SPE 126681

ESP Application to De-bottleneck Gas Lift System Offshore Fathi Shnaib, SPE, Production Engineering Team Leader, Dubai Petroleum; Manickam S. Nadar, SPE, Production Engineering Consultant, Smart Zone Solutions; and Steve Booth and Ademola Otubaga, SPE, Lead Production Engineers, Dubai Petroleum

Copyright 2010, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Oil and Gas India Conference and Exhibition held in Mumbai, India, 2022 January 2010. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract The Falah field offshore Dubai consists of four satellite platforms and is mostly produced by gas lift. High pressure lift gas is received from the main SWFateh field and the produced fluid and gas after a two-phase separation are returned to SWFateh through long sub-sea pipelines. The system is constrained both on the gas lift supply and surface production networks. The conversion of two of the major gas lift producers to electric submersible pump (ESP) has helped de-bottleneck the Falah system.

The main objectives were to increase drawdown in these wells using ESP and to reduce the load on the gas lift and production systems. Both of these objectives have been successfully achieved. This paper will describe the system constraints, the options considered and the economics associated with each option. The modeling work that helped the justification for the ESP installation will also be described.

The selection of well candidates was an important criterion for success. From a reservoir perspective the goal was to achieve improved oil recovery with increased drawdown. From a facility perspective the wells were selected at the farthest (FB) platform that had the minimum gas lift pressure in the field. Commissioning of the ESPs has reduced the gas load on the system and the production system pressures have decreased as a result. Gas lift operating depths would be deepened in some of the Falah wells, taking advantage of the increased gas lift header pressure now available.

The use of ESP for de-bottlenecking a gas lifted field is an excellent example of production system optimization. This demonstrates how a different type of artificial lift can be effectively used to improve the productivity of a field that uses one type of artificial lift.

Introduction

Selection of artificial lift method requires a consideration of several aspects of the petroleum production process the reservoir characteristics, type of recovery mechanism, fluid properties, reservoir depth, production rate per well, well construction details such as size of tubing and casing, well deviation, dog-leg severity, completion type, etc., availability of power, availability of high pressure gas, isolated or multiple well, environmental restrictions, onshore or offshore, completion and workover costs, availability of suitable technology and adequate technical support in the country and many more factors. Production problems such as corrosive environment, paraffin accumulation, sand production, emulsions, high gas-oil ratio (GOR) or high water-cut may also influenze the artificial lift selection. Furthermore, as the production conditions change over the life of the well, a new method may be more suitable for the rest of the life of the well and the well may be changed to a different artificial lift method (1).

Gas lift (GL), electric submersible pump (ESP) and hydraulic jet pumps are generally classified as high-volume lift methods whereas sucker rod pumps, progressive cavity pumps and hydraulic pumps come under the low volume artificial lift methods.

Artificial Lift Efficiency

The efficiency of an artificial lift system is given by Eq. 1:

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powerinput power useful

746.0/))((00000736.0

==

kWliftbpd liq

(Eq. 1)

The horse power required for the artificial lift directly depends on the production rate (bpd), the net lift head to be supplied by the lift system (ft.) and the specific gravity of the fluid being lifted (). A broad comparison of the overall system efficiency of various artificial lift methods is indicated in Table 1 (2), (3).

If the reservoir pressure declines, the artificial lift system will be required to supply a large amount of energy to maintain the production. For water-drive reservoirs where the reservoir pressure is reasonably constant, the increase in watercut will increase the bottom-hole pressure of the fluid column and hence more energy will be required to lift the heavier fluid. With the increase of water-cut, a much larger volume of fluid will have to be lifted for maintaining certain amount oil production. For example, if the watercut increases from 50 to 80%, for maintaining the oil production rate at 1000 bopd the volume of fluid to be lifted increases from 2,000 to 5,000 bfpd. Furthermore, as the watercut increases the formation gas-liquid ratio (GLR) decreases and if continuous flow gas lift is used, the amount of gas required to lift the liquid would become excessive and hence the advantage of gas lift becomes questionable for these conditions. The pump assisted lift can pump with lower bottom-hole pressures when compared to gas lift (1).

Thus the increase in lifting costs with increase with watercut is more pronounced with gas lift. This has a major impact on the operating costs as the efficiency of gas lift is low. Thus if other conditions are favourable it may be economically advantageous to use ESP as the lift method instead of gas lift at higher watercuts.

Impact of System Parameters

If the system network in which the well is a part of is seriously bottlenecked, it affects the performance of a gas lifted well more than that of an ESP lifted well. It is quite common that facilities and pipelines designed for lower rates are being used for handling much larger volumes during the later part of the life of a field. This is very often true for offshore where a pipeline replacement or laying new pipeline is very expensive and challenging.

The most economical total gas-liquid ratio (TGLR) is achieved when the profit obtained from lifting a quantity of oil by a unit increment of gas is just equal to the cost of that unit of gas (4). Thus it is desirable to maintain the TGLR equal to or slightly lower than this economic limit in order to stay profitable. However in network systems the consideration is more complex as the flowing wellhead pressure of a well is affected by the other components of system and therefore the optimum GLR will also depend on the resultant flowing wellhead pressure. The economic limit should be attributed to the system as a whole, rather than an individual well.

The bottleneck in a gas lifted network can be on the surface production network, gas lift system or both. A surface pressure constraint on the production system network increases the flowing wellhead pressure (FWHP), whereas a pressure constraint on the gas lift side decreases the available gas lift injection pressure at well location. Both these can reduce the production from a gas lifted well even if sufficient gas lift rate is available.

Figure 1 shows the well performance surface (WPS) of an example gas lifted well completed with 4.0 ID tubing and producing at 85% watercut. As shown by the plot, the production rate for a lift gas rate of 5.0 MMscf/D decreases from 760 to 610 bopd for an increase of the FWHP from 150 to 350 psia. It should be also noted that in order to produce the well at the maximum production rate possible by gas lift, the gas lift rate requirement increases from 5.0 to 7.5 MMscf/D as the FWHP increases from 150 to 350 psia. The maximum production possible from this well also decreases from 760 to 640 bopd due to the increase in FWHP. This is the result of the FWHP creating a direct back pressure on the formation face in a gas lifted well.

Figure 2 shows the injection pressure required to maintain the optimum gas lift rate to the same well while maintaining the downhole gas lift injection depth and gas lift valve (GLV) port size unchanged. The gas lift injection pressure required increases from 1100 to 1375 psig for an increase of the FWHP from 150 to 350 psia. In many occasions if the elevated gas lift injection pressure is not available, the operating point will be moved to a shallower depth. A shallow operating point reduces the hydraulic lift efficiency of the lift system.

Rather than lowering the pressure gradient in the tubing to reduce the bottom-hole pressure, as in gas lift, downhole pumps increase the pressure at the bottom of the tubing a sufficient amount to lift the liquid stream to the surface (5). On an ESP lifted well if the pump design is adequate the pump can be operated to provide the additional head that is required to overcome the increased flowline pressure in order to deliver well fluids. This will ensure that the flowing bottom-hole pressure (FBHP) and hence the drawdown are not affected. Figure 3 shows the pressure profile of an example ESP well where the pump has been speeded up from 58 to 60 Hz using a variable frequency drive (VFD) in order to maintain the pump intake pressure even though

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the flowline pressure has increased by 100 psi. The well production has not been affected. This is achievable only if the motor has sufficient horsepower to handle the additional load reqired to pump the fluid against the increased wellhead pressure.

Application Background

The Falah field is one of the four fields operated by Dubai Petroleum offshore Dubai. This field was discovered in 1972 and began producing in 1978 about 10 years after the start of production from other DP fields. The Falah wells have been drilled from four platforms. The main pipelines connected to the production system of interest are shown in Figure 4. The main gas lift compression and fluid separation facilities are available at SWFateh field. The high pressure gas required for gas lifting the Falah wells arrives from the SWFateh central facilities. However the produced fluid is separated using two-phase separators and sent to the SWF Field in separate liquid and gas lines. This is done to facilitiate easy transportation of fluids from Falah to SWFateh.

The production line up within the Falah Field is shown in Figure 5. The produced fluid is handled within Falah as two streams - the low pressure (LP) and high pressure (HP) streams. Gas and liquid flowing through the LP system gets its pressure boosted (gas compressed by the booster compressor and liquid pressured up by the oil transfer pumps) and sent to SWFateh. As the LP system is already flowing at above capacity limits it became necessary to flow part of the production through a HP separator. This will allow the gas outlet to join the booster compressor discharge and the liquid outlet to join the oil transfer pump discharge before these are direted into into the long departing pipelines. Usually most of the wells with high gas lift efficiency (i.e., wells with low injected gas-oil ratio, IGOR) are being produced through the LP system.

Over the years the Falah field has seen significant increase in production rates especially after the application of horizontal well drilling technology in this field. As a result the gas lift requirement of the Falah field has increased gradually with the increase of production and watercut. The reservoir pressure is being maintained by waterflooding. By the beginning of 2008 the flow rates in the Falah pipelines were such that the available gas lift header pressure at Falah was at its lowest. It was also necessary to maintain very high pressures in the production separators in order to move the fluids to SWFateh. The booster compressor was also overstretched in terms of its capacity.

The Falah field production optimization thus had the following major challenges:

1. Wells were not efficiently gas lifted due to high back pressure on the production system network and low gas lift pressure available. The pressure loss in the gas lift import pipeline was very large mainly due to high flow rates in the pipeline.

2. The Falah facilities were handling production rates more than the design capacity.

3. The operating depths of gas lifted wells were gradually being moved up-hole. This was making it impossible to achieve the drawdown desired for efficient reservoir management.

4. There were a few wells where it was required to further increase the drawdown. But this would not be possible with the existing system constraints.

5. The field water-cut was on the increase. This would mean that gas lift requirement of the field will increase in future.

6. There was no room available for performing any gas lift optimization in the field. Any small increase in gas lift rate to one well would lead to increase of production header pressure and further decrease of gas lift header pressure. The system was so much bottle-necked that the net benefit from any well optimization activity would be almost nothing.

7. Major expansion plans such as additional facilities (compression, separation, pump or additional pipelines) could not be justified due to marginal economics, mainly due to the significant investment required for these options and uncertainty around water-cut development.

Production De-bottlenecking Options

In order to address the de-bottlenecking issue, three major options were evaluated:

1. Upsize tubing of selected producers and continue on gas lift

2. Install Multi-phase booster pumps and reduce back-pressure on wells

3. Install ESP in a few selected wells

Tubing Upsize

Increasing the size of the production tubing decreases the frictional pressure gradient in the tubing. This allows a deeper gas lifting of the well even if gas lift supply pressure remains the same. This leads to increase of drawdown and hence more production.

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Figure 6 shows the gas lift response curves with 4.0 and 5.0 ID tubing strings for an example well, assuming no change in the inflow parameters and watercut. Even though the fluid production rate would increase, the major disadvantage with this option is that the lift gas demand on the system futher increases and makes the problem worse. As can be seen from the slope of the gas lift response curves for the example well, the optimum gas lift requirement increases from 3.5 to 5.5 MMscf/D due to the tubing upsizing. Yet another uncertainty is the water-cut behaviour of the well with the tubing upsize. With horizontal wells a change in the drawdown sometimes brings large changes in water-cut, and in most cases results in increased water production. Even though the production rate can be controlled if required, the tubing flow may become unstable if the production rate is reduced beyond the minimum stable rate. For these reasons this option was not selected.

Multi-Phase Booster Pump

The use of multi-phase pump (MPP) to de-bottleneck the Falah production system was investigated. The study revealed that it was technically feasible to increase production with the application of multi-phase pump and enhance the reservoir recovery (6). Four common types of MPP investigated in this evaluation are shown in Figure 7. Of these the twin-screw technology would be best suited for the application when compared with helicon-axial, progressive cavity and piston pumps.

The impact of the reduction in FWHP for a selected group of wells was investigated. The MPP will be required to handle very large gas-volume fractions (GVF) as all the wells are gas lifted. The GVF is currently around 95% and as the wellhead flowing pressure decreases the actual GVF increases beyond 99% (Figure 8). This increases the size of the pump required. The horsepower requirement for the MPP increases in an exponential fashion beyond a point, while the increase in oil production slows down (Figure 9).

The conclusion was that very large pump would be required to achieve a reasonable improvement in oil production. Additional deck space will have to be allotted and the power generation capability will have to be increased. Special construction barge will be required to install the MPP as the platform crane cannot lift the heavy load of MPP. Overall, the economics for the MPP option was positive but not very robust. Furthermore, the system bottlenecks will continue to remain. Hence this option was not pursued.

ESP

The consideration was to convert two wells from GL to ESP. Conversion of gas lifted wells into ESP producers should bring the following benefits. The benefits are of two types:

ESP Benefits

Well Benefits:

It should be possible to increase well production as higher drawdown can be achieved with ESP compared to gas lift. The increased well production is achieved with no additional gas load on the system.

System Level Benefits:

Converting two GL wells to ESP will free up about 6% of the Falah field gas lift load. The lift gas thus freed up can be used for allocating to other wells in the Falah field or elsewhere, thus making some spare lift gas capacity available for lift optimization of other wells. Freed up gas can also be used later for development wells.

The gas rate to be handled by the Falah booster compressor will marginally decrease. As a result it may be possible to either divert one more well from the HP system to the LP system or realize the benefit as a reduced LP separator pressure, whichever gives more oil production.

This will also reduce the LP gas load on the production system and therefore production separator pressure would decrease. All other wells will produce more fluid due to reduced FWHP.

GL Design Improvement in Other wells:

The reduced gas lift requirement would result in increased gas lift supply pressure at Falah platforms. This can be used to improve the gas lift efficiency of shallow-lifted wells by lifting deeper.

ESP Concerns

Even though the benefits are attractive from well and system performance aspects, the ESP option had the following concerns:

ESP run life

Need local power generation

SPE 126681 5

Need rig to replace the pump when it fails

Significant production downtime for rig move and positioning

Considering the investment costs (installing power generation, ESP installation) and the operating costs (power generator maintenance costs and the cost of performing a rig workover to replace a failed ESP considering a run life of 2-3 years), the economics was very positive due to the production benefits coming out of the ESP wells and from the system as a whole. There were two more factors which were advantageous for the ESP case:

There was less uncertainty around the well performance of the candidates selected for ESP. These were existing wells with known downhole performance for considerable time. Thus the resultant ESP well performance could be predicted with a good level of confidence. This also minimized the uncertainty around the sizing of the ESP as the well inflow performance was already known.

There was an ESP running in the Falah field already. The production engineering/operations organizations had already gone through a good learning curve in the installation and operation of ESP in the same field.

Chemical Methods DRA, CFU

In addition to these options, two chemical methods were investigated.

1. First was a field trial of a drag reducing agent (DRA) with an objective of reducing the frictional drag in the liquid pipelines connecting Falah platforms to the SWFateh Main facilities. This would not bring any noticeable benefit to the system and was not pursued.

2. A study was undertaken on the potential use of Compact Flotation Units (CFU) to treat and dispose the produced water at Falah (7). This in theory would reduce the fluid load on the liquid transfer lines from Falah to SWFateh, thus reducing the energy required to pump these fluids to SWFateh. There was some marginal cost saving on the chemicals utilized. But there was no significant reduction in the system bottleneck as the gas system would still remain constrained. The economics was not good. Furthermore there were environmental concerns of discharging overboard water from a remote platform. Hence this project was not pursued.

The decision therefore was to select the ESP option.

Candidate selection for ESP

A screening criterion was established for selecting the best candidate for this project (8). At a higher level, the candidate selection was approached from a project feasibility angle. Availability of the deck space was one of the first considerations. From the existing bottlenecks, the wells from FB platform (the farthest from the central facilities) were preferred. The main reason for this was that this platform had the lowest gas lift header pressure. About 27% of the delivery pressure supplied by the gas lift compressors at SWFateh was lost in the pipeline as friction loss. Incidentally this was the platform where the gas lift header pressure improvement could usher good uplift from other wells.

Once the platform was identified, following considerations were applied in screening the wells for the GL to ESP conversion:

1. The well should have stable and good reservoir pressure support.

2. Wells should have current flowing bottom-hole pressure at least 200 psi above the bubble point pressure of the formation. For this consideration, a lower limit on the FBHP was also agreed to with the reservoir engineering team for the ESP design and operation. This was done to ensure that the ESP would not lower the FBHP much below the bubble point pressure of the formation.

3. The impact of increase of fluid withdrawal rate by ESP on the overall reservoir management should be taken into account.

4. The selected candidate wells should have relatively low to medium water-cut.

5. Wells with very low productivity index (PI) should be avoided.

6. Wells with medium to high decline rates would be screened out.

As the operator had up-to-date well models, nodal anlysis was performed to study the impact of installing ESP in the wells. Assuming a reasonable increase in watercut, the production improvements were estimated and the wells were shortlisted and ranked in the order of preference. This led to a list of top five candidate wells. Detailed technical and commercial evaluations were performed on the top five candidates. Risk factors such as a shorter ESP run life, abnormal increase in water-cut, other reservoir

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risks such as impact on offset production were applied and a risk-based economic evaluation was completed for the short-listed candidates. A risked techno-commercial decision process was used to arrive at the two final well candidates.

Modeling of Expected Benefits

The objective of this de-bottlenecking project is to realize production increase from all the wells, apart from the benefit to be gained by installing ESP in two wells. Prior to the project execution the production benefits were estimated by modeling as follows:

Wells

ESP well models were built starting with the calibrated models of gas lifted wells. Nodal analysis was performed for the ESP case. This gave the risked uplift for the ESP producers.

Network

The impact of the system benefits are best stuidied with the help of a network model. The operator is maintaining fully calibrated network models for the Falah field that incorporates the wells and the associated surface equipment and pipelines. The gas lifted wells in the network model were replaced with the ESP wells. Results of optimization runs performed using the network model were used to estimate the production increase due to network benefits (mainly due to reduced flowing wellhead pressures).

The network model optimization runs also indicated the resultant gas lift header pressures to be expected at each of the Falah platforms.

Further gas-lift optimization work

The candidates which have the potential to improve the operating depths using the increased gas lift header pressure were short listed. This would be a future opportunity and therefore the production uplift from this work was not included in the justification for the ESP project.

Implementation and Field Results

The GL to ESP conversion project was approved based on combined benefit from the wells and the network and implemented. The results of the project were excellent and turned out to be better than the conservative modeling estimates. These are summarized in Table 2 and Table 3.

Post-ESP Projects

Gas lift has been redesigned in a few of the wells selected for deeper lifting. This has further improved well performance and field production. Additional projects have been implemented in the field with the objective of further improving the gas lift header pressure at Falah. This involved modifications in the gas lift supply system from the SWFateh field. This has helped to further de-bottleneck the system.

Conclusions

The ESPs have removed part of the bottleneck in the system, causing significant decrease in production system pressure and increase in gas lift supply pressure.

The system benefits have been more significant than the production benefits from the candidate wells. This has allowed further optimization of the field.

The well candidate selection played a vital role for the success of this project.

Excellent inter-displine communication was maintained amongst the production, reservoir and workover engineering teams. Keeping the operations and operations support personnel in the communication loop was really beneficial. These have played crucial roles in the successful and timely implementation of the project.

A decision and risk analysis incorporating the reservoir knowledge and other uncertainties helped to minimize the risks associated with the project.

The results from this project confirm that the overall benefits of any optimization exercise should always be evaluated at the system level.

SPE 126681 7

Nomenclature BOPD Barrels of oil/day

BFPD Barrels of fluid/day

CFU Compact Floatation Unit

DRA Drag reducing agent

ESP Electric submersible pump

FWHP Flowing wellhead pressure

FBHP Flowing bottom-hole pressure

GL Gas Lift

GLR Gas-liquid ratio

GOR Gas-oil ratio

GVF Gas Volume Fraction

HP High pressure

IGLR Injected gas-liquid ratio

IGOR Injected gas-oil ratio

LP Low pressure

MPP Multi-phase pump

PI Productivity Index

TGLR Total gas-liquid ratio

VFD Variable Frequency Drive

References

1. Brown, K. E., et al.: The Technology of Artificial Lift Methods Volume 2b, Petroleum Publishing Co., Tulsa, Oklahoma, 1980.

2. Lea, James F., Texas Tech University: Artificial Lift Selection, SPE Production Handbook.

3. Lea, James F. and Nickens, Henry V.: Selection of Artificial Lift, paper SPE 52157 presented at the 1999 SPE Mid-Continent Operations Symposium, held in Oklahoma City, Oklahoma, March 28-31, 1999.

4. Brown, K. E., et al.: The Technology of Artificial Lift Methods Volume 2a, PenWell Publishing Co., Tulsa, Oklahoma, 1980.

5. Economides, M. J., et al.: Petroleum Production Systems, Prentice Hall PTR, New Jersey, 1994.

6. Adebari, Adeola: Evaluation of Multiphase pumps for debottlenecking a Gas Lifted Production System (Case Study: Dubai Petroleum Falah Field), M. Sc., Petroleum Engineering Project Report, 2007/2008, Institute of Petroleum Engineering, Heriot-Watt University.

7. Ketait, Reem: Impact of removing produced water volumes in Falah field Applicability & Benefits of Compact Flotation Unit Pilot Study, University Internship Final Report Fall 2008, Chemical Engineering Dept., Faculty of Engineering, U.A.E. University, Al Ain, U.A.E.

8. Alagba, Tonye: Selection of Suitable well candidates for Gas Lift ESP conversion, Offshore Dubai, M. Sc Petroleum engineering, Project Report, 2006/2007, Institute of Petroleum Engineering, Heriot-Watt University.

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AL

METHOD

OVERALL SYSTEM

EFFICIENCY (%)

PCP 40 - 70

Rod Pump 45 - 60

ESP 35 - 60

Gas Lift 10 - 30

Jet Pump 10 - 30

Hydaulic Piston Pump 45 - 55

Table 1: Artificial Lift System Efficiencies

SYSTEM PARAMETER IMPROVEMENT OBSERVED

Decrease in production separator pressure FB: 30 psi

FA: 15 psi

FC: 10 psi

Increase in gas lift header pressure FB: 120 psi

FACD: 50 psi Table 2: System Pressure Improvements Observed ESTIMATED

PRODUCTION INCREASE

ACHIEVED PRODUCTION INCREASE

REMARKS

From the ESP wells 4% *2.0% * Affected by the sudden increase of water-cut in an offset producer

System Benefits: Production + GL side

3.6% 3.6%

Total 7.6% 5.6%

Table 3: Production Results

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Figure 1: Well Performance Surface (WPS) of a GL well

Figure 2: WPS of a GL well showing GL Injection Pressure Required

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y g y

9000

8000

7000

6000

5000

4000

3000

2000

1000

0

True

Ver

tical

Dep

th (f

t)

3500300025002000150010005000Pressure (psia)

350300250200150100500Temperature (degrees F)

Pressure: Q liq = 3180.208 STB/day, Freq = 58.0 Hz, P start = 200.000 psiaPressure: Q liq = 3205.647 STB/day, Freq = 60.0 Hz, P start = 300.000 psia

Figure 3: VFD Application to handle Increase in FWHP

FD

FCFA

FB

HP Gas LineOil LineLP Gas Line

20 LP Gas, 46040

12 HP Gas, 45962

18 Oil, 45877

SWFatehMainFacilities

12 Oil, 24559

8 HP Gas, 24644

16 LP Gas, 24495

12 Oil, 3714

8 Gas, 3734

Gas Lift pressure very low

Production system pressure very high

Has booster compressor for returning LP gas

FD

FCFA

FB

HP Gas LineOil LineLP Gas Line

20 LP Gas, 46040

12 HP Gas, 45962

18 Oil, 45877

SWFatehMainFacilities

12 Oil, 24559

8 HP Gas, 24644

16 LP Gas, 24495

12 Oil, 3714

8 Gas, 3734

Gas Lift pressure very low

Production system pressure very high

Has booster compressor for returning LP gas

Figure 4: Major Pipelines connecting the Falah Field

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FC LP Wells

FC HP Wells

FC HP Prod Manifold

FC LP Prod Manifold

Production from FD

Production from FA

FA LP Prod Separator

FC HP Prod Separator

FA Pumps

FA Compressor

Oil from FBLiquid To Main Facilities

LP Gas To Main Facilities

LP Gas from FBFB Prod

SeparatorFB Wells

3-Phase FlowLP Gas FlowLiquid Flow

Legend

FC LP Wells

FC HP Wells

FC HP Prod Manifold

FC LP Prod Manifold

Production from FD

Production from FA

FA LP Prod Separator

FC HP Prod Separator

FA Pumps

FA Compressor

Oil from FBLiquid To Main Facilities

LP Gas To Main Facilities

LP Gas from FBFB Prod

SeparatorFB Wells

3-Phase FlowLP Gas FlowLiquid Flow

Legend

FC HP Prod Manifold

FC LP Prod Manifold

Production from FD

Production from FA

FA LP Prod Separator

FC HP Prod Separator

FA Pumps

FA Compressor

Oil from FBLiquid To Main Facilities

LP Gas To Main Facilities

LP Gas from FBFB Prod

SeparatorFB Wells

3-Phase FlowLP Gas FlowLiquid Flow

Legend

Figure 5: Falah Field Production line-up

2000

3000

4000

5000

6000

7000

Ope

ratin

g R

ate

(STB

/day

)

765432Lift gas injection rate (MMSCF/day)

Inside dia. of all well nodes = 4.892 inInside dia. of all well nodes = 3.958 in

Figure 6: Gas Lift response curve for Tubing Upsize Option

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Figure 7: Multi-phase pump Operating Envelope

95

95.5

96

96.5

97

97.5

98

98.5

99

99.5

100

0 50 100 150 200 250 300

Reduction in FWHP, psi

GVF,%

Figure 8: Impact of FWHP on Gas-volume fraction

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0

2000

4000

6000

8000

10000

12000

14000

0 50 100 150 200 250 300

Reduction in FWHP, psi

Shaf

t HP

0.0

5.0

10.0

15.0

20.0

25.0

30.0

35.0

Oil

Gai

n, %

Shaft Power, HP

Oil gain,%

Figure 9: Impact of FWHP on MPP Shaft horse-power

100

125

150

175

200

225

250

275

300

325

350

6/1/2008 7/1/2008 7/31/2008 8/30/2008 9/29/2008 10/29/2008 11/28/2008 12/28/2008

FA Sep. Pressure

FB Sep. Pressure

FC Sep.Press

FB-16 Shut-in for ESP Workover (14-Sep-08)

Both ESP's in service (02-Nov-08)

Well

100

125

150

175

200

225

250

275

300

325

350

6/1/2008 7/1/2008 7/31/2008 8/30/2008 9/29/2008 10/29/2008 11/28/2008 12/28/2008

FA Sep. Pressure

FB Sep. Pressure

FC Sep.Press

FB-16 Shut-in for ESP Workover (14-Sep-08)

Both ESP's in service (02-Nov-08)

Well

Figure 10: Falah separator pressure trend