CASING PRESSURE

Dummy 1000 TUBING PRESSURE

Valve 1

Valve 2

EPTH(

FTT

VD)

1500

2000

Valve 3

Orifice 2500

3000

Pr

Slide 12Section 1 - Principles SIBH

P

=


13/35

Gas Lift

FTHPProduced Fluids + Lift Gas

as ys em

Low Pressure gas

bubbling up

the well,

lightening the

fluid column in

Gaslift Compressor

High Pressure Gas

t e we

CHP

Separator

Liquid

Lift gas injectedat the deepest

mandrel


Pwf


14/35

Gas Lift

PRESSURE (PSI)500 10000

Well Flowing

INJECTION GAS Dummy

Fluid Level

500

CASING

Press

TUBING

Press.

Dummy 1000

Valve 1

Valve 2

1500

2000

Valve 3

Orifice 2500

3000

Slide 14Section 1 - PrinciplesPr

Pwf


15/35

Gas Lift

A Well Bein Gas Lifted

PRESSURE (PSI)

0

500 10000

Well Flowing

INJECTION GASDummy

Fluid Level

500

CASING

Press

TUBING

CASING PRESSURE

Dummy 1000

.

Valve 2

1500

2000

a ve

Orifice 2500

3000

3500

Slide 15Section 1 - PrinciplesPr

Pwf


16/35

Gas Lift

To enable the well that wil l not flow naturally

to produce o ncrease pro uc on ra es n na ura ow ng

wells

To remove or unload fluids from gas wells.



17/35


18/35

Gas Lift

us ave a source o gas

Imported gas from other fields may result in start up

problems Possible high installation cost

Top sides modif ications to existing platforms

Bottomhole pressure can not be reduced too much,since backpressure of two phase flow up the tubing has

.

Significant effort required to operate effectively

Can be too forgiving Quite inefficient (energy)



19/35


20/35

Gas Lift

-

Continuous f low is similar to natural flow and isachieved b controllin the in ection of as into thefluid column to cause aeration from the point ofinjection

Advantages: Takes full advantage of the gas energy available at the

surface

g er pro uc on vo ume

Equipment can be centralized Valves can either be wireline or tubing retrieved

Disadvantages:

Must have a continuous source of gas. a es o e a ove p or e c en ng. Bottom hole producing pressure increases both with

depths and volume



21/35

Gas Lift

- Intermittent flow is by injecting gas of suff icient volume and

surface, this usually require high gas rate to reduce the liquidfallback. The liquid to surface is in slug or piston form.

Advantages: Can obtain lower producing bottom hole pressure than

continuous flow and at low rates.

Suitable for well with production below 150 bpd (low P.I wells)

Can remedy wax deposition in tubing for waxy crude

Disadvantages: Limited in volume.

Causes surge on surface equipment. Equipment must be designed to handle the surge.

Cause interruption to other flowing wells in the productionsystem



22/35

Gas Lift

or ow ro uc on e s, n erm en ow gas s abetter Choice.

BFPD)

- -

2-7/8 TUBING - 200 TO 300 BFPD 3-1/2 TUBING - 300 TO 400 BFPD

3 Main Categories - Intermittent gas lift

- Chamber lift - Plunger lift ? (can be used without gaslift as well)



23/35

Gas Lift

Injecting gas into the well reduces weight of the fluid

column and conse uentl reducin the flowin bottom holeProduced Fluid + Lift Gas

pressure. (Optimal product ion)

1900

Optimal injection

point

1600

1500

Q1 =2000 b/d

Inj. Gas = 1mscf/d

w

Qliq500 2000 2200

Non Optimal lift ing

w = ps g

Q1 =2200 b/d

Inj. Gas = 2mscf/d

At high draw-down i.e. high gas in ject ion rate:

1) Non-darcy flow in IPR

2) Causes increase in the frict ional losses in the tubing


thus offsetting the reduction of weight in the fluid

column.


24/35

Gas Lift

A wells ability to produce fluid

a reduction in bottom hole pressure i.e.

theP(Reservoir Bottom Hole)



25/35

Gas Lift

Required Data

Static Bottom Hole Pressure

Pressure in the wellbore at the perforations under-

SBHP, Pr, Ps

Flowin Bottom Hole Pressure

Pressure in the wellbore at the perforations with thewell producing at a given rate

, ,

Drawdown

Change in pressure from static to flowing SBHP-FBHP = P

Fluid Rate


e test per orme w e runn ng survey =


26/35

Gas Lift

One way to quantify a wells productivity

is to use a relationship known as:

production rate and drawdown (rate and

ressure



27/35

Gas Lift

PI = BLPD / P

Drawdown

=

BLPD = P * PI



28/35

Gas Lift

ne way o p o e ro uc v y s n erms o ro uc v yIndex (PI)

The PI is a convenient term to compare performance between.

SBHP

BHP

PI is expressed in terms of rate versus drawdown (bpd / psi)Rate



29/35

Gas Lift

RELATIONSHIP

We have another curve to describe the inflow into the well

from the formation. This is theinflow curve

(inflow, .

P

B

Rate


G Lift


30/35

Gas Lift

RELATIONSHIP

The inflow curve can be derived using any two points. Normally

the SBHP is given as one point. e oge curve s one n ow re a ons p:

Q/Qmax = 1 - 0.2(FBHP/SBHP) - 0.8(FBHP/SBHP)2

where FBHP and Q are measured data (normally from a surveyand a concurrent welltest).

H

P

SBHP

B

Q

FBHPQmax


Rate

G Lift


31/35

Gas Lift

PI is a more simple way to handle inflow.

IPR is more complex, and more correct than, u requ res e er a a o correc ycalculate

P

B PI

Rate


Gas Lift


32/35

Gas Lift

we compare e n ow mo e an e ou ow mo eby drawing them on the same graph, we can find the

expected flow rate and FBHP.

BH

P

FBHP

Rate This technique is the basis for more complex predictions

such as the equil ibrium curve and the lift gas performancecurve.


Gas Lift


33/35

Gas Lift

Inflow: Pwf = Pres dPres dPperf

Outflow: Pwf = Psep + dPfl + dPtbg

TGLR3Inflow OutflowTGLR2

BHP

TGLR3 > TGLR2 > TGLR1

Rate


Gas Lift


34/35

Gas Lift

900)

n m e as or max mum

flowrate is desired

2) Limited Gas or the most

600

700

on(BPD econom ca ra e s es re

1) Production is fixed

Water /gas coning

300400

rodu

cti

Sand production

Governmentregulations

321

0

100Net

Gas lift Injection (Mscfd)


Gas Lift


35/35

Gas Lift

Qinj

production as we approach maximum point

700

800

900

BPD) Optimum Injection Point Qliq

400

500

600

uctio

n(

Sub-optimum in jecting points

100

200

300

N

etPro

0

50 100 200 300 400 500 600 700 800 900 1000

Gas lift In ection Mscfd


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Lecture11a_Basic Gaslift Sec 1 - Principles

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