Case History of Gas Lift Case History of Gas Lift Conversions in Horizontal Conversions in Horizontal Wells in the Williston BasinWells in the Williston Basin
Authored by Keith Fangmeier, Terry Fredrickson, Authored by Keith Fangmeier, Terry Fredrickson, Steve Fretland, and Lee RiegerSteve Fretland, and Lee Rieger
Amerada Hess CorporationAmerada Hess Corporation
Williston BasinWilliston Basin
South Dakota 31 Million Barrels
North Dakota 1,361 Million Barrels
Manitoba 212 Million Barrels
Saskatchewan 1,776 Million Barrels
Montana 815 Million Barrels
Beaver Lodge FieldBeaver Lodge Field
Beaver Lodge Madison Unit Beaver Lodge Madison Unit Historical ProductionHistorical Production
BLMU
100
1,000
10,000
100,000
Oct
-51
Oct
-55
Oct
-59
Oct
-63
Oct
-67
Oct
-71
Oct
-75
Oct
-79
Oct
-83
Oct
-87
Oct
-91
Oct
-95
Oct
-99
Oct
-03
Oct
-07
Date
Pro
du
ctio
n &
Inje
ctio
n R
ate
BOPD
MCFD
BWPD
BWIPD
BLMU Field MapBLMU Field Map
T155N
R95WT156N
BLMU Reservoir PropertiesBLMU Reservoir Properties
Permeability 2.1 md
Porosity 9.10%
Original GOR 1773 scf/bo
PBP 3205 psia
Oil Gravity 39-42
Water Salinity/Gravity 287,000 ppm/1.18
Hydrogen Sulfide 2.60%
Reservoir Temperature
241 F
Example Horizontal SectionExample Horizontal Section
BLMU H-9H
10,4
32
8,444
8,276
8,245
8,4909,
640
8,285
8,54
0
8,390
8,329
12,2
15
8,100
8,200
8,300
8,400
8,500
8,20
0
8,40
0
8,60
0
8,80
0
9,00
0
9,20
0
9,40
0
9,60
0
9,80
0
10,0
00
10,2
00
10,4
00
10,6
00
10,8
00
11,0
00
11,2
00
11,4
00
11,6
00
11,8
00
12,0
00
12,2
00
12,4
00
MD (Ft.)
TV
D (
Ft.
)
Csg Shoe - 8245' MD, 8244' TVD1st Ratcliffe - 8276' MD, 8275' TVDKOP - 8285' MD, 8284' TVD2nd Ratcliffe - 8329' MD, 8328' TVD
25’
BLMU Field RedevelopmentBLMU Field Redevelopment
Phase 1: ESP’s and GL with 2-7/8” tubingPhase 1: ESP’s and GL with 2-7/8” tubing Phase 2: ESP’s with advanced gas Phase 2: ESP’s with advanced gas
handling equipmenthandling equipment Phase 3: GL with 3.5” tubingPhase 3: GL with 3.5” tubing Phase 4: Facility and pipeline modificationsPhase 4: Facility and pipeline modifications Phase 5: Future enhancementsPhase 5: Future enhancements
Phase 1. ESP’s and Phase 1. ESP’s and GL with 2-7/8” TubingGL with 2-7/8” Tubing
ESP’sESP’s Installed in the initial completions to recover Installed in the initial completions to recover
the large fluid volumes during drilling the large fluid volumes during drilling (~40,000 bbls)(~40,000 bbls)
Produced large fluid volumes (~3,000 BFPD)Produced large fluid volumes (~3,000 BFPD) Replaced with GL ran on 2-7/8” due to Replaced with GL ran on 2-7/8” due to
continual pump failures (2 failures/well/year)continual pump failures (2 failures/well/year) Failures with consistent gas handling issuesFailures with consistent gas handling issues
Example Rates after Gas Lift ConversionExample Rates after Gas Lift Conversion
Production Tests After Gas Lift Conversion
0
50
100
150
200
250
300
350
400
450
500
07-28-2001
10-26-2001
01-24-2002
04-24-2002
07-23-2002
10-21-2002
01-19-2003
04-19-2003
07-18-2003
10-16-2003
01-14-2004
Oil
Rat
e
0
300
600
900
1200
1500
1800
2100
2400
2700
3000
Gas
& W
ater
Rat
e
Oil Rate (BOPD)
Gas Rate (MCFD)
Water Rate (BWPD)
ESP Failure
Converted to ESP
Produced by GL
Converted back to ESP
Phase 2. ESP’s with Advanced Phase 2. ESP’s with Advanced Gas Handling EquipmentGas Handling Equipment
Installed to maximize productionInstalled to maximize production Utilized the new technologies from two Utilized the new technologies from two
ESP manufacturesESP manufactures Initial installation had a favorable run life Initial installation had a favorable run life
of 8 months, but subsequent installations of 8 months, but subsequent installations had short run lives (< 1 month)had short run lives (< 1 month)
Phase 3. GL with 3.5” TubingPhase 3. GL with 3.5” Tubing
Keeps wells onlineKeeps wells online Overrides the heading issuesOverrides the heading issues 3.5” tubing provided more tubing capacity3.5” tubing provided more tubing capacity
Production Tests after Conversion Production Tests after Conversion using 3.5” OD Tubingusing 3.5” OD Tubing
Well 1 Production Tests
0
100
200
300
400
500
600
700
800
900
06-08-2003
06-28-2003
07-18-2003
08-07-2003
08-27-2003
09-16-2003
10-06-2003
10-26-2003
11-15-2003
12-05-2003
12-25-2003
01-14-2004
Oil
Rat
e
-500
0
500
1000
1500
2000
2500
3000
3500
4000
Gas
& W
ater
Rat
e
Oil Rate (BOPD)
Gas Rate (MCFD)
Water Rate (BWPD)
ESP Failure
Converted to GL
Production Tests after Conversion Production Tests after Conversion using 3.5” OD Tubingusing 3.5” OD Tubing
Well 2 Production Tests
0
50
100
150
200
250
300
350
400
450
500
550
600
650
04-29-2003
05-19-2003
06-08-2003
06-28-2003
07-18-2003
08-07-2003
08-27-2003
09-16-2003
10-06-2003
10-26-2003
11-15-2003
12-05-2003
12-25-2003
01-14-2004
Oil
Rat
e
0
500
1000
1500
2000
2500
3000
3500
4000
4500
5000
5500
6000
6500
Gas
& W
ater
Rat
e
Oil Rate (BOPD)
Gas Rate (MCFD)
Water Rate (BWPD)
ESP Failure
Converted to GL
Summary of Average GVF’sSummary of Average GVF’s
Well Name Well Test Lift
TypeBOPD BWPD Oil % MCFD
FGLR (scf/bbl)
PIP (psig)
GVF
BLMU C-05H 06/01/2003 ESP 335 2393 12.30% 502 184 2175 6.30%
BLMU C-05H 06/26/2003 ESP 228 1688 11.90% 1093 570 1916 40.30%
BLMU C-05H 12/30/2003 GL 397 2619 13.20% 5728 18991800 est 73.70%
BLMU H-09H 02/24/2003 ESP 367 2460 13.00% 3487 1233 1607 66.70%
BLMU H-09H 12/30/2003 GL 558 2504 18.20% 8028 26221500 est 82.50%
BLMU V-27H 10/01/2003 ESP 593 2235 21.00% 1520 537 2382 25.70%
BLMU V-27H 12/30/2003 GL 717 3656 16.40% 3565 8152000 est 48.00%
Phase 4. Facility and Pipeline Phase 4. Facility and Pipeline
ModificationsModifications
Production EnhancementProduction Enhancement Install portable production facility (PPF)Install portable production facility (PPF)
Removes gas at well site lowering FTPRemoves gas at well site lowering FTP Monitor well continuouslyMonitor well continuously Minimizes construction timeMinimizes construction time Easily removed and moved to other wellsEasily removed and moved to other wells More cost effective than installing larger flowlinesMore cost effective than installing larger flowlines
Gas Lift Pressure ChartGas Lift Pressure Chart
Production After Installation of PPFProduction After Installation of PPFWell 3 Production Tests
0
100
200
300
400
500
600
700
800
900
1000
05-24-2002
07-13-2002
09-01-2002
10-21-2002
12-10-2002
01-29-2003
03-20-2003
05-09-2003
06-28-2003
08-17-2003
10-06-2003
11-25-2003
01-14-2004
03-04-2004
Oil
Rat
e/F
TP
0
1000
2000
3000
4000
5000
6000
7000
8000
9000
10000
Gas
& W
ater
Rat
e
Oil Rate (BOPD)
FTP
Gas Rate (MCFD)
Water Rate (BWPD)
Converted to GL
Installed PPF
Lifting Cost SummaryLifting Cost Summary
Gas Lift: $0.72/BOEGas Lift: $0.72/BOE ESP: $1.31/BOEESP: $1.31/BOE BOE = BO + (MCF/6)BOE = BO + (MCF/6)
Inflow PerformanceInflow Performance
Dual Porosity System (matrix/fracture)Dual Porosity System (matrix/fracture) Difficult to predictDifficult to predict PI increases with increasing drawdownPI increases with increasing drawdown FGLR increases with liquid productionFGLR increases with liquid production
FLGR Response to Increased FLGR Response to Increased DrawdownDrawdown
Well 2 FGLR vs. Time
0
500
1000
1500
2000
2500
05/29/2
003
06/28/2
003
07/28/2
003
08/27/2
003
09/26/2
003
10/26/2
003
11/25/2
003
12/25/2
003
01/24/2
004
FG
LR
0%
5%
10%
15%
20%
25%
% O
il
FGLR
% Oil
Converted to GL
Future EnhancementsFuture Enhancements
install 4.5” tubing (7-5/8” casing only);install 4.5” tubing (7-5/8” casing only); install annular flow with conventional gas install annular flow with conventional gas
lift pressures; andlift pressures; and increase the gas injection pressure, with increase the gas injection pressure, with
annular flow, for single point deep annular flow, for single point deep injection in the horizontal section.injection in the horizontal section.
Nodal Analysis Comparing Nodal Analysis Comparing Annular vs. Tubular FlowAnnular vs. Tubular Flow
Production Capacity Comparison
0
500
1000
1500
2000
2500
3000
3500
0 1000 2000 3000 4000 5000 6000 7000 8000BPD
Flo
win
g B
ott
om
Ho
le P
ressu
re--
PS
I
2-3/8" x 5.5" Annular Flow
2-7/8" x 7" Annular Flow
3-1/2"
4-1/2"
Automation OverviewAutomation Overview
SCADA system currently in placeSCADA system currently in place Scheduled to be replaced with a web based Scheduled to be replaced with a web based
surveillance systemsurveillance system New system will allow production engineers to trendNew system will allow production engineers to trend
Casing pressureCasing pressure Injection gas rateInjection gas rate Flowline pressureFlowline pressure Flowline temperatureFlowline temperature
New system will used to better optimize productionNew system will used to better optimize production
ConclusionsConclusions The BLMU’s secondary gas cap, natural fractures, and The BLMU’s secondary gas cap, natural fractures, and
horizontal completions create a production opportunity horizontal completions create a production opportunity that is best exploited with gas lift.that is best exploited with gas lift.
Gas lift is more cost effective than ESP’s in the BLMU.Gas lift is more cost effective than ESP’s in the BLMU. Inflow modeling of a naturally fractured reservoir with Inflow modeling of a naturally fractured reservoir with
horizontal completions is difficult.horizontal completions is difficult. The State of North Dakota allows an operator to produce The State of North Dakota allows an operator to produce
wells at a maximum or most efficient rate.wells at a maximum or most efficient rate. Increased drawdown permits recovery of lost drilling Increased drawdown permits recovery of lost drilling
fluids and solids and subsequently increases GLR’s.fluids and solids and subsequently increases GLR’s. Well performance appears to improve as a result of Well performance appears to improve as a result of
continuous operations. continuous operations. High volume lift systems require coordination between High volume lift systems require coordination between
production engineering and field operations.production engineering and field operations. Gas lift is essentially transparent to the problems induced Gas lift is essentially transparent to the problems induced
by terrain slugging.by terrain slugging.
AcknowledgmentsAcknowledgments
Fred Roberts of Production Services in Fred Roberts of Production Services in Williston, North DakotaWilliston, North Dakota
Amerada Hess Management TeamAmerada Hess Management Team