Case History of Gas Lift Conversions in Horizontal Wells in the Williston Basin

Keith Fangmeier, Terry Fredrickson, Steve Fretland, and Lee Rieger, Amerada Hess Corporation

Abstract

For several years Amerada Hess (AHC) has been redeveloping the Beaver Lodge Madison Unit utilizing horizontal drilling. Relatively, large fluid volumes (2,500 – 3,000 BFPD), high water cuts (~90%), and low bottom hole pressures characterize a typical BLMU horizontal well. Until recently, electric submersible pumps (ESP) were installed as the preferred artificial lift method to produce the high fluid volumes. ESP failures were common due to high gas volume fractions (GVF) at the pump intake (60–90%); which were caused by high formation gas liquid ratios (FGLR) and liquid/gas slug flow induced by the long horizontal laterals. In order to reduce downtime and mitigate high workover costs, several of the horizontal wells have been converted to continuous gas lift with encouraging results. This paper will focus on horizontal well production before and after gas lift conversions and include a lifting cost comparison between ESP and gas lift.

Introduction

The Beaver Lodge Madison Unit (BLMU) is located on the Nesson Anticline of the Williston Basin, 3 miles south of Tioga and 35 miles east of Williston, ND. (See Figure 1.)

Figure 1. Location of Beaver Lodge Field

1 The field was discovered in April, 1951 and unitized in July, 1958. A peripheral water flood enhanced oil recovery project was initiated in 1959 after reservoir pressure had declined from 3,821 psia to 2,600 psia. Waterflood injection was discontinued in 1971. (See Figure 2.)

BLMU 36,000 BOPD

33,000 MCFD

30,000 BWPD

BWIPD 27,000

s 24,000 e t a R

n 21,000 o i t c e j n I

18,000 &

n o i t 15,000 c u d o r

P 12,000

0 1 5 9 3 7 1 5 9 3 7 1 5 9 3 7 5 5 5 6 6 7 7 7 8 8 9 9 9 0 0 ------t t t t t t t t t t t t t t t c c c c c c c c c c c c c c c O O O O O O O O O O O O O O O Date Figure 2. Production History

Beginning in 1998, the field has been revitalized with new horizontal drilling techniques. To date the BLMU has recovered 54 MMBO, 92 BCF, and 102 MMBW.

The Madison reservoir consists of a highly fractured limestone reservoir system with a distinct southwest to northeast facture trend. The reservoir area is 15,200 acres with average thickness of 154 feet and net thickness of 49 feet. (See Figure 3.)

2 T156N R95W

Figure 3. Beaver Lodge Madison Unit

The natural drive mechanism is a depletion/edge water drive. Reservoir conductivity appears to be dominated by the northeast/southwest trending natural fracture system. See Table I below for reservoir property summary.

Table I. BLMU 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

3 Currently, reservoir pressure ranges from 1,100 to 2,300 psig and GOR is in excess of 5,000 scf/bo . Pressure depletion has created a secondary gas cap.

Since 1951, over 200 vertical wells have been drilled of which seven are still on production. Cumulative production for a typical Madison vertical well is 255 MBO and 413 MBW. To date, 17 horizontal wells have been drilled and completed in the Rival zone of the Madison formation with 16 of the 17 horizontal wells oriented normal to the natural fracture system. Horizontal wells represent over 95% of unit’s total current production. Initial rates for Madison horizontals average 400 BOPD, 3000 BWPD, and 2.5 MMCFPD. When drilling a horizontal well, seven inch production casing is set to 8,250 feet TVD, the well is kicked off just below the shoe, and completed as a 5.875 inch open hole lateral. Due to a massive salt section located just above the Madison formation, heavy weight casing is used. (See Figure 4.)

4 Figure 4. Example Wellbore Schematic

5 Furthermore, the proximity of a salt section to the Madison requires short radius geometry with a typical radius from vertical to horizontal in 20’ to 200±’. Typical horizontal lateral lengths are 2,750’ to 3,250’. (See Figure 5.)

BLMU H-9H MD (Ft.) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 4 8 2 6 0 0 0 0 0 0 2 0 6 4 0 8 4 2 0 0 0 0 , , , , , , , , , , , , , 6 2 0 6 4 8 4 8 2 2 2 2 1 1 1 1 1 0 0 0 0 0 , , , , , , , , , 1 1 1 1 1 1 1 1 1 1 1 1 1 9 9 9 9 9 8 8 8 8 8,100

Csg Shoe - 8245' MD, 8244' TVD 1st Ratcliffe - 8276' MD, 8275' TVD KOP - 8285' MD, 8284' TVD 8,200 2nd Ratcliffe - 8329' MD, 8328' TVD 8,245

8,276 ) .

8,285 t F ( 8,300 D V 8,329 T

8,390 8,400 5 1 2 ,

2 8,444 1 2 3 4

, 8,490 0 0 4 1 6 0 , 4 9 5 , 8

Figure 5. Example Horizontal Section

As can been seen from the Figure 5, the horizontal lateral has several highs and lows in the profile. As inflow begins to decline, gas accumulates in the highs and liquid accumulates in lows. The accumulations continue until pocket gas bridges the hole diameter and is eventually forced out as a slug 1. The constant gas/fluid slug flow is believed to be the primary problem in the consistent ESP failures.

Management, engineering, and field personnel evaluated the ESP failures. The team decided to convert several ESP operated wells to continuous gas lift utilizing 2-7/8” tubing. Production rates with 2-7/8” gas lift systems, in most cases, were less than the ESP systems; but the gas lift systems were more reliable. Therefore to reestablish production rates, additional attempts were made by AHC to utilize advanced gas handling equipment recently developed by the ESP manufactures. After each of the new designs failed to sustain long run lives, a new continuous gas lift design was incorporated with help from Williston based gas lift service personnel. The new gas lift design utilized 3.5” tubing and currently is the preferred lift method because of increased production and lower lifting expenses.

The current gas lift design evolved because of extensive teamwork between management, field personnel, engineering, and service companies and opened the door to several production optimization opportunities. The next phase is facility and pipeline system modifications to further increase production.

The BLMU gas gathering system contains both low pressure and high pressure lines. Gas lift supply gas is supplied by the high pressure system after being processed by the Tioga Gas Plant (owned by AHC). The average compressor discharge pressure is 1,310 psig and the average wellhead gas injection pressure is 1,220 psig. The Tioga Gas Plant’s gathering/compression system has been an asset for implementing a gas lift strategy. Currently, 16 of the 17 horizontal wells are currently being produced by continuous gas lift.

6 BLMU Field Redevelopment

The various artificial lift phases of the field redevelopment are:

 Phase 1: ESP’s and GL with 2-7/8” tubing;  Phase 2: ESP’s with advanced gas handling equipment;  Phase 3: GL with 3.5” tubing;  Phase 4: Facility and pipeline modifications; and  Phase 5: Future enhancements.

Phase 1. ESP’s and GL with 2-7/8” Tubing

After drilling the first horizontal well in 1998, an ESP was installed. Due to the relatively low bottom hole pressures in the Madison formation, fluid loss is substantial during drilling. In some instances upwards of 40,000 barrels of fluid have been lost. Pressure depletion, combined with an anticipated 90% water cut and lost drilling fluids, led the engineering staff to select ESP’s (380-400 HP systems) to effectively clean up the well after drilling. Failure rates were common with the initial ESP installations often averaging 2 failures per year per well. The failures were consistent with gas handling issues, but also badly worn pumps were seen during teardowns due to this clean-up operation.

In BLMU, declining reservoir pressure and flowing bottom hole pressures yields higher FGLR’s and subsequently higher GVF’s. In addition, the GVF’s became erratic because of the liquid/gas slug flow induced by the long horizontal laterals

After several failed ESP installations, continuous gas lift was installed at various locations utilizing 2-7/8” tubing. The first designs generally were two unloading valves with the first valve located at the static fluid level. Operating valves were installed to bottom spaced about every 400 feet with an orifice on bottom. Due to the corrosive nature of the produced fluid, 1.50” stainless steel conventional IPO gas lift valves with Monel checks were installed with 1/4” and 5/16” ports. The initial gas lift designs were reliable, but yielded lower production rates than the ESP systems. However, overall production increased with continuous operation (no shut downs with gas lift system). The Madison reservoir with horizontal wells appears to go through a transition or de-watering phase before normal production rates resumes. (See Figure 6.)

7 Production Tests After Gas Lift Conversion

500 3000

Converted to ESP 450 2700 ESP Failure

400 2400

350 2100 e 300 1800 t a R

t Oil Rate (BOPD) e a t a R 250 1500 Gas Rate (MCFD) l W i

& Water Rate (BWPD)

Converted back to ESP s 200 1200 a G

150 900 Produced by GL 100 600

50 300

0 0 0 1 0 0 0 1 0 0 0 1 0 7 0 1 4 7 0 1 4 7 0 1 ------2 2 2 1 1 1 2 2 2 1 1 8 6 4 9 9 4 4 3 1 8 6 ------2 2 2 2 2 2 2 2 2 2 2 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1 1 2 2 2 2 3 3 3 3 4

Figure 6. Example Rates after Gas Lift Conversion

As can be seen from the figure above, the production dramatically dropped of after it was converted to gas lift. Due to the production decrease from Phase 1 gas lift system, new ESP gas handling technologies were incorporated into next ESP designs.

Phase 2. ESP’s with Advanced Gas Handling Equipment

Fluid/gas slug flow and high FGLR’s are common to BLMU horizontal wells. These conditions are attributable to the effect of dual porosity systems and sinusoidal well profiles encountered in the horizontal laterals. This producing environment challenges normal ESP gas handling technology. To overcome this problem, two prototype gas handling systems were installed in a few of the horizontal wells. The initial installation of one of these systems proved to have a favorable run life (8 months); but after the initial failure, subsequent installations had short run lives. The next generation of gas handling systems was installed on two horizontal wells drilled during the summer of 2003. After short run lives of less than 3 months on both installations, both wells were converted to gas lift.

Phase 3. GL with 3.5” Tubing

After evaluating the initial gas lift systems with 2-7/8” tubing, it became evident that tubing capacity was restricting the flow rates. Through nodal analysis it was determined that 3.5” tubing and potentially 4.5” tubing could return production to the higher ESP production rates. The gas lift designs were similar to the previous designs and incorporated two unloading valves with the first valve placed at the static fluid level. Operating valves were installed to bottom and spaced about every 400 feet with an orifice on bottom. As before, 1.50” stainless steel conventional IPO gas lift vales with Monel checks and port sizes between 1/4” and 5/16”. As the wells started to unload to lower operating points, production continued to increase with results higher than modeled. (See Figure 7.)

8 Well 1 Production Tests

900 4000

800 3500

700 3000 ESP Failure 600 2500 e t a R

e 500 2000 r

t Oil Rate (BOPD) e a t a R

Gas Rate (MCFD) l W i

& Water Rate (BWPD)

400 1500 s a G 300 1000

200 500

0 -500 0 0 0 0 0 0 1 1 1 1 1 0 6 6 7 8 8 9 0 0 1 2 2 1 ------0 1 2 0 2 0 1 2 0 1 1 2 8 8 7 6 6 5 4 8 7 6 5 5 ------2 2 2 2 2 2 2 2 2 2 2 2 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 3 3 3 3 3 3 3 3 3 3 3 4

Well 2 Production Tests

650 6500

600 6000

550 5500

500 5000

450 4500

400 4000 e t a R e r t Oil Rate (BOPD)

350 3500 e a t a R

Gas Rate (MCFD) l W i 300 3000 O

& Water Rate (BWPD)

ESP Failure s a

250 2500 G

200 2000

150 1500

100 1000

50 500

0 0 0 0 0 0 0 0 0 0 1 1 1 1 1 0 5 8 0 0 1 2 1 4 6 6 7 8 9 2 ------1 2 0 2 1 0 1 2 0 2 1 0 1 2 9 9 8 8 8 7 7 6 6 6 5 5 5 4 ------2 2 2 2 2 2 2 2 2 2 2 2 2 2 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 3 3 3 3 3 3 4 3 3 3 3 3 3 3

Figure 7. Production Tests after Conversions

9 Gas interference in pumps and high GVF’s, was limiting the drawdown capability of the ESP systems. Increasing tubing capacity from 2-7/8” to 3-1/2” resulted in higher production rates. As gas rates increased on well 2, injection gas was shut off and the well started to flow. Due to the increased production rates, several facility and pipeline modifications were identified. A summary of key wells and average GVF’s from a daily test is included in Table II. Note that both C-05 and V-27 initially produced with manageable GVF’s, but GVF’s increased over time. In addition, the GVF’s are calculated on a 24 test rate and varied considerably in 24 hours from the average rate calculated because of terrain slugging2.

Table II. Summary of Average GVF’s Lift FGLR PIP Well Name Well Test BOPD BWPD Oil % MCFD GVF Type (scf/bbl) (psig) 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 1899 1800 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 2622 1500 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 815 2000 est 48.00%

Phase 4. Facility and Pipeline Modifications

The increased production rates resulted in some bottlenecking issues in several flowlines and production equipment. To resolve these bottlenecking issues, a plan was devised to place a portable production facility (PPF) at the specified location. The PPF offered several advantages to installing a larger flowline to the current satellite battery:

 monitor well continuously;  removes gas at the well site lowering wellhead pressure;  minimizes construction time; and  can be easily removed and moved to other wells after production declines.

The PPF is a 48” horizontal separator, measurement equipment, electronic control devices, and a transfer pump. The PPF is equipped with a radio transmitter that allows the separator pressures/temperatures, flow rates, etc. to be communicated to field and engineering offices via a basic Supervisory Control and Data Acquisition system (SCADA). One of first installations of the PPF resulted in lowering the wellhead pressure and a production increase, but due to the non linear productivity index (PI) of a dual porosity system reservoir, the production increase was better than predicted. (See Figure 8.)

10 Well 3 Production Tests

1000 10000

900 9000

800 8000

700 7000 e 600 6000 t a Oil Rate (BOPD) P R

T Converted to GL r

F FTP e / t e a t 500 5000 Gas Rate (MCFD) a W

l Water Rate (BWPD) & i

s O 400 4000 a G

300 3000

200 2000

100 1000 Installed PPF 0 0 0 0 0 1 1 0 0 0 0 0 1 1 0 0 5 7 9 0 2 1 3 5 6 8 0 1 1 3 ------0 2 2 0 0 2 1 2 1 1 2 2 1 0 1 1 0 9 6 5 4 4 3 0 9 8 7 4 ------2 2 2 2 2 2 2 2 2 2 2 2 2 2 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 2 2 2 2 2 3 3 3 3 3 3 3 4 4

Figure 8. Production Before and After the Installation of a PPF

Phase 5. Future Enhancements

Currently, engineers are evaluating the use of 4.5” tubing or installation of an annular flow gas lift system. Several potential high volume gas lift opportunities exist in the BLMU and include the following:

 install 4.5” tubing (7-5/8” casing only);  install annular flow with conventional gas lift pressures; and  increase the gas injection pressure, with annular flow, for single point deep injection in the horizontal section.

Annular flow and 4.5” tubing would provide increased flow capacity; however as demonstrated by field tests, small changes in drawdown can produce dramatic production increases. Therefore, facility constraints need to be addressed before the installation of these systems. The annular flow system utilizing 2-7/8” tubing inside 7” or 7-5/8” casing provides a flow capacity equivalent to 4.5” tubing and would deliver 5000+ bpd and 5 MMCFPD. Ultimately the ultra high pressure system may reduce heading created by the horizontal completion by injecting gas in the horizontal section.

11 Lifting Costs Summary

BLMU lifting expenses decreased when lift techniques were changed from ESP’s to gas lift. Compression costs are relatively inexpensive at $0.40 per MCF of injection gas. On average, most gas lift wells inject 1,000 MCFD which results in a daily injection gas charge of $400. Daily costs to run an ESP include specified rental charge and power consumption; which result in a daily ESP charge of $560. Assuming all other controllable expenses are the same, a gas lift system saves an average of $160/day/well. Therefore, with the assumption of two ESP failures per year, the lifting costs for an 800 barrel of oil equivalent (BOE, 6 MCF = 1 BO) per day well are as follows:

 Gas Lift: $0.72/BOE;  ESP: $1.31/BOE.

Inflow Performance

Inflow performance for BLMU horizontal wells in a dual porosity system is difficult to predict. The productivity index (PI) appears to increase with increasing drawdown. As the flowing bottom hole pressure is reduced, small fractures “open up” contributing to inflow. Generally the fractures extend into the secondary gas cap and provide a rapid increase in gas production. Experience with North Dakota horizontal wells indicates that an increased drawdown not only increases total liquid production but typically water cuts decrease in the early stages with increasing liquid production. Furthermore, the FGLR will increase as total liquid production increases. (See Figure 9.)

Well 2 FGLR vs. Time

2500 25%

2000 20% Well Shut In

1500 Converted to 15% GL l i R FGLR L O

% % Oil F

1000 10%

500 5%

0 0% 0 0 0 0 0 1 1 1 0 5 6 7 8 9 0 1 2 1 / / / / / / / / / 2 2 2 2 2 2 2 2 2 8 8 6 6 4 9 7 5 5 / / / / / / / / / 2 2 2 2 2 2 2 2 2 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 3 3 3 3 4 3 3 3 3

Figure 9. FLGR Response to Increased Drawdown

Therefore, the PI for a BLMU horizontal well appears to be non-linear and makes predicting well performance difficult, but is a definite upside to BLMU operations.

12 Automation Overview

The BLMU utilizes an in-house SCADA system for well and facility surveillance. Currently, the SCADA system monitors vessel conditions, pump pressures, and flow rates through the vessels. In addition, the system records well test data and projects 24 hour tests. The SCADA system, a UNIX based system, is functionally difficult for technicians and operators to view screens and obtain information.

In early 2004, a new SCADA system incorporating Iconics software will be installed. A primary goal of new system is improved gas lift well surveillance. With real-time wellhead surveillance and automation data available on a portable laptop computer, the production operations team can quickly identify well problems and opportunities to improve gas lift performance.3 The Iconics system is being developed as a web based program enabling engineers the ability to continually monitor the data from the office or home. Each gas lift well will send real time data from the Total flow computer and flowline pressure/temperature transmitters to the office. Data will be stored in central database for easy access. By simply clicking on the facility and well name, production engineers will be able analyze 24 hour trends and the well’s most recent production test. Flowline pressure and temperature, casing pressure, lift gas injection rate, and choke position trends will all be available to the users. In addition, electronically controlled chokes are being installed at each gas injection point. After determining the optimum injection gas rate, the choke will be programmed to maintain this rate. By maintaining a constant gas injection rate, slugging problems could be reduced. The new SCADA system will provide production engineers invaluable information for identifying potential optimization candidates.

Conclusions

 The BLMU’s secondary gas cap, natural fractures, and horizontal completions create a production opportunity that is best exploited with gas lift.

 Inflow modeling of a naturally fractured reservoir with horizontal completions is difficult.

 Experience with North Dakota horizontal wells indicates that an increased drawdown not only increases total liquid production but FGLR’s will likewise increase.

 The State of North Dakota does not have a prorated regulatory system. Thus, in the BLMU an operator can produce a well at a maximum or most efficient rate.

 Increased drawdown permits recovery of drilling fluids and solids lost while drilling the depleted Madison formation. Furthermore, obtaining an increased drawdown allows the wellbore (probably from the natural fracture system) to produce drilling fines and thus enhance deliverability.

 Operating Tioga Gas Plant at capacity has increased the profitability of the plant.

 Incremental oil production and associated water variable expense is insignificant when compared to the fixed operating expense. Thus incremental oil/gas produced from the Phase 3 and 4 modifications has a significant impact on operating income.

 Well performance appears to improve as a result of continuous operations. The power grid in North Dakota is weak and numerous power interruptions and subsequent start-ups of ESP equipment yields deferred production. Once a well is down and restarted the well must go through a transition period and de-watering phase before production resumes a ‘normal rate’.

13 Acknowledgments

The authors thank Fred Roberts of Production Service Company in Williston, ND for sharing his extensive knowledge of gas lift design and management of Amerada Hess for their permission to compose this paper.

References

1. Noonan, S. G. et al: “Impact of Transient Flow Conditions on ESP in Sinusoidal Well Profiles: A Case Study,” paper SPE 84134 presented at the 2003 SPE Annual Technical Conference and Exhibition held in Denver, Colorado, U.S.A., 5-8 October 2003.

2. Muecke, N.B., Kappelhoff, G.H., Watson, A., “ESP Design Changes High GLR and High Sand Production; Apache Stag Project.

3. Reeves, D., Harvey Jr., R., and Smith, T.: “Gas Lift Automation: Real Time Data to Desktop for Optimizing an Offshore Platform,” paper SPE 84166 presented at the 2003 SPE Annual Technical Conference and Exhibition held in Denver, Colorado, U.S.A., 5-8 October 2003.

4. Beliveau, D.: “Heterogeneity, Geostatics, Horizontal Wells, and Blackjack Poker,” JPT (December 1995) 1068.

5. Vicente, R., Sarica, C., and Ertekin, T.: “Horizontal Well Design Optimization: A Study of the Parameters Affecting the Productivity and Flux Distribution of a Horizontal Well,” paper SPE 84194 presented at the 2003 SPE Annual Technical Conference and Exhibition held in Denver, Colorado, U.S.A., 5-8 October 2003.

6. Sato, K.: “Productivity Correlation for Horizontal Sinks Completed in Fractured Reservoirs,” SPE Reservoir Eval. & Eng., Vol. 3, No. 2, April 2000.