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