Transcript No Slide Title

Use of Transient Simulators to
Assess Gas Lift Viability for
Offshore Angola
2002 North
American
Gas Lift Workshop
SHAUNA NOONAN
/ FRED BROWNLEE
© ChevronTexaco 2001
Actually a better title would be:
Produce 40,000 BWPD
from 23,000 ft MD (8800 ft TVD)
via Gas Lift
Fact or Fiction?
February 5, 2002
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Presentation Outline
Operating Parameters
Discussion on software (transient and static programs)
Work scope
Some of the results
What did we learn?
Questions
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Parameters
• 4500 psi injection pressure at wellhead
• Target production of 40,000 bwpd / well
• 0.68 gravity injection gas
• Up to 30 MMscfd source gas available / well
• 1.06 gravity water
• Wellhead pressure of 250 psi
• Reservoir Pressure of 3500 psi
• Dry Tree (offshore in 1200 ft water)
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Deviation Profile
Deviation Profile ( Whd @ 20.00 feet )
Offset (feet)
0
0
2000 4000 6000 8000 10000 12000 14000 16000 18000 20000
1000
True Vert Depth (feet)
2000
3000
4000
5000
6000
7000
8000
9000
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From previous nodal analysis...
The target rate may be reached via conventional gas lift for a
flow area equivalent to 8 5/8” tubing.
This would require gas lift rates of approximately 20 MMscfd.
BUT…..
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We have the following concerns:
• Strategic importance of this well for project development
• Static nodal program cannot predict whether the well could
be unloaded.
• Transient program can predict unloading conditions, but
uses flow correlations that are not valid for large tubing
sizes (greater than 5.5”)
• Existing transient flow program is not capable of reverse
flow completions analysis.
• At the high injection pressures required, is the gas actually
in a gaseous state at the orifice?
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OLGA 2000
“OLGA 2000 is the market-leading simulator for transient multiphase
flow of oil, water and gas in well and pipelines with process equipment. “
→ Over 10,000 experiments were run in eight years on the
SINTEF Two-Phase Flow Laboratory near Trondheim, Norway
→ The tests were run in both steady state and transient modes
→ The resultant data / correlations reside within OLGA 2000
→ ChevronTexaco has been using this program for many years to
assess flow assurance issues in pipelines and risers. It has not
been used for downhole analysis applications
→ Limited to single point gas lift configurations
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The Plan
• Evaluate various completion options for high rate water wells
using three different flow analysis software packages:
– Well Evaluation Manager (WEM) using OLGAs
– Dynalift
– OLGA2000
• Evaluate Dynalift when used for large tubing completions
• Develop & validate the well unloading sequence
• Confirm importance of surface controlled downhole choke
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Scope of Study
The following scenarios were evaluated:
• Case WA1: Lift gas injection down 11¾” casing with 8⅝” tubing.
• Case WA2: Lift gas injection down 11¾” casing with IPC 7” tubing
• Case WA3: Lift gas injection down 11¾” casing with IPC 8⅝” tubing
• Case WB1: Lift gas injection down 3½” tubing with 9⅝” casing
• Case WB2: Lift gas injection down 2⅞” tubing, with 9⅝” casing
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Results
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Case WA1 - Steady State
Water Well (Case WA1: 8 5/8 tubing, gas injection down annulus)
45000
40000
Total Water Produced (bwpd)
35000
30000
25000
20000
15000
10000
5000
0
0
5000
10000
15000
20000
25000
30000
Injected Gas Rate (mscfd)
WEM (OLGAs)
Dynalift (transient with Beggs Brill)
Scandpower (OLGA2000)
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Case WA1 - Steady State
Injection Pressure at Wellhead (psia) / Differential Pressure
across Orifice (psi)
WA1: Comparison of Operating Pressures
3500
1750
3000
1500
2500
1250
2000
1000
1500
750
1000
500
500
250
0
0
5000
10000
15000
20000
25000
0
30000
Injected Gas Rate (mscfd)
OLGA2000
Dynalift
dP (OLGA2000)
WEM (OLGAs)
dP (WEM)
dP (Dynalift)
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Case WA1
Notes:
• Separation between WEM & OLGA2000 not fully
explained; (possibility - OLGA2000 starting with transient
flow first)
• Dynalift example uses 0.5” orifice - significant at higher
flow rates (problems with 1”)
• OLGA2000 & WEM assume a fixed pressure differential
not a fixed choke
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BBT Water Voidage Well - GLG Down Annulus - Std. Tubing
ACCU MULATED LIQUID VOLUME FLOW TUB_OU T_Q [bbl]
PRESSUR E ANN_IN [ps ia]
PRESSUR E ANN_OUT [ps ia]
PRESSUR E TUB_IN [ps ia]
GAS MASS FLOW ANN _OU T_Q [kg/s]
TOTAL LIQUID VOLUME FLOW TUB_OUT_Q [bbl/d]
C ONTROLLER SIGNAL CTL_GLV [-]
2000
4500
7
200000
1
0.9
4000
6
0.8
Note the 180,000
bwpd slug OLGA
predicted during the
unloading cycle.
3500
1500
150000
5
0.7
3000
0.6
2000
100000
-
kg/s
1000
psia
bbl
2500
bbl/d
4
0.5
3
0.4
1500
0.3
2
500
50000
1000
0.2
1
500
0
0
0.1
0
0
0
0
5
10
16
Time [h]
Benguela-Belize - Gas -Lift down Annulus
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Case WA1 - Unloading
BBT Water Voidage Well - GLG Down Annulus - Std. Tubing
TubGIunload20: PRESSURE NAT_IN [ps ia]
TubGIunload20r: PRESSUR E N AT_IN [ps ia]
TubGIunload20: TOTAL LIQU ID VOLUME FLOW TU B_OUT_Q [bbl/d]
TubGIunload20r: TOTAL LIQUID VOLUME FLOW TUB_OUT_Q [bbl/d]
4500
200000
4000
150000
psia
bbl/d
3500
100000
3000
50000
2500
2000
0
0
5
10
15
16
Time [h]
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Case WA2
Water Well (Case WA2: 7" plastic lined tbg, gas injection down annulus)
45000
40000
Total Water Produced (bwpd)
35000
30000
25000
20000
15000
10000
5000
0
0
5000
10000
15000
20000
25000
30000
Injected Gas Rate (mscfd)
WEM (OLGAs)
Scandpower (OLGA2000)
Dynalift (transient with Beggs Brill)
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Case WA1 versus Case WA3
WA1 versus WA3 (conventional versus plastic lined 8 5/8" tubing.
50000
45000
Total Water Produced (bwpd)
40000
35000
30000
25000
20000
15000
10000
5000
0
0
5000
10000
15000
20000
25000
30000
35000
Injected Gas Rate (mscfd)
WA1 WEM (OLGAs)
WA1 Dynalift
WA1 Scandpower (OLGA2000)
WA3 WEM (OLGAs)
WA3 Dynalift
WA# Scandpower (OLGA 2000)
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Effect of IPC
Injection Pressure at Wellhead (psia) / Differential Pressure across
Orifice (psi)
WA1 versus WA3: Comparison of Operating Pressures
3000
2500
2000
1500
Roughness Difference
Case WA1: 0.0018
1000
Case WA3: 0.00006
500
0
0
5000
10000
15000
20000
25000
30000
Injected Gas Rate (mscfd)
WEM (OLGAs)
dP (WEM)
WA3 WEM (OLGAs)
WA3 dP (WEM)
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Case WB1
Water Well (Case WB1: Reverse flow gas lift.. 9 5/8" csg with 3.5" tbg .... equivalent flow area of
8 5/8"))
45000
40000
Total Water Produced (bwpd)
35000
30000
25000
20000
OLGA2000 & WEM
include pressure loss from
casing connections in
annulus; Dynalift uses
equivalent area
15000
10000
5000
0
0
5000
10000
15000
20000
25000
30000
Injected Gas Rate (mscfd)
WEM (OLGAs)
Scandpower (OLGA2000)
Dynalift (equiv. Flow area using Beggs Brill)
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WHAT DID WE LEARN?
• Have a higher degree of confidence that this well could be
unloaded.
• Question of conventional versus reverse gas lift must include
drilling feasibility and operational safety concerns
• WEM OLGAs works well for assessing well performance but
does not answer unloading questions
• For higher rate / pressure single point gas lift systems, surface
controlled downhole gas lift valves are mandatory to reduce
upsets while unloading the well
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QUESTIONS?
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