Basics of Gas Well Deliquification

Basics of Gas Well Deliquification
9th European Gas Well Deliquification Conference
Groningen, 22nd -24th September 2014
Anurag Mittal, Shell – NAM (Assen)
1
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
2
Origin of Liquid Loading
3
Flow Regimes
Liquid Holdup and Hydrostatic Head
2
3
Gas wells – Multiphase Flow (Gas
+ Condensate +Water)
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
Critical Gas velocity
Critical Gas velocity
1. High Gas Velocity - Liquid is
dragged up to surface in the form
of liquid film and liquid droplets
1
Gas Velocity
Bubble
Slug
Churn
Annular
Dispersed
Continuous
Phase
Liquid
Gas/Liquid
Gas
Gas
Gas
NonContinuous
Phase
Free gas as
bubbles
Liquid film
around gas
slugs
Liquid film
starts
dropping
Pipe wall
coated with
liquid
Liquid
dispersed as
droplets
Pressure
Gradient
Liquid, Gas
reduces ρ
Gas + Liquid
Gas + Liquid
Gas + Liquid
Gas
4
Sources of Liquids
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
1 m3/e6 m3 = 0.18 bbl/MMscf
5
Liquid Loading Cycle
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
L13-FE-102
1.E+03 200 100
900
800
Qmin is minimum stable rate
a.k.a. critical rate
a.k.a. liquid loading rate
1
2
3
4
5
L13FE1.E_FI-01-102.U
194.
kNm3/d
L13FE1.E_PI-29-102.U
25.6
barg
L13FE1.E_TI-01-102.U
61.0
degC
700
600
500
400
300
Qmin~200e3 m3/d
200
100
0
0
0
01/02/2009 15:27:08.142
Volume flow well 102
FTHP WELL 102FE
Temperature flow well 102
120.00 days
01/06/2009 15:27:08.142
6
Recognize Liquid Loading
7
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
8
Example 1a – Onset of Liquid Loading
Well recovers before loading completely
Qmin~160e3 m3/d
FTHP=10 barg
THP (Barg)
Gas Rate (e3 m3/d
Temparature (⁰C)
9
Example 1b – Onset of Liquid Loading
BHP ↑
Qgas ↓
Stable FTHP
THP (Barg)
Gas Rate (e3 m3/d
BHP (Barg)
10
Intermittent
Pressure
Buildup
Production
(PBU) (IP)
Just Before Shut-in – Mixture of Gas &
Liquid
P
Liquid column depends on reservoir, well
and production parameters
Gas
Gas column on top and liquid column on
bottom
THP
After Shut-in –
Time
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
11
Example 2 – Formation Water Breakthrough
K15-FK-106
K15-FK-106
2
2
200 100
1.8
1.8
1.6
1.6
1.4
Dry BU
1.4
1.2
1.2
1
1
0.8
0.8
0.6
0.6
0.4
0.4
0.2
0.2
0
0
0
10/01/2011 16:44:57.338
5.00 days
K15-FK Flowline WH-106
200 100 K15FK1.FIC-01-6.PV
0.256
6Nm3/d
K15FK1.PI-02-6.PV
64.5
barg
K15FK1.TI-02-6.PV
77.2
°C
THP (Barg)
Gas Rate (e3 m3/d
Temparature (⁰C)
Wet BU
0
0
0
16:44:57.338
5.00 days
15/01/201127/03/2011
16:44:57.338
K15-FK Flowline WH-106
01/04/2011 16:44:57.338
12
Example 3 – Tight Gas with Natural Fractures
PW27
CMS_PW-FI-0580
1.50272
T/J DAY
CMS_PW-PI-0583
116.59230
BARG
10 200
9
8
THP (Barg)
Gas Rate (e3 m3/d
7
Dry BU
Wet BU
6
5
4
3
2
1
0 0
21/12/2010 10:02:14
7.27 days
28/12/2010 16:32:05
7.01 days
13
16/09/2010 01:33:23
Metastable Production
Pressure [bara]
50
60
70
80
Well depth [m]
3200
3400
Un-Loaded
3600
3800
4000
4200
Flowing gas gradient unloaded
Flowing gas gradient loaded
Pore pressure
Loaded
14
Example 5a – Bubble Flow
THP (Barg)
Gas Rate (e3 m3/d
Temparature (⁰C)
Qmin~190e3 m3/d
Qmeta~50e3 m3/d
15
Example 5b – Bubble Flow (SPE 153073)
16
Model Liquid Loading
17
Turner’s Criteria Qmin
Turner’s Equation
Heaviest Fluid decides Liquid
Loading (i.e Water)
Vt =
Independent of WGR
1.593σ
(ρ l − ρ g ) 14
ρg2
3 1/2"
5"
7"
300
5” tubing & 20 bar FTHP
Qmin=70,000 m3/d
250
Qmin (e3 m3/d)
Water of condensation sufficient
to cause liquid loading
4
1
2 7/8"
Minimum gas velocity translated
into minimum gas rate at
wellhead
1
200
Qmin = TC.FTHP0.5.ID2/[(FTHT+273).Z]
150
100
50
0
0
20
40
60
80
100
FTHP(bar)
18
Qmin – Wellbore Model, Bottomhole Pressure
Takes multi-phase flow
regime along entire
wellbore into account
Slug
Churn
Annular
VLP
IPR
Bottom of lift curve is
accepted as most
representative minimum
stable rate – steady state
production left of bottom is
possible but unreliable
Bottom ≠ Turner
Pres=50 bar, A=10, FTHP=10 bar, ID=4.291”
WGR=100, CGR=100
WGR=0, CGR=100
WGR=0, CGR=0
Especially at higher Qmin
(above 50e3 m3/d or 2
MMscf/d)
19
Importance of Liquid Loading
20
Material Balance – “Single Tank”
Determine incremental reserves based on reduction of minimum
achievable reservoir pressure (Pmin)
Qmin=0.3 mln m3/d
(P/Z)ab=34 bar
UR=1.62 Bcm
P/Z (bara @ datum level)
350
300
K7-FB-101
K7-11
250
Material Balance
Qmin=0.15 mln m3/d
(P/Z)ab=28 bar
UR=1.66 Bcm
(RF +2%)
200
150
100
50
0
0.0
0.5
1.0
1.5
2.0
2.5
3.0
Gas Produced (mrd m3)
21
GWD Very Important for Tight Gas Reservoirs
100%
Reservoir Quality
Compression
0%
Recovery Factor
GWD
Primary
Depletion
HorWell
Stimulation
Tight
Poor
Moderate
Prolific
22
Gas Well Deliquification
Methods
23
Gas Well Deliquification
Wellhead compressor
Increase gas rate above Qmin
Compression, stimulation, gas
lift, intermittent production
Reduce Qmin
Compression, velocity string,
foam, plunger
Remove liquid
Downhole pump
Continuous foam
24
Life-Cycle GWD Strategy
Early Life
Mid-Life
Late Life
•Casing Flow
•Tubing Flow
•Intermittent
Production
•Compression
•Velocity
String
•Foamer
•Plunger
•More
Compression
•Gas Lift
•Downhole
Pump
25
Deliquification Techniques
1.
Intermittent production
2.
Compression
3.
Velocity string
4.
Continuous foam
5.
Plunger lift
6.
Gas lift
7.
Downhole pump
26
Intermittent Production
27
Size of the
Natural
Cycle
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
1
2
3
4
5
(3) Meta-stable production: some gas
produced to surface, liquids injected
downhole
(4) No production: no gas production,
liquids injected downhole, pressure recovery
28
Size of theCycle
Managed
Prize – Intermittent Production (IP)
(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
1
2
3
4
5
(3) Meta-stable production: gas produced
to surface, liquids injected downhole
(4) No production: no gas production,
liquids injected downhole, pressure
recovery
29
IP – Field Example 1
COV33
1.E+05 50
THP (Barg)
Gas Rate (e3 m3/d
90000
1
80000
2
3
4
5
70000
60000
5
1
1
5
50000
2
2
40000
30000
20000
3
4
4
10000
0
0
07/10/2010 00:00:00
2.00 days
30
09/10/2010 00:00:00
Two Tank Model
Reservoir pressure at onset of
liquid loading is unchanged
for fast tank
Vfast
Pslow
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
Vslow
Pfast
Crossflow
Pslow2 – Pfast2 = R.Q
Inflow
Pfast2 – FBHP2 = A.Q + F.Q2
FBHP
Outflow
FBHP2 = B.FTHP2 + C.Q2
FTHP
Fast
Tank
Slow Tank
31
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)
32
Uptime (SPE 153073)
Close to 100% uptime in
first stage of liquid loading
33
Compression
34
Effect of Compression
Well close to
Liquid Loading
Stable
Production
BHP (↓) = ∆Phyd (↓) + ∆Pfric (↑) + ∆Pacc + FTHP (↓)
Increased gas rate above Qmin and reduced Qmin
35
Twin-Screw Pumps
Liquid knock out
• Bornemann
• Well-Cluster Pump
• Leistritz MPS Series
• Single-Well Pump
• 8-1,100 Mscf/day (22731,000 m3/day)*
• 16 bar (232 psi) Boost
• 8-90 kW (10-120 hp)
• Applications:
• up to 15,000 Mscf/day
(425,000 m3/day)*
• up to 50 bar (700 psi)
Boost
•Application:
• 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:
File
Title
• Bornemann SLM Series
• Single-Well
Penn West (Canada) - Red
Earth Field
ExxonMobil (Germany) –
Lastrup Field
Mobil (Canada)
Talisman Energy
(Canada)
* At Pwellhead = 10 bar (150 psig)
36
Velocity String
37
Effect of Velocity String
VS- Qmin
Increase in Gas Velocity - Reduced Qmin
Qmin
38
Velocity String Example 1
TID305
7” Casing
50000 50 50
3-1/2” Tubing
VS Installed
2” VS
THP (Barg)
Gas Rate (e3 m3/d
Temparature (⁰C)
40000
30000
20000
10000
0
0 0
01/07/2000 00:00:00
NATGAS NATGAS NATGAS
123.00 days
39
01/11/2000 00:00:00
11
/1
/1
99
11
6
/1
5/
1
9
11
/2 96
9/
12 199
6
/1
3/
12 199
6
/2
7/
1
1/ 996
10
/1
1/ 997
24
/1
99
7
2/
7/
19
9
2/
21 7
/1
9
3/ 97
7/
1
3/ 997
21
/1
9
4/ 97
4/
1
4/ 997
18
/1
99
7
5/
2/
19
5/
9
16 7
/1
5/ 997
30
/1
6/ 997
13
/1
6/ 997
27
/1
7/ 997
11
/1
7/ 997
25
/1
99
7
8/
8/
19
8/
9
22 7
/1
99
7
9/
5/
1
9/ 997
19
/1
10 997
/3
/
10 199
7
/1
7/
1
9
10
/3 97
1/
19
97
Velocity String Example 2
Total Cost: $20,121
7” Casing
2-3/8” Tubing
1200
VS Installed
1000
800
200
Average rate for 90 days prior to installation: 246 mcfd
1-1/4” VS
MCFD
Tubing PSI
Casing PSI
Line PSI
Projection
600
400
☺
Paid out in 3 months
0
Average for last 30 days: 327 mcfd
40
Average rate for 90 days prior to installation: 911 mcfd
MCFD
Line PSI
projection
Average rate for last 30 days: 539 mcfd
12/22/2000
12/8/2000
11/24/2000
11/10/2000
10/27/2000
10/13/2000
9/29/2000
9/15/2000
9/1/2000
8/18/2000
8/4/2000
1200
1000
-20
800
-40
VS Installed
-60
400
-80
200
-100
0
-120
Cum We dge (MMscf)
2-3/8” Tubing
7/21/2000
7/7/2000
6/23/2000
6/9/2000
5/26/2000
5/12/2000
4/28/2000
4/14/2000
5-1/2” Casing
3/31/2000
3/17/2000
600
3/3/2000
2/18/2000
2/4/2000
1/21/2000
1/7/2000
12/24/1999
12/10/1999
11/26/1999
11/12/1999
10/29/1999
10/15/1999
10/1/1999
Gas Rate (ks cf/d)
Velocity String Example 3
Gross Cost: $19905
1-1/4” VS
0
Huge reduction in well capacity
Timming of VS installation is crucial
cumwedge
41
Foam-Continuous/Intermittent
42
Foam
Injection
Continuous
Foam (CF) [TC 285⇓
⇓143]
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 sticks
Automated
43
Continuous Foam Lift
(CF) [TC 285⇓
⇓143]
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
200
Gas Rate (e3 Sm3/d)
150
100
50
0
0
10
20
30
40
50
Foam Injection Rate (L/d)
60
70
Installing cap string
44
Continuous Foam –LiftField
– Field
Example
Example
1
45
CF – Field Example
Continuous
Foam – Solutions to Retain SCSSV
Actuated
Offshore
Control line fluid and Surfactant
SV
FWV
UMGV=SSV
LMGV
FV=SCSSV
KW
Control line fluid
Onshore
KW
Manual
SV
FWV
UMGV=SSV
LMGV Surfactant
REN-LMGV
FV=SCSSV
46
Plunger
47
Plunger Lift
The various parts of a plunger lift are:
4
1. Bottomhole spring
2. Plunger
3. Arrival sensor
3
8
5
7
4. Lubricator/catcher
6
5. Pressure transducers
6. Motor valve(s)
7. Gas flow meter
2
8. Wellhead controller
1
48
Plunger Lift: Working
1.
Plunger at surface, well open: Gas is
produced, liquid accumulates on top of
the standing valve
Well shut-in: Plunger drops to the bottom
2.
3.
4.
5.
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
49
80000
70000
Plunger falls
90000
Well Shut in
1.E+05 20 50
Plunger arrives
WYK-32
Well Open up
Plunger Lift Example 1
THP (Barg)
Gas Rate (e3 m3/d
Temparature (⁰C)
60000
50000
40000
30000
10000
0
0 0
01/07/2012 19:54:57
Plunger rises
20000
Shut-in
period
Flow period
6.00 hours
02/07/2012 01:54:49
Target velocity up = 150-300 m/min
1200 m AHD in 6 min = 200 m/min
50
Gas Lift
51
Effect of Gas Lift in Gas Wells
PRes = 58 Bara
Paban = 53
Bara
Natural
Flow
Gas Lift
Lift Gas Ratio Limited to 1
Optimum Gas Injection
Rates
Reservoir Depletion
FBHP (in Bara)
LGR = 1585
sm3/Msm3
ΔPgain = 8 Bar
Paban = 45
Bara
Injected Gas Ratio
Supplies additional gas thus reducing the Qmin
52
Gas Lift Completions
Side Pocket
Mandrel
Coiled tubing with
internal mounted
gas lift valves.
Retrofit
53
Downhole Pump
54
Effect of Downhole Pump
55
Deliquification Selection
56
One Tool Does Not Solve All Problems
57
Deliq Selection Process
In the Deliq selection process, the feasibility is evaluated based on the following
factors:
Dimension limitations
Wellbore configuration
Service or support
Reliability
Desired rate versus depth
Reservoir abandonment
pressure
Efficiency
Footprint
Temperature
Fluid make-up and properties
￭ Gas-to-liquid ratio
￭ Chemical properties
￭ Solids or sand
Infrastructure
Environmental impact
Productivity
Connected volume
Reference: Lea, J.F. et al., “What’s New in Artificial Lift?”, World Oil, May 2013, 55-67
© Shell International Petroleum Co. Ltd.
RESTRICTED
September 2013
58
Deliq Selection Curves
Tbg ID 4”
FTHP 100 bara
WGR
100 m3/e6sm3
Pmin (bara)
100
10
1
Prolific
10
NFA
Plunger
A (bar2/e3Sm3/d)
Compression
VelString_2"+Plunger
100
VelString_2"
GasLift_Dry
1000
Foam
Pump
Tight
59
Deliq Selection Table
Criteria
MWHC
VS
CF
GL
DP
PL
?
High LGR
Large
Separator
Start-up
Issues
Good at
High WCR
Limited by
pump
capacity
High Freq
?
?
No Issues
Large
amounts
May cause
jamming
?
?
?
Mandrel or
Retrofit
Large Tbg
size
Monobore
Completion
No Issues
Solids
Require
separation
No Issues
No Issues
Completion
No Issues
No Issues
No Issues
60
Deliq Selection Table
Criteria
MWHC
VS
CF
Deviation
No Issues
Can be
installed in
long Horiz.
No Issues
GL
DP
PL
?
?
?
<50-60⁰
(Wireline)
?
Costs
High
Reliability
<50-60⁰
Mid
?
Mid
Low
(CO avail.)
High
?
Excellent
LK-2
failures
Low
?
Excellent
Limited
61
GWD Selection
Make
GWD Part– of
Summary
Initial Well & Facility Design
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
.....................
62
63