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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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