1

Basics of Gas Well Deliquification

7th European Gas Well Deliquification Conference

Groningen, 24-26 September 2012

Kees Veeken, Shell – NAM (Assen)

2

Short Course Contents & Objectives

Origin of liquid loading

Recognise liquid loading

Model liquid loading

Importance of liquid loading

Gas well deliquification

Select deliquification

3

Origin of Liquid Loading

4

Critical Gas Velocity

Gas wells produce both gas and liquid (condensate and water)

Multi-phase gas well flow is characterized by different flow regimes

At high enough gas velocity the liquid is dragged up to surface in the form of liquid film and liquid droplets

When the gas velocity reduces below the so-called critical velocity the well liquids can no longer be produced in the form of film or droplets

Then liquids will accumulate in the wellbore and the liquid fraction increases significantly

5

Water of condensation due to temperature reduction

Fresh water, dictated by reservoir pressure and temperature

WGR ~5-100 m3/e6 m3 or 1-20 bbl/MMscf

Gas condensate (heavier hydrocarbon components) due to pressure and temperature reduction

CGR ~1-1000 m3/e6 m3 or 0.2-200 bbl/MMscf

Sources of Liquids

Formation water entering through the perfs

Typically saline (up to salt saturated causing salt scaling)

WGR ~10-1000 m3/e6 m3 or 2-200 bbl/MMscf

1

10

100

1000

1 10 100 1000

WG

R (m

3/e

6m

3)

Pressure (bara)

6

Flow Regimes

BUBBLE SLUG CHURN ANNULAR MIST

Decreasing Gas Velocity

Tubing +/- completely filled

with liquid

Free gas as small bubbles

Liquid contacts wall surface,

bubbles reduce density

Gas bubbles expand as they

rise into larger bubbles and

slugs

Liquid film around slugs may

fall down

Gas and liquid affect

pressure gradient

Gas phase is continuous

Some liquids as droplets in gas

Liquid affect pressure gradient

Gas phase is continuous

Pipe wall coated with liquid film

Pressure gradient determined

from gas flow

7

4 2 3 1 5

As reservoir pressure (Pres) declines due to depletion, well production (Q) decreases

When Q decreases below Qmin, liquid loading cycle starts and average production drops

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 rate

a.k.a. critical rate

a.k.a. liquid loading rate

8

Recognize Liquid Loading

9

Signs of Liquid Loading

Production shows accelerated decline

Short term – real time data e.g. PI

Long term – monthly data e.g. OFM

Signs of slugging (noise, movement, pressure/rate measurement)

Intermittent production

Reduction of LGR

Reduction of wellhead temperature

Production and wellhead pressure decline together

Slow or incomplete pressure buildup

10

TID-301

TID_301 Natgas TID_301 Natgas TID_301 Natgas

15-1-2002 7:32:40

9-1-02 10-1-02 11-1-02 12-1-02 13-1-02 14-1-02 15-1-02

TID3-FR-301

Nm3/dg

TID3-PR-301

Barg

TID3-TR-301

?C

50000

100000

150000

200000

250000

0

300000

6.67

13.33

20.00

26.67

33.33

0.00

40.00

11

22

33

44

55

0

66

183930

10.33

66

TID3-FR-301

Nm3/dg

TID3-PR-301

Barg

TID3-TR-301

?C

Example (1) - Onset

Qmin~160e3 m3/d

Well recovers before loading completely

FTHP=10 bara

11

Metastable Production

0

20000

40000

60000

80000

29-Dec 18-Jan 7-Feb 27-Feb 19-Mar 8-Apr

Ga

s R

ate

(m

3/d

)

0

10

20

30

40

TH

P,

BH

P (

ba

r)

Gas Rate THP BHP

Qmin=40,000 m3/d

Qmeta=12,000 m3/d

Gas bubbles through

liquid column (SPE 95282)

Pressure depth graph

3200

3400

3600

3800

4000

4200

50 60 70 80

Pressure [bara]

Well d

ep

th [

m]

Flowing gas gradient unloaded Flowing gas gradient loadedPore pressure

12

Example (2a) – Bubble Flow

Qmin~190e3 m3/d

Metastable production or

bubble flow: Qmeta~50e3 m3/d

13

Example (2b) – Bubble Flow (SPE 153073)

14 WELL A-570 (PW-16) FLOW WELL A-570 (PW-16) PRESS

CMS_PW-FI-0570

T/J DAY

CMS_PW-PI-0573

BARG

PW16

10/02/2011 07:00:54.035 29/08/2011 07:00:54.035199.96 days

1

2

3

4

5

6

7

8

9

0

10

0

100

44.26130

0.71555

Example (3) – Horizontal Well

Qmin~90e3 m3/d

Well kicked off using batch foam

15

Hydrostatic column after shut-in consists of gas column on top and liquid column on bottom

Liquid column depends on reservoir, well and production parameters, 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)

16

K15-FK Flowline WH-106

K15-FK THP WH-106

K15-FK THP TEMPERATURE 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 THP WH-106

K15-FK THP TEMPERATURE WH-106

K15FK1.FIC-01-6.PV

6Nm3/d

K15FK1.PI-02-6.PV

barg

K15FK1.TI-02-6.PV

°C

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

9.94

130.

0.50

Example (4) – Formation Water Breakthrough

Wet BU

Dry BU

17

WELL A-580 (PW-27) FLOW

WELL A-580 (PW-27) PRESS

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

WELL A-580 (PW-27) FLOW WELL A-580 (PW-27) PRESS

CMS_PW-FI-0580

T/J DAY

CMS_PW-PI-0583

BARG

PW27

09/09/2010 01:13:30 16/09/2010 01:33:237.01 days

1

2

3

4

5

6

7

8

9

0

10

0

200

113.07597

0.00000

Example (5) – Tight Gas with Natural Fractures

Wet BU Dry BU

18

GGT1-FR-31

69505

Nm3/d

KOL1-PR-1

18.119

BARG

KOL1-TRC-1

29.680

Gr C

KOL-100 Outlet KOL-100 Outlet KOL-100

15/01/2012 00:07:3211/01/2012 00:06:04 4.00 days

KOL-1

0

20000

40000

60000

80000

1.E+05

1.2E+05

1.5E+05

0

75

0

75

Example (6) – Large Liner Slugging

Liner

Slugging

Liner

Loading &

Unloading

19

Model Liquid Loading

20

Water of condensation sufficient to cause liquid loading

Liquid loading initiated by water also in high CGR gas wells

Minimum rate for condensate typically ½ minimum rate for water

Qmin – Turner

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"

E.g. 5” tubing & 20 bar FTHP Qmin=70,000 m3/d

Translates minimum gas velocity at wellhead into minimum gas rate

Independent of WGR

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

21

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

VLP IPR

Qmin – Wellbore Model, Bottomhole Pressure (e.g. Prosper)

Annular Churn Slug

22

Qmin means instability rather than liquid loading

Liquid loading can occur at gas rate higher than Qmin

Qmin – Tapered String (Liquid Loading = Misnomer)

200mx6”+2600mx4”+200mx8” Qmin = 91-104e3 m3/d

4”

QL

L =

50e3 m

3/d

6”

QL

L =

103e3 m

3/d

8”

QL

L =

223e3 m

3/d

2800mx4”+200mx8” Qmin = 63-99e3 m3/d

3000m 4” Qmin = 61-83e3 m3/d

23

Importance of Liquid Loading

24

Material Balance

OGIP=3000e6 m3

Pi/Z=200 bara

Pres/Z=117 bara

Pmin/Z=83 bara

Gp=505e6 m3 Rese

rvoi

r Pre

ssur

e

Gp

Material Balance Gp = OGIP.(Pi/Z– Pres/Z)/(Pi/Z) UR = OGIP.(Pi/Z– Pmin/Z)/(Pi/Z) RF = (Pi/Z– Pmin/Z)/(Pi/Z)

Tank model

Straight line material balance determines incremental production as reservoir pressure declines

Not representative for tight gas well

Better represented by two-tank or multi-tank model

D=15e6 m3/bara

25

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 le

ve

l)

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”

26

Impact of LL and GWD on Ultimate Recovery

Assumes

Vertical

Well

Tight Prolific

(Improve KH)

Deliq

uific

atio

n

A=10,000 A=1000 A=100 A=10

27

GWD Very Important for Tight Gas Reservoirs

Poor Tight Moderate Prolific

Reco

very

Facto

r 0

%

100%

Reservoir Quality

GWD Compression

HorWell

Stimulation

Primary

Depletion

28

Gas Well Deliquification

29

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, heater

Wellhead compressor

Continuous foam

30

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

31

Deliquification Techniques

Intermittent production

Compression

Stimulation or water shut-off

Velocity string

Continuous foam

Plunger lift

Gas lift Downhole pump

32

Intermittent Production

33

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

4 2 3 1 5

Natural Cycle

34

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

4 2 3 1 5

Managed Cycle – Intermittent Production (IP)

35

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

04/28/2007 11/14/2007 06/01/2008 12/18/2008 07/06/2009 01/22/2010 08/10/2010 02/26/2011

Flo

wra

te (E

3m3/

d)

Date

OJP #1 Production (LL then Cycled Effectively)

Avg Daily Production Avg Monthly Production

Continuous Flow

Cycling

IP – Field Example (1)

Qmin~12e3 m3/d

Metastable production

is sub-optimum !!!

36

COV33-FR-4-33-1

22425

NM3/D

COV33-PT-4-33-1

9.4571

BARG

PUT 33 PUT 33

09/10/2010 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 (2)

37

PD:RB11_31_FG

MCF/day

PD:RB11_31_PTUB

PSIG

PD:RB11_31_PCAS

PSIG

PD:RB11_31_PLN

psia

PD:RB11_31_QGY

MCF

PD:RB11_31_QOY

BBLS

PD:RB11_31_QWY

BBLS

RAINBOW 11-31

4/23/2009 9:23:08.986 AM 6/22/2009 9:23:08.986 AM60.00 days

10

100

1000

1

10000

11.94485

0.76392

262.74109

283.49551

739.39362

283.21579

477.45331

Start-up of Automated Intermitting

Increase in daily average

water and gas production

IP – Field Example (3)

38

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

Inflow Pfast

2 – FBHP2 = A.Q + F.Q2

Crossflow Pslow

2 – Pfast2 = R.Q

Vslow

FTHP

Outflow FBHP2 = B.FTHP2 + C.Q2

39

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

Pi = 350 bara OGIP = 500e6 m3

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

40

Uptime (SPE 153073)

Close to 100% uptime in first stage of liquid loading

41

Compression

42

Twin-Screw Pumps

File

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 Pwellhead = 10 bar (150 psig)

Liquid knock out

43

Velocity String

44

Gas Well Deliquification Modelling – Velocity String

Deliquification changes outflow a.k.a. lift curve

Lift curves for deliquification can be easily modelled in case of compression and velocity string

Lift curves for other cases are less straightforward e.g. foam and plunger

45

Velocity String Example (1)

NATGAS NATGAS NATGAS

TID3-FR-305

NM3/D

TID3-PR-305

BARG

TID3-TR-305

GR C

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

21.207

12.520

28120.

7” Casing 3-1/2” Tubing 2” CT

CT Installed

46

Velocity String Example (2)

0

200

400

600

800

1000

1200

11/1

/199

6

11/1

5/199

6

11/2

9/199

6

12/1

3/199

6

12/2

7/199

6

1/10

/199

7

1/24

/199

7

2/7/

1997

2/21

/199

7

3/7/

1997

3/21

/199

7

4/4/

1997

4/18

/199

7

5/2/

1997

5/16

/199

7

5/30

/199

7

6/13

/199

7

6/27

/199

7

7/11

/199

7

7/25

/199

7

8/8/

1997

8/22

/199

7

9/5/

1997

9/19

/199

7

10/3

/199

7

10/1

7/199

7

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

CT Installed

7” Casing 2-3/8” Tubing 1-1/4” CT

47

0

200

400

600

800

1000

1200

10

/1/1

99

9

10

/15

/19

99

10

/29

/19

99

11

/12

/19

99

11

/26

/19

99

12

/10

/19

99

12

/24

/19

99

1/7

/20

00

1/2

1/2

00

0

2/4

/20

00

2/1

8/2

00

0

3/3

/20

00

3/1

7/2

00

0

3/3

1/2

00

0

4/1

4/2

00

0

4/2

8/2

00

0

5/1

2/2

00

0

5/2

6/2

00

0

6/9

/20

00

6/2

3/2

00

0

7/7

/20

00

7/2

1/2

00

0

8/4

/20

00

8/1

8/2

00

0

9/1

/20

00

9/1

5/2

00

0

9/2

9/2

00

0

10

/13

/20

00

10

/27

/20

00

11

/10

/20

00

11

/24

/20

00

12

/8/2

00

0

12

/22

/20

00

MC

FD

-120

-100

-80

-60

-40

-20

0

MM

CF

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)

CT Installed

5-1/2” Casing 2-3/8” Tubing 1-1/4” CT

48

(Continuous) Foam

49 Dropping soap stick

Continuous Foam (CF) [TC 285143] Soaping

Introduce a surfactant at bottom of tubing to induce foaming

Soap sticks, backside, capillary string injection

Less effective with condensate

50 Installing cap string

Continuous Foam (CF) [TC 285143] Continuous Foam Lift

Continuous injection of surfactant (solution) via 1/4” capillary string or backside

Reduces minimum rate by ≥ 50%

Surfactant concentration 1,000-10,000 ppm, typical cost € 5/L

UIE onshore installation cost typically € 300,000 (offshore x5)

51

Continuous Foam Lift – Field Example Continuous Foam – Field Example (1)

52

0

200

400

600

800

1000

1200

1400

1600

1800

3/1/00

3/8/00

3/15

/00

3/22

/00

3/29

/00

4/5/00

4/12

/00

4/19

/00

4/26

/00

5/3/00

5/10

/00

5/17

/00

5/24

/00

5/31

/00

6/7/00

6/14

/00

6/21

/00

6/28

/00

7/5/00

7/12

/00

7/19

/00

7/26

/00

8/2/00

8/9/00

8/16

/00

8/23

/00

8/30

/00

9/6/00

9/13

/00

9/20

/00

9/27

/00

10/4/00

10/11/00

10/18/00

10/25/00

11/1/00

Gas R

ate

(M

CF

/D)

Continuous Foam Lift – Field Example Continuous Foam – Field Example (2)

3-1/2” Casing 1-1/4” CT

Foam CT

53

CF – Field Example Continuous Foam – UIE Solutions to Retain SSSV

Actuated Manual

FV=SSSV

SV

FWV

LMGV

UMGV=SSV

KW C

on

tro

l lin

e flu

id a

nd

Su

rfa

cta

nt

FV=SSSV

SV

FWV

LMGV

UMGV=SSV

KW

Co

ntr

ol lin

e flu

id

REN-LMGV

Surfactant

Onshore Offshore

54

Plunger

55

1. Plunger at surface, well open: gas is produced, liquid accumulates on top of standing valve

2. Well shut in: plunger drops to bottom

3. Plunger on bottom with liquid slug on top: casing pressure builds up

4. Well open: casing gas expansion plus reservoir gas push plunger plus liquid to surface

5. Plunger at surface, well open: gas is produced, liquid accumulates

1 2 3 4 5

Plunger Lift Plunger Lift

56

WYK4-FI-4-32-1

22682

NM3/D

WYK4-PI-4-32-1

7.1626

BARG

WYK4-TI-4-32-1

13.185

DEG.C

CALCULATED FLOW FLOWLINE TO WELLHEAD PRESSURE TEMPERATURE

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

Ope

n up

Pl

unge

r ris

es

Plun

ger

arriv

es

Flow period

Shut

in

Plun

ger

falls

Shut-in period

Target velocity up = 150-300 m/min 1200 m AHD in 6 min = 200 m/min

57

Plunger Lift Field Example

Installed Plunger

58

Field Examples

59

Plunger Design and Material Selection

Plunger design

Barstock plungers are commonly used due

to low cost and low maintenance.

Viper plungers are used for wax wells (spiral design)

In low production wells, padded plungers are used to provide better seal

Material Selection

Lubricator – rated for 5000 psi and cold temp spec

60

Plunger Materials

61

Gas Lift

62

Intermittent Gas Lift using Concentric Coiled Tubing

63

Downhole Pump

64

Pulse Pump or Balance Pump

Hydraulically actuated down-hole pump system in a pulsing manner

Simple DH reciprocating pump – no reversing mechanism required

Closed power-fluid system with only one string for single acting.

Simple surface equipment

For deep well with 4.5” casing, the pump have to run through the casing or 3.5” tubing

Pump capacity is lower rate ~ 20 BPD for deep well and small casing

65

Select Deliquification

66

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

67

Selection Impacted by Well Parameters

LGR (WGR and CGR)

Plunger lift has limited liquid capacity (slug size & cycle time)

Gas lift is designed to handle large liquid volumes

Solids

Downhole pump requires screen / filter to handle solids

Gas lift does not depend on solids

Completion geometry

Plunger deployment depth and effectiveness dictated by ID profile

Compression does not depend on completion geometry

Well geometry

Plunger cannot be deployed beyond 50-60 degrees deviation

Velocity string can be installed down long horizontals

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Selection Impacted by Operating Parameters

Installation cost

Downhole pump requires significant investment in well and surface equipment

Plunger lift is charaterised by low installation cost

Reliability

Downhole pump has limited reliability

Velocity string has excellent reliability

Operating cost

Plunger lift increases number of interventions and is often not compatible with offshore production operations

Velocity string does not require additional interventions

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Comparing GWD Measures

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Consider future deliquification when designing new well and surface facilities

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

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GWD Selection – Summary Make GWD Part of Initial Well & Facility Design

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