Gas Well De-Liquification Workshop Denver, Colorado March 1 - 3, 2004 Adaptive Product Technology for Coalbed Natural Gas (CBM) William A. Grubb, General Manager Weatherford International Ltd.
Gas Well De-Liquification Workshop Denver, Colorado March 1 - 3, 2004 Adaptive Product Technology for Coalbed Natural Gas (CBM) William A. Grubb, General.
Dec 18, 2015
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Gas Well De-Liquification Workshop
Denver, Colorado March 1 - 3, 2004
Adaptive Product Technology for Coalbed Natural Gas (CBM)
William A. Grubb, General ManagerWeatherford International Ltd.
Forms of Lift Used in CBM
Electric Submersib
le Pumping
(ESP)
PlungerLift
Reciprocating Rod Lift
Progressing Cavity Pumping
(PCP)
De-watering Characteristics
Technology to de-water coal changes over life of well or field
Coal deposits are often active aquifers
Initial wells can produce substantial water volumes
Water production declines with time
Development or in-fill wells typically come on at higher gas – water ratios
De-watering/Production Cycle
Two key points to de-watering success: Maintain low BHP Do not shut-in the well – water refloods coal
Mean Time to Failure / Run Life
Capital Expense (CAPEX)
Lease Operating Expense (LOE)
Deliverability & Production Rates
Water Disposal
Operator’s Objectives & Decision Drivers
Lift Technologies forCoalbed Natural Gas Applications
Progressing Cavity Pumping
Electric Submersible Pumping
Plunger Lift
Reciprocating Rod Lift
Automation
* If vented or if natural gas anchor is used.
ElectricMotor
400° F or less
Good
Good
Good
Good
Workover orPulling Rig
Excellent
35% - 60%
10,000’ TVD or less
20,000 BPD or less
Electric Submersible
Operating Depth (Typical)
Operating Volume (Typical)
Operating Temperature
Corrosion Handling
Gas Handling
Solids Handling
Coal Dust Handling
Servicing
Prime Mover
Offshore Application
Overall System Efficiency
PlungerLift
4,500’ TVD or less
2,200 BPD or less
150° F or less
Fair
Good
Excellent
Good
Workover orPulling Rig
Gas or Electric
Good
40% - 80%
1,000’ TVD or less
30 BPD or less
120° - 550º F
Excellent
Excellent
Good
WellheadCatcher or Wireline
Wells’ Natural Energy
N/A
N/A
Good
Reciprocating Rod Lift
8,000’ TVDor less
1,500 BPD or less
100° - 350º F
Good
Good*
Good
N/A
50%-60%
Progressing Cavity
Workover orPulling Rig
Gas or Electric
Good
System ConsiderationsFor Coalbed Natural Gas
Progressing CavityPumping Systems
PC Pump Advantagesin Coalbed Natural Gas Operations
Able to produce problem wells; excellent solids handling - coal, shale and sand
Gas producing capabilities High system efficiency Produce wells with poor cement
jobs Flexibility in production volume
with one pump Remote locations without power
and pilot projects
Wellhead
Drive
Casing
Production Tubing
Sucker Rod
StatorRotor
Tubing Collar
Tag Bar Sub
Electric SubmersiblePumping Systems
ESP Advantagesin Coalbed Natural Gas Operations
Low to moderate costs for shallow depth wells
Minimal surface profile
Flexibility in production volumes with VFD
Repairable, which reduces LOE
Good gas handling with gas separator
Good solids handling when built with hardened bearings
Plunger Lift Systems
Plunger Lift Advantages in Coalbed Natural Gas Operations
Unload wells that continue to load up with produced wellbore fluids
Installed as a method of dewatering High GLR coalbed natural gas wells
Maintains higher operating pressure on rate sensitive coalbed natural gas wells
Lubricator
Catcher
Solar Panel
Controller
Dual “T” Pad
Plunger
Bumper
Spring
Reciprocating Rod Lift Systems
Rod Lift Advantagesin Coalbed Natural Gas Operations
Low to moderate costs for shallow depth wells
High system efficiency
Excellent flexibility – can alter stroke speed /length, plunger size, run time to control production
Equipment available with wide range of gear reducers, structural ratings and stroke length combinations
Surface equipment available in low profile design for visually-sensitive areas
Excellent salvage value
Sucker Rod
Tubing Anchor/
Catcher
Sucker RodPump
Assembly
Case Histories
Progressing Cavity Pumping
Electric Submersible Pumping
Plunger Lift
Reciprocating Rod Lift
PCP - Coalbed Natural Gas
Initially client had 5 ESP failures within 2 months
Well data for this problem well -
1100’ depth and 7” casing with 2-3/8” tubing
Introduced a 100-2100 Buna PCP with 4.3 L hydraulic drive system - July 2000
Solution: Increased the net gas rate to 550 mcf
Case History
PCP - Coalbed Natural Gas
0
100
200
300
400
500
600
700
800
900
Gas Production
Water Production
BP
D /
MC
D
Weath
erf
ord
PC
PC
om
men
ces O
pera
tion
Case History continued
Best Practices & Lessons LearnedBest Practices & Lessons Learned
PCP – Coalbed Natural Gas
Necessary to run looser fitting pumps
Lower RPM extends run life
Reduced tubing wear with full rod on top of rotor
Two snap-on rod guides per rod
Case History
ESP - Coalbed Natural Gas
Client initially ran conventional water well submersible equipment
Average run times were < 4 weeks – equipment sent to junk pile after failure
Well Data:
–Depth - 600’-1,200’
–Casing - 5 ½” and 7”
–Tubing – 2 3/8” and 2 7/8”
Installed specialized CBM-ESP™ with enhanced gas and abrasion handling capabilities
Used repairable CBM equipment CBM-ESP substantially increased run
times
ESP - Coalbed Natural Gas
ESP Average Days Running
43 5586
109140
170201
232262
293323
354385
10 14 14 15 15 15 15 15 15 15 15 15 15
0
50
100
150
200
250
300
350
400
450
Jan-03
Feb-03
Mar-03
Apr-03
May-03
Jun-03
Jul-03
Aug-03
Sep-03
Oct-03
Nov-03
Dec-03
Jan-04
Day
Ru
nn
ing
(R
ed B
ars)
0
50
100
150
200
250
300
350
Nu
mb
er o
f P
um
ps
Inst
alle
d (
Blu
e L
ine)
Insta
lled
CB
M-E
SP
Case History continued
Best Practices & Lessons LearnedBest Practices & Lessons Learned
ESP – Coalbed Natural Gas
Essential to gather correct application data for sizing
When possible, pre-assemble pump, motor and screens
Use proper field techniques when handling
ESP should be manufactured with compression stages and hardened bearings
When applicable, install ESP with inverted shroud intake
Client initially ran rod lift pumps
Gas locking problems occurred as reservoir was de-watered and GLR increased
Well Data: Perf. Depth: 1100 ft. Casing - 5 1/2” 17 ppf Tubing – 2 3/8” 4.7 ppf, J-55
Plunger Lift Coalbed Natural Gas
Case History
Plunger Lift Installed
Plunger Lift Installed
Rod Pump Plunger Lift
Plunger Lift Coalbed Natural Gas
Best Practices & Lessons Learned
Evaluate production for required GLR to drive system
Examine PPM dissolved solids and coal fines for possible screen application
Shut well for pressure build up
Evaluate shut in pressure vs. GLR
Plunger Lift - Coalbed Natural Gas
Rod Lift - Coalbed Natural Gas
45 rod pumping wells, with oldest installed in 1993
PCPs were unsuccessful
Well Data:
– Perf. Depth: 2,000 ft.
– Casing - 5 1/2” and 7”
– Tubing - 2 3/8”, 2 7/8” and 3 1/2”
Case History
Rod Lift – Coalbed Natural Gas
Rod Pumps Average Days Running
2341 46
77
107 105
135149
180 173
204215
228240
253238 244 252
270
301284
2 36 6 6
8 8 9 911 11 12 13 14 15
1820
22 23 23
27
0
50
100
150
200
250
300
350
May-02
Jun-02
Jul-02
Aug-02
Sep-02
Oct-02
Nov-02
Dec-02
Jan-03
Feb-03
Mar-03
Apr-03
May-03
Jun-03
Jul-03
Aug-03
Sep-03
Oct-03
Nov-03
Dec-03
Jan-04
Day
s R
un
nin
g (
Red
Bar
)
0
5
10
15
20
25
30
35
40
45
50
Nu
mb
er o
f P
um
ps
(Blu
e L
ine)
Case History continued
Insta
lled
Rod
P
um
p
Rod Lift – Coalbed Natural Gas
Tried grooved plungers; determined traditional chrome barrel pumps worked best
Wipers added to top and bottom of plunger increased pump life by keeping coal fines and solids from entering pump
Developed regular pump replacement schedule every 6 months, even though company was experiencing pump runs of up to 18 months, to minimize downtime, keep pump efficiencies high and maximize fluid production ( gas production)
Best Practices & Lessons Learned
Q&A
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