1. CASING HEAD PRESSURE FINE TUNING in Dual String Gas Lift Well With Injection Pressure Operated Valve
ASME – WORK SHOP - KUALA LUMPUR 2003
By:
Gatut Widianoko ( Weatherford )
Herry Subekti ( BP – Indonesia )
Wahyu Jatmiko ( BP – Indonesia )

2. Abstract
After two ( 2 ) years gas lift optimization performed with concentrated in gas lift change out, starting this year 2003, Bp -Indonesia begin to focus on Casing Head Pressure Tuning.
The first year, the gas lift optimization had made 3500 bopd oil gain, and the second year had made 4000 bopd oil gains. This year, up-to the second quarter 2003, BP had made 4500 bopd oil gains. This total gains is came from 40 % gas lift change out, and 60 % from Casing Head Pressure Tuning.
Today we are going to talk about the steps of casing head pressure tuning of the BP-Indonesia gas lift optimization on dual string gas lift well as follow :
1) Identify the gas lift well problems ;
2) Nodal analyzing to determine the well potential ;
3) Optimize point of injection of both string by gas lift change
out ;
4) Perform Tuning Casing Head Pressure to optimize both
string.

3. Offshore North West Java Oil Field
JAKARTA
BIMA
ARDJUNA AV
AVS AA MX MQ MR MM MB LL L
BZZ B K U E F ZU P 25
50 KM X
KLX
KLY
KNA KL KK
APN O
CILAMAYA
KALIMANTAN
SULAWESI
SUMATERA
J A V A GG
GG Gas
Accumulation
“O” AREA POD
ARIMBI
CIREBON

4. BP Wells General Conditions
Old Oil Field with more than 30 years old
High FGOR with 1000 : 1 or more
Low PI with only about 1 – 3 blpd / psi
Low Production with about blpd
Low Static Pressure with average ~ 600 psi
Limited Casing Pressure with ~ 600 psi only
Flowing Tubing Pressure is about 180 psi
Shallow well - reservoir depth ~ 3000 ft TVD
Limited data (SBHP and PI is normally unknown)
Old wells - may have leaking valve or tubing
Some gas lift valves installed 5-10 years ago
Some gas lift header choke stuck open/close

5. Dual Completion ECHO - WELLs Adjust CHP , Reduce / increase
COMPLETION DIAGRAM
NOT TO SCALE
9-5/8” 4285’ MD
2-7/8” 286’
Packer @ 3111’ MD
Packer @ 3504’
EZ ( 4016’ ’ )
( 4025’ – 4031’ )
( 4035’ – 4043’ )
( 4050’ – 4062’ )
1050’
3032’
2-7/8” SPM
1012’
2625’
3007’
2-7/8” WB-1D 3383’
2-7/8” WB-1D 3183’
2-7/8” 248’
EZ-22B ( Squeezed-Off )
Packer @ 3340’
2-7/8” WB-1D 3584’
2-7/8” WB-1D 3100’
EZ-23 ( 3389’ ’ )
EZ-24B ( 3590’ ’ )
4205’ MD
Packer @ 3900’
2-7/8” WB-1D 3164’
1898’
2652’
1866’
Find CHP problems
Adjust CHP , Reduce / increase
Slowly until get best
production rate. Repeat it if
needed. Keep best this CHP as
operating pres.
Great savings of time
&
efforts
Dual Completion

6. CHP Fine Tuning Candidates Wells ( Gas Lift Optimization )
Suddenly production rate drop
Suddenly the well dead
Casing Head Pressure unstable
Suddenly gas injection rate increase/decrease
Inaccurate gas rate measure
Robbing, and cause one (1) string dead or drop
The well shutdown under maintenance
The well shut-in while service status
Gas lift Change out is being perform
Suddenly Casing Head Pressure Increase
Suddenly Casing Head Pressure decrease
Suddenly Flowing Tubing Head Pressure increase

7. Casing Head Pressure Tuning Steps in Dual Gas Lift well
Use graphical method to construct the well condition. Draw the static and flowing pressure gradient, etc.
Select Kick Off and best Operating pressure available.
Use 90% (max) off Kick Off as Operating pressure.
Select best point of injection of both string ( close or same depth ) and operating port size (close or same size).
Use same surface opening and closing pressure for both string valve.
Perform gas lift well performance by software on each string to determine optimum condition .
Perform CHP tuning by open the Gas Lift Header Choke and set at the kick off pressure selected.
Adjusts the CHP slowly to reach the Best Surface Operating Pressure selected.
Record the Rates. Select the best rate and keep best CHP.

8. Graphical Method (To determine best Point of Injection, KO and OP)
Echo- Wells
PRESSURE (p s i)
500
1000
1500
FTP
CHP D E P T H Ft V
0.1 p s I / ft
Casing Pressure FL
1000 #1
Tubing
Pressure #2
2000 #3
0.45 p s i / ft #7
3000
Mid Perforation
FBHP
1200 p s i
4000
Operating Pres.
Kick Off

9. Gas Lift Well Performance
Gas Injection Rate Vs Production Rate
Optimum Point
Q l
Q i
Q I : Gas in Rate mscfd
Q l : Prod. Rate blpd

10. Why Do instead of Casing Head Pressure tuning
Gas Injection Rate Tuning ?

11. Gas Measurement Problems
Not each platform has a good measurement
facilities
Some Gas Measuring inaccurate
Gas Injection rate not recorded
Gas in VS CHP does not make sense
We Decided
Using CHP as parameter to optimize gas injection
Adjust CHP to find a best production rate of both
String
Measure Gas In, after best CHP reached / selected
Record and keep best CHP of each Well

12. WHAT IS BEST CHP Back to The Original Operating Pressure Design
Where is the existing CHP ?
Is it too high ?
Any un-loader valve reopen?
Is the existing gas in too much ?
Do We need to decrease it ? OR
Is it too low ?
Is the existing gas in too low ?
Can the existing CHP pressure reach the operating valve ?
Do we need to Increase it ?
Any actions needs to be done ?

13. Decreasing CHP (To determine Best Operating Pressure) Existing CHP
Too High
Echo- Wells
PRESSURE (p s i)
1500
FTP
500
CHP
1000 D E P T H Ft V
0.1 p s I / ft
Casing Pressure FL
1000 #1
Tubing
Pressure #2
2000 #3
0.45 p s i / ft #7
3000
Mid Perforation
1200 p s i
FBHP
4000
Best Operating Pres.
Kick Off

14. Increasing CHP (To determine Best Operating Pressure) Existing CHP
Too Low
Echo- Wells
PRESSURE (p s i)
500
1000
1500
FTP
CHP D E P T H Ft V
0.1 p s I / ft
Casing Pressure FL
1000 #1
Tubing
Pressure #2
2000 #3
0.45 p s i / ft #7
3000
Mid Perforation
FBHP
1200 p s i
4000
Operating Pres.
Kick Off

15. Some Wells Sample of CHP tuning at BP-Indonesia
Best CHP
Oil Gains : 250 b o p d
Best CHP : 520 p s i
Sample : A

16. Some Wells Sample of CHP tuning at BP-Indonesia
440
Best CHP
Oil Gains : 70 b o p d
Sample : B

17. Some Wells Sample of CHP tuning at BP-Indonesia
Best CHP
Oil Gains : 80 b o p d
Sample : C
Best CHP : 590 p s i

18. Sample of One Platform CHP Tuning Results
* Total Gains for one platform by CHP tuning : 150 b o p d
* Gas gains is not recorded
* Working Days : 10 days.

19. Total Oil Gains by CHP Tuning YTD up to 2nd Qtr

20. Total Oil Gains by Gas Lift Change Out YTD up to 2nd Qtr’ 03

21. Total Oil Gains After Gas Lift Optimization YTD up to 2nd Qtr’ 03

22. Tuning Results VS Gas Lift Change Out Results up to 2nd Qtr’ 03

23. Well Work Percentage TOTAL GAS LIFT JOB YTD UP TO 2nd Qtr’ 03
Total Wells analyzes : 190 wells
Completed by Wire line : 31 wells
: 87 Wells potential
: 18 Wells had optimum
: 5 New wells
: 44 Wells CHP Tuning
: 36 Wells Needs FGS & SBHP
survey

24. Total Oil Gains After Gas Lift Optimization YTD Up to 2nd Qtr’ 03

25. CHP Tuning – Lessons Learned ( With Injection Pressure Valve )
Enough Kick Off (KO) and Operating (OP) Pressure to reach deepest point of injection is required
Differential pressure between KO and OP is ~10% of casing pressure, (or at least 50psi).
Use graphical method to select best point of injection and best draw down of both (200 – 500 psi) strings.
Surface opening pressure of both string are same. Use at least 10 psi less than the CHP available.
Surface closing pressure of both strings must be at least 20 psi above OP, and 30 psi less than KO
To avoid “gas robbing” - depth point of injection of both strings must be close or equal; same thing in the port size
Perform CHP tuning to reach Optimum Conditions
Watch the CHP performance and Keep it at best CHP.