1

Basics of Gas Well Deliquification

9th European Gas Well Deliquification Conference

Groningen, 22nd -24th September 2014

Anurag Mittal, Shell – NAM (Assen)

2

Short Course Contents & Objectives

� Origin of liquid loading

� Recognise liquid loading

� Model liquid loading

� Importance of Gas Well Deliquification

� Gas well Deliquification methods

� Gas well Deliquification selection

3

Origin of Liquid Loading

4

Flow Regimes

� Gas wells – Multiphase Flow (Gas

+ Condensate +Water)

1. High Gas Velocity - Liquid is

dragged up to surface in the form

of liquid film and liquid droplets

2. Mid Gas Velocity – Liquid

film/droplets start dropping out

increasing hydrostatic head

3. Low Gas Velocity - Liquids can no

longer be produced in the form of

film or droplets

Liquid Holdup and Hydrostatic Head

Gas Velocity

1

Cri

tical G

as v

elo

cit

y

Cri

tical G

as v

elo

cit

y

3 2

Bubble Slug Churn Annular Dispersed

Continuous Phase

Liquid Gas/Liquid Gas Gas Gas

Non-Continuous Phase

Free gas as bubbles

Liquid film around gas

slugs

Liquid filmstarts

dropping

Pipe wall coated with

liquid

Liquid dispersed as

droplets

Pressure Gradient

Liquid, Gas reduces ρ

Gas + Liquid Gas + Liquid Gas + Liquid Gas

5

� Formation Water

� Entering through Perfs

� Typically saline (up to salt saturated causing salt scaling)

� WGR ~10-1000 m3/e6 m3

� Water of Condensation

� Fresh water, dictated by reservoir pressure and temperature

� WGR ~5-100 m3/e6 m3

� Gas Condensate

� Heavier Hydrocarbons dropping due to pressure and temperature reduction

� CGR ~1-1000 m3/e6 m3

Sources of Liquids

1 m3/e6 m3 = 0.18 bbl/MMscf

6

421 5

� Decrease in well production (Q)

� Reservoir Depletion (Pres)

� Increase in WGR (Formation + Condensed)

� When Q decreases below Qmin (Liquid Loading Rate), liquid loading cycle starts and average production drops 3

Liquid Loading Cycle

Volume flow well 102

FTHP WELL 102FE

Temperature flow well 102

L13FE1.E_FI-01-102.U

kNm3/d

L13FE1.E_PI-29-102.U

barg

L13FE1.E_TI-01-102.U

degC

L13-FE-102

01/02/2009 15:27:08.142 01/06/2009 15:27:08.142120.00 days

100

200

300

400

500

600

700

800

900

0

1.E+03

0

200

0

100

61.0

25.6

194.

Qmin~200e3 m3/d

Qmin is minimum stable ratea.k.a. critical rate

a.k.a. liquid loading rate

7

Recognize Liquid Loading

8

Signs of Liquid Loading

� Production shows accelerated decline

� Short term – real time data e.g. PI

� Long term – monthly data e.g. OFM

� Production decrease while Bottom Hole pressure increases (Constant FTHP)

� Production and wellhead pressure decline together

� Slow or incomplete pressure buildup

� Reduction of LGR

� Reduction of wellhead temperature

� Slugging (noise, movement, pressure/rate measurement)

� Intermittent production

9

Example 1a – Onset of Liquid Loading

Qmin~160e3 m3/d

Well recovers before loading completely

FTHP=10 barg THP (Barg)

Gas Rate (e3 m3/d

Temparature (⁰C)

10

Example 1b – Onset of Liquid Loading

Stable FTHP

BHP ↑

Qgas ↓

THP (Barg)

Gas Rate (e3 m3/d

BHP (Barg)

11

� Just Before Shut-in – Mixture of Gas &

Liquid

� After Shut-in –

� Gas column on top and liquid column on

bottom

� Liquid column depends on reservoir, well

and production parameters

� Liquid column increases dramatically after

liquid loading

� Liquid column will drain into reservoir i.e.

will decrease and ultimately disappear

� Monitor liquid loading (and water

production) via PBU Liquid

Time

Intermittent Production (IP)Pressure Buildup (PBU)

P

THP

Gas

12

Example 2 – Formation Water Breakthrough

K15-FK Flowline WH-106

K15FK1.FIC-01-6.PV

6Nm3/d

K15FK1.PI-02-6.PV

barg

K15FK1.TI-02-6.PV

°C

K15-FK-106

10/01/2011 16:44:57.338 15/01/2011 16:44:57.3385.00 days

0.2

0.4

0.6

0.8

1

1.2

1.4

1.6

1.8

0

2

0

200

0

100

77.2

64.5

0.256

K15-FK Flowline WH-106

K15-FK-106

27/03/2011 16:44:57.338 01/04/2011 16:44:57.3385.00 days

0.2

0.4

0.6

0.8

1

1.2

1.4

1.6

1.8

0

2

0

200

0

100

Wet BU

Dry BU

THP (Barg)

Gas Rate (e3 m3/d

Temparature (⁰C)

13

Example 3 – Tight Gas with Natural Fractures

CMS_PW-FI-0580

T/J DAY

CMS_PW-PI-0583

BARG

PW27

21/12/2010 10:02:14 28/12/2010 16:32:057.27 days

1

2

3

4

5

6

7

8

9

0

10

0

200

116.59230

1.50272

16/09/2010 01:33:237.01 days

Wet BUDry BU

THP (Barg)

Gas Rate (e3 m3/d

14

Metastable Production

3200

3400

3600

3800

4000

4200

50 60 70 80

Pressure [bara]

We

ll d

ep

th [

m]

Flowing gas gradient unloaded Flowing gas gradient loadedPore pressure

Un-Loaded

Loaded

15

Example 5a – Bubble Flow

Qmin~190e3 m3/d

Qmeta~50e3 m3/d

THP (Barg)

Gas Rate (e3 m3/d

Temparature (⁰C)

16

Example 5b – Bubble Flow (SPE 153073)

17

Model Liquid Loading

18

Turner’s Criteria Qmin

� Heaviest Fluid decides Liquid

Loading (i.e Water)

� Independent of WGR

� Minimum gas velocity translated

into minimum gas rate at

wellhead

� Water of condensation sufficient

to cause liquid loading

0

50

100

150

200

250

300

0 20 40 60 80 100

FTHP (bar)

Qm

in (

e3 m

3/d

)

2 7/8" 3 1/2" 5" 7"

5” tubing & 20 bar FTHPQmin=70,000 m3/d

Qmin = TC.FTHP0.5.ID2/[(FTHT+273).Z]

Turner’s Equation

( )2

1

41

41

593.1

g

gl

tV

ρ

ρρσ −=

19

� Takes multi-phase flow

regime along entire

wellbore into account

� Bottom of lift curve is

accepted as most

representative minimum

stable rate – steady state

production left of bottom is

possible but unreliable

� Bottom ≠ Turner

� Especially at higher Qmin

(above 50e3 m3/d or 2

MMscf/d)Pres=50 bar, A=10, FTHP=10 bar, ID=4.291”

WGR=100, CGR=100WGR=0, CGR=100WGR=0, CGR=0

VLP IPR

Qmin – Wellbore Model, Bottomhole Pressure

AnnularChurnSlug

20

Importance of Liquid Loading

21

� Determine incremental reserves based on reduction of minimum

achievable reservoir pressure (Pmin)

0

50

100

150

200

250

300

350

0.0 0.5 1.0 1.5 2.0 2.5 3.0

Gas Produced (mrd m3)

P/Z

(b

ara

@ d

atu

m level)

K7-FB-101

K7-11

Material Balance

Qmin=0.15 mln m3/d(P/Z)ab=28 barUR=1.66 Bcm

(RF +2%)

Qmin=0.3 mln m3/d(P/Z)ab=34 barUR=1.62 Bcm

Material Balance – “Single Tank”

22

GWD Very Important for Tight Gas Reservoirs

PoorTight Moderate Prolific

Reco

very

Facto

r0%

100% Reservoir Quality

GWDCompression

HorWellStimulation

PrimaryDepletion

23

Gas Well Deliquification Methods

24

Gas Well Deliquification

� Increase gas rate above Qmin

� Compression, stimulation, gas

lift, intermittent production

� Reduce Qmin

� Compression, velocity string,

foam, plunger

� Remove liquid

� Downhole pump

Wellhead compressor

Continuous foam

25

Life-Cycle GWD Strategy

Early Life•Casing Flow•Tubing Flow•Intermittent

Production

Mid-Life•Compression•Velocity

String•Foamer•Plunger

Late Life•More

Compression•Gas Lift•Downhole

Pump

26

Deliquification Techniques

1. Intermittent production

2. Compression

3. Velocity string

4. Continuous foam

5. Plunger lift

6. Gas lift

7. Downhole pump

27

Intermittent Production

28

Size of the Prize

� (1) & (5) Stable production: both gas & liquids produced to surface

� (2) Liquid loading: liquids no longer produced to surface, gas production declines as liquid column builds

� (3) Meta-stable production: some gas produced to surface, liquids injected downhole

� (4) No production: no gas production, liquids injected downhole, pressure recovery

42 31 5

Natural Cycle

29

Size of the Prize

� (1) & (5) Stable production: both gas & liquids produced to surface

� (2) Liquid loading: liquids no longer produced to surface, gas production declines as liquid column builds

� (3) Meta-stable production: gas produced to surface, liquids injected downhole

� (4) No production: no gas production, liquids injected downhole, pressure recovery

42 31 5

Managed Cycle – Intermittent Production (IP)

3009/10/2010 00:00:0007/10/2010 00:00:00 2.00 days

COV33

0

10000

20000

30000

40000

50000

60000

70000

80000

90000

1.E+05

0

50

IP – Field Example 1

THP (Barg)

Gas Rate (e3 m3/d

42 31 5

15

1

2

4

5

43

2

31

� Reservoir pressure at onset of

liquid loading is unchanged

for fast tank

� Reservoir pressure at onset of

liquid loading is higher for

slow tank, difference

controlled by inflow and

crossflow parameters

� Slow tank gas volume left at

elevated pressure represents

gas volume available for

intermittent production

Two Tank Model

Vfast

FBHP

Pfast

Pslow

InflowPfast

2 – FBHP2 = A.Q + F.Q2

CrossflowPslow

2 – Pfast2 = R.Q

Vslow

FTHPOutflowFBHP2 = B.FTHP2 + C.Q2

Fast Tank

Slow Tank

32

Production Forecast (Vfast/Vslow=0.10, A/R=0.20)

Pi = 350 baraOGIP = 500e6 m3

Vfast/Vslow = 0.10A = 20 bar2/(e3m3/d)R = 100 bar2/(e3m3/d)

33

Uptime (SPE 153073)

Close to 100% uptime in first stage of liquid loading

34

Compression

35

Effect of Compression

� BHP (↓) = ∆Phyd (↓) + ∆Pfric (↑) + ∆Pacc + FTHP (↓)

� Increased gas rate above Qmin and reduced Qmin

Well close to Liquid Loading

Stable Production

36

Twin-Screw PumpsF

ile

Title

• Bornemann SLM Series

• Single-Well

• Bornemann

• Well-Cluster Pump

• Leistritz MPS Series

• Single-Well Pump

• 8-1,100 Mscf/day (227-

31,000 m3/day)*

• 16 bar (232 psi) Boost

• 8-90 kW (10-120 hp)

• Applications:� Penn West (Canada) - Red

Earth Field

� ExxonMobil (Germany) –

Lastrup Field

• up to 15,000 Mscf/day

(425,000 m3/day)*

• up to 50 bar (700 psi)

Boost

•Application:� Mobil (Canada)

• 160-2,400 Mscf/day

(4,500-68,000 m3/day)*

• 10-20 bar (150-300

psi) Boost

• 20-350 hp (15-260 kW)

• Applications:� Talisman Energy

(Canada)* At P* At P* At P* At Pwellheadwellheadwellheadwellhead = 10 bar (150 psig)= 10 bar (150 psig)= 10 bar (150 psig)= 10 bar (150 psig)

Liquid knock out

37

Velocity String

38

Effect of Velocity String

� Increase in Gas Velocity - Reduced Qmin

VS- Qmin Qmin

39

Velocity String Example 1

NATGAS NATGAS NATGAS

TID305

01/07/2000 00:00:00 01/11/2000 00:00:00123.00 days

10000

20000

30000

40000

0

50000

0

50

0

50

7” Casing 3-1/2” Tubing 2” VS

VS Installed THP (Barg)

Gas Rate (e3 m3/d

Temparature (⁰C)

40

Velocity String Example 2

0

200

400

600

800

1000

1200

11/1

/199

611

/15/1

996

11/2

9/199

612

/13/1

996

12/2

7/199

61/

10/1

997

1/24

/199

72/

7/199

72/

21/1

997

3/7/

1997

3/21

/199

74/

4/199

74/

18/1

997

5/2/

1997

5/16

/199

75/

30/1

997

6/13

/199

76/

27/1

997

7/11

/199

77/

25/1

997

8/8/

1997

8/22

/199

79/

5/199

79/

19/1

997

10/3

/199

710

/17/1

997

10/3

1/199

7

MCFD

Tubing PSI

Casing PSI

Line PSI

Projection

Total Cost: $20,121

Average rate for 90 days prior to installation: 246 mcfd Average for last 30 days: 327 mcfd

☺Paid out in 3 months

VS Installed

7” Casing 2-3/8” Tubing 1-1/4” VS

41

-120

-100

-80

-60

-40

-20

0

0

200

400

600

800

1000

1200

10

/1/1

999

10

/15/1

99

9

10

/29/1

99

9

11

/12/1

99

9

11

/26/1

99

9

12

/10/1

99

9

12

/24/1

99

9

1/7

/200

0

1/2

1/2

000

2/4

/200

0

2/1

8/2

000

3/3

/200

0

3/1

7/2

000

3/3

1/2

000

4/1

4/2

000

4/2

8/2

000

5/1

2/2

000

5/2

6/2

000

6/9

/200

0

6/2

3/2

000

7/7

/200

0

7/2

1/2

000

8/4

/200

0

8/1

8/2

000

9/1

/200

0

9/1

5/2

000

9/2

9/2

000

10

/13/2

00

0

10

/27/2

00

0

11

/10/2

00

0

11

/24/2

00

0

12

/8/2

000

12

/22/2

00

0

Cu

m W

ed

ge (M

Mscf)

Gas

Rate

(k

scf/

d)

MCFD Line PSI projection cumwedge

Gross Cost: $19905

�

Average rate for 90 days prior to installation: 911 mcfd Average rate for last 30 days: 539 mcfd

Velocity String Example 3

VS Installed

5-1/2” Casing 2-3/8” Tubing 1-1/4” VS

Huge reduction in well capacityTimming of VS installation is crucial

42

Foam-Continuous/Intermittent

43

Continuous Foam (CF) [TC 285⇓⇓⇓⇓143]Foam Injection

� Surfactant at bottom of tubing induces

foaming

� Foam stabilizes liquid film and delays

film reversal thus reducing Qmin

� Less effective with condensate (acts as

natural defoamer)

� Methods of injection

� Capillary string injection

� Batch Foam

� Soap sticksAutomated

44Installing cap string

Continuous Foam (CF) [TC 285⇓⇓⇓⇓143]Continuous Foam Lift

� Continuous injection of surfactant solution

via 1/4” capillary string

� Reduces Qmin by ≥ 30%

� Foam concentration 1,000-10,000 ppm

� Qgas independent of Foam concentration

0

50

100

150

200

0 10 20 30 40 50 60 70

Ga

s R

ate

(e

3 S

m3

/d)

Foam Injection Rate (L/d)

45

Continuous Foam Lift – Field ExampleContinuous Foam – Field Example 1

46

CF – Field ExampleContinuous Foam – Solutions to Retain SCSSV

Actuated Manual

FV=SCSSV

SV

FWV

LMGV

UMGV=SSV

KWC

ontr

ol l

ine flu

id a

nd S

urf

acta

nt

FV=SCSSV

SV

FWV

LMGV

UMGV=SSV

KW

Contr

ol l

ine flu

id

REN-LMGV

Surfactant

Onshore Offshore

47

Plunger

48

Plunger Lift

The various parts of a plunger lift are:

1. Bottomhole spring

2. Plunger

3. Arrival sensor

4. Lubricator/catcher

5. Pressure transducers

6. Motor valve(s)

7. Gas flow meter

8. Wellhead controller

1

2

34

5

8

67

49

Plunger Lift: Working

Plunger at surface, well open: Gas is produced, liquid accumulates on top of the standing valve

Well shut-in: Plunger drops to the bottom

Plunger on bottom with liquid slug on top: Casing pressure builds up

Well open: Casing gas expansion pushes plunger plus liquid to the surface.

Plunger at surface, well open: Gas is produced, liquid accumulates

1.

2.

3.

4.

5.

50

02/07/2012 01:54:4901/07/2012 19:54:57 6.00 hours

WYK-32

0

10000

20000

30000

40000

50000

60000

70000

80000

90000

1.E+05

0

20

0

50

Plunger Lift Example 1

Wel

l Ope

n up

Plun

ger

rise

sPl

unge

r ar

rive

s

Flow periodW

ell S

hut i

n

Plun

ger

falls

Shut-inperiod

Target velocity up = 150-300 m/min1200 m AHD in 6 min = 200 m/min

THP (Barg)

Gas Rate (e3 m3/d

Temparature (⁰C)

51

Gas Lift

52

Effect of Gas Lift in Gas Wells

� Supplies additional gas thus reducing the Qmin

LGR = 1585

sm3/Msm3

Optimum Gas Injection

Rates

Injected Gas Ratio

FB

HP

(in

Ba

ra)

Lift G

as R

atio L

imited to 1

PRes = 58 Bara

Paban = 53

Bara

Paban = 45

Bara

ΔPgain = 8 Bar

Na

tura

l

Flo

w

Ga

s L

ift

Reserv

oir D

eple

tion

53

Gas Lift Completions

Coiled tubing with internal mounted

gas lift valves.

Side Pocket Mandrel

Retrofit

54

Downhole Pump

55

Effect of Downhole Pump

56

Deliquification Selection

57

One Tool Does Not Solve All ProblemsOne Tool Does Not Solve All Problems

September 2013© Shell International Petroleum Co. Ltd. 58RESTRICTED

In the Deliq selection process, the feasibility is evaluated based on the following factors:

Deliq Selection Process

Reference: Lea, J.F. et al., “What’s New in Artificial Lift?”, World Oil, May 2013, 55-67

Dimension limitations

Wellbore configuration

Desired rate versus depth

Reservoir abandonment pressure

Temperature

Fluid make-up and properties

￭ Gas-to-liquid ratio

￭ Chemical properties

￭ Solids or sand

Infrastructure

Service or support

Reliability

Efficiency

Footprint

Environmental impact

Productivity

Connected volume

59

Deliq Selection Curves

10

100

1 10 100 1000

Pm

in(b

ara

)

A (bar2/e3Sm3/d)

NFA Compression VelString_2" Foam

Plunger VelString_2"+Plunger GasLift_Dry Pump

Tbg ID 4”FTHP 100 baraWGR 100 m3/e6sm3

TightProlific

60

Deliq Selection Table

Criteria MWHC VS CF GL DP PL

High LGR ���� ���� ���� ���� ? ����

LargeSeparator

Start-up Issues

Good at High WCR

No IssuesLimited by

pump capacity

High Freq

Solids ���� ���� ���� ���� ? ?Require

separationNo Issues No Issues No Issues

Large amounts

May cause jamming

Completion ���� ���� ���� ? ? ?

No Issues No Issues No IssuesMandrel or

RetrofitLarge Tbg

sizeMonoboreCompletion

61

Deliq Selection Table

Criteria MWHC VS CF GL DP PL

Deviation ���� ���� ���� ? ? ?

No IssuesCan be

installed in long Horiz.

No Issues<50-60⁰(Wireline)

<50-60⁰

Costs ���� ���� ���� ���� ? ����

High Mid MidLow

(CO avail.)High Low

Reliability ? ���� ? ���� ���� ?

ExcellentLK-2

failuresExcellent Limited

62

� Select tubing size that is robust against low productivity scenario

� Adopt monobore to avoid liner loading & to allow use of plunger

� Include actuated (flow wing) valve and wellhead P/T gauge upstream

of flowing wing valve for intermittent production

� Provide well profile to hang off velocity string

� Provide wellhead / Xmas tree access for continuous foam, gas lift

and/or pump hydraulics

� Provide flowline/manifold access for mobile compression

� Plan for power for compression

� Plan for gas lift flowlines for gas lift

� .....................

GWD Selection – SummaryMake GWD Part of Initial Well & Facility Design

63