00077660_27 MARZO

Copyright 2002, Society of Petroleum Engineers Inc. This paper was prepared for presentation at the SPE Annual Technical Conference and Exhibition held in San Antonio, Texas, 29 September–2 October 2002. 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, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes 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 where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

Abstract The paper discusses the design and installation of remotely controlled in-situ gas lift in the horizontal well B-4 BH on the Norne subsea field. The importance of proper design i.e.; sizing the valve small enough to avoid high pressure gas from the gas cap flowing back into the oil zone and large enough to optimise lift efficiency within the gas processing capacity is emphasized. Both a numerical and an analytical design analysis approach are presented. Examples of current and predicted well performance with and without gas lift are included.

Introduction Production and injection on the Norne field has resulted in an over-pressured gas cap overlying an under-pressured oil reservoir. This has resulted in the need for artificial lift, especially with increasing water cut (WC). It has also made in-situ gas lift an attractive solution.

This paper discusses the design and installation of remotely controlled in-situ gas lift in the horizontal well B-4 BH on the Norne subsea field.

Current strategy for Norne includes pressuring up the oil reservoir. Process facility constraints coupled with expected reservoir behaviour have dictated a thorough design analysis of the gas-lift valve. The objective being to find a valve size small enough to avoid high pressure gas flowing back into the oil zone and large enough to optimise lift efficiency within the gas processing capacity of the floating production, storage and offloading (FPSO) vessel. With the remotely operated flow control valve in place, the well was cleaned up much faster than expected for the current reservoir and well conditions at Norne.

As expected, the horizontal well B-4 BH initially produced approximately 6000 Sm3/d of water free oil with no gas lift. Seven months later (March 2002) the water cut had increased to 33%. Liquid production with no gas lift was 5065 Sm3/d and marginally more (5160 Sm3/d) with a limited amount of gas lift (60 kSm3/d).

Examples of current and predicted well performance with and without gas lift are presented.

Field Description The Norne field (Fig. 1) was discovered1 in 1991 and put on production in November 1997. It is the northern most producing field on the Norwegian Continental Shelf; 200 km off shore Norway in approximately 380 m water depth. The field is developed with 5 subsea templates (3 for production and 2 for injection) connected to a FPSO vessel. Each template has 4 well slots giving a total of 20 available slots. Currently 12 are used for oil production, 6 for water injection and 2 for gas injection. Daily production is currently 33 000 Sm3/d limited by the gas processing capacity.

The Norne field is part of a horst structure, and the hydrocarbons are located in sandstone formations of Lower and Middle Jurassic age of generally good reservoir quality. The hydrocarbon column starts at about 2525 m mean sea level and is 135 m thick with a 110 m oil column and an overlying gas cap (Fig. 2). In-place volumes are estimated to 157 MSm3 of oil and 29 GSm3 of gas (including both gas cap and associated gas). Recoverable oil is estimated to 84 MSm3.

The structure is relatively flat and the reservoir consists of four formations: Garn, Ile, Tofte and Tilje. The Garn and Ile formations are separated by the tight Not shale. Based on pressure data from the exploration wells, the Not shale was expected to be non-sealing locally by major faults, providing reservoir communication between the Garn formation and the underlying formations. However, production history has proven this assumption to be wrong. In other words, the Not shale is sealing across the whole field.

The original drainage strategy comprised both gas- and water drive. Assuming a gravity stable displacement of both the gas and the water contacts, the producers were placed horizontally in the middle of the Ile oil zone. Hence, gas was injected into the Garn formation, resulting in an increase in pressure from initially 270 bars to 300 bars (Fig. 3).

SPE 77660

Remotely Controlled In-Situ Gas Lift on the Norne Subsea Field Ferid T. Al-Kasim, Synøve Tevik, Knut Arne Jakobsen, Statoil ASA, Yula Tang, SPE, Scandpower A/S, Younes Jalali, SPE, Schlumberger

2 F. AL-KASIM, S. TEVIK, K. JAKOBSEN, Y. TANG, Y. JALALI SPE 77660

Simultaneous production from the Ile and Tofte producers resulted in depletion of the reservoir from 270 bars to 220 bars (Fig. 3). I.e. the Not formation has proven to hold a pressure differential of at least 80 bars.

This situation could not continue, considering both rock strength (potential sand production) and lift capabilities. Therefore, the injection strategy was altered a year after production start-up. Both gas and water have since been injected deep, i.e. below or just above the original oil-water contact (OWC). In addition to altering the injection strategy, the new wells are designed to be more robust with respect to water cut, by placing horizontal drainage sections at different elevations above the OWC (Fig. 2). The Garn Formation is still over-pressured while the pressure in Ile/Tofte has as per today increased from 220 bars to about 240 bars.

Problem Definition Full field reservoir simulations show that circulation of water is necessary to obtain a good recovery factor for the Norne Field. The most critical parameter to fulfill this drainage strategy is pressure support. With the current reservoir pressure it is not possible to lift wells with water cuts higher than about 60% (Fig. 4). In the full field simulation model the problem is solved by massive water injection (maximum 54 000 Sm3/d). With the predicted injection schedule the reservoir pressure in Ile/Tofte will increase to above 320 bars in year 2004. At this reservoir pressure the producers are able to lift even very high water cut levels. Until then, some sort of artificial lift is required to maintain a high production rate and restart high water cut wells after shutdowns.

There is a concern whether it is possible to accomplish the predicted injection schedule. As per today the water injection rate is 48 000 Sm3/d (about 6000 Sm3/d lower than predicted). As a consequence, the increase in reservoir pressure is behind schedule and the need for artificial lift has become even more important.

An important factor to consider when selecting artificial lift solution for Norne, is the constraining gas processing capacity of the FPSO.

Problem Solution Being a subsea development already in place, electrical submersible pumps, conventional gas lift and other artificial lift options were found either too expensive or too ineffective. In-situ gas lift however, could utilize the over-pressured gas cap and allow gas influx into the wellbore to help lift the wellbore fluids to surface. Due to the gas processing capacity constraints of the FPSO and the changing reservoir conditions, it had to be possible to remotely control the in-situ gas lift. First of all, it would not be needed initially, but after some time, when the water cut increased. Secondly, once it was needed it had to be possible to adjust the amount of gas throughput according to the changing reservoir conditions and the gas processing capacity.

The solution was a remotely operated hydraulic 5 ½” wireline retrievable gas lift valve with 6 adjustable positions

(0, 20, 40, 60, 80 and 100% opening). Similar systems have been installed elsewhere with success2.

A quick-look evaluation of the potential for artificial lift was tested in the numerical full field reservoir simulator by manipulating the vertical lift performance curves. The results showed a significant potential for increased oil production rate by use of artificial lift (Fig. 5). Based on these results it was decided to proceed with more detailed design analysis of the remotely controlled in-situ gas lift system for the horizontal producer, 6608/10-B-4 BH.

Gas Lift Valve Design There are essentially four choices for the particular mandrel size of this valve; slot widths of 1/16”, 2/16”, 3/16”, or 4/16”. The valve has two slots (at 180°) with a fixed effective height of 1”. The design objective is to find the optimal slot width; small enough to avoid high pressure gas flowing back into the oil zone, and large enough to optimise lift performance within the gas processing capacity of the FPSO. Being a subsea installation it is costly to retrieve and change the gas lift valve even if it is wireline retrievable. Therefore, it was important to choose the correct slot width the first time.

Two design approaches were chosen, one based on nodal analysis and the other based on numerical simulation. Nodal Analysis Approach

The nodal analysis approach was chosen to have an alternative method to the simulation approach and to be able to investigate well and gas lift performance in more detail for specific scenarios. The choke valve had to be designed so that optimum gas lift gas rates could enter the tubing for the various operating scenarios foreseen.

The gas was to be taken from the Garn formation., which was expected to have a fairly constant pressure of 280 to 290 bars during the time period of interest (Fig. 3). The producing formations are Middle and Upper Ile with reservoir pressures increasing from 245 bars initially to a maximum of 320 bars in 2004. When the Ile reservoir pressure exceeds approximately 300 bars the flowing tubing pressure at gas lift valve depth becomes too high to allow gas influx from the Garn formation. At this reservoir pressure the well flows naturally for most water cuts. Therefore, the nodal analysis approach focused on the years 2001, 2002 and 2003 only.

A commercial wellbore hydraulics program was used with input parameters from the planned B-4 BH well and neighbouring wells. A PI of approximately 220 Sm3/d/bar was required to match the predicted initial liquid rate of 6000 Sm3/d without gas lift. The gas lift was modeled by choosing the No friction loss in annulus and fixed depth of injection options. A series of wellbore hydraulics cases with varying water cuts and gas lift injection rates were then run for the predicted conditions in years 2001, 2002 and 2003. The main reasons for this were:

1. To make sensitivity plots of liquid production rate vs. gas lift injection rate for various water cuts in order to find optimum gas lift injection rates (Fig. 6 - 8).

SPE 77660 REMOTELY CONTROLLED IN-SITU GAS LIFT ON THE NORNE SUBSEA FIELD 3

2. Generate solution points to use as input to the quick look matching option where the corresponding orifice diameter and pressure drop across the valve could be calculated.

The quick look matching option was then used, firstly to

check the feasibility of the gas lift system and secondly to adjust the orifice diameter to match the flowing tubing pressure at valve depth and available gas cap pressure in Garn. A small draw down of 2 - 3 bars was assumed for the gas inflow from Garn, based on field experience.

The quick look matching option requires a casing head pressure at which the gas lift gas normally is provided. This value was chosen to give a corresponding casing pressure at valve depth equal to the Garn pressure minus 2-3 bars.

The following scenarios were chosen:

1. 2001 with an Ile pressure of 245 bars and 30% WC. The likelihood of cutting water the first half-year of production was assumed small. Never the less, this would be one of the extremes that the choke should be designed to handle should early water breakthrough occur or the Ile pressure not increase as rapidly as anticipated.

2. 2002 with an Ile pressure of 270 bars and 60% WC. According to Fig. 15 most of the year would pass with no water production. At the end of the year however, a rapid increase in WC was expected that peaked off at about 60%. Therefore, a WC of 60% was chosen.

3. 2003 with an Ile pressure of 290 bars and 85% WC. This is probably the last year where gas influx is possible. Fig. 15 indicates WCs between 60% and 85% during this time period. A WC of 85% was chosen since it represented the upper extreme.

From the sensitivity plots (Fig. 6 - 8) it can be seen that gas

lift injection rates up to 300 kSm3/d is adequate for all scenarios. Also, having in mind that several high GOR wells are choked back due to the gas processing capacity constraints on the FPSO, the most common operating range for the gas lift gas influx would be between 50 and 200 kSm3/d.

A tabulation of the results for all scenarios is shown in Table 1.

Scenario Liquid

rate (Sm3/d)

Gas lift injection Rate (kSm3/d)

Delta P across gas lift valve (bar)

Calculated orifice diameter (1/64”)

2001 30%WC P Ile=245 bar P Garn=290 bar

5330 5440 5559 5598

50 100 200 300

73.3 74.0 75.2 75.5

10.2 14.4 20.3 25.0

2002 60% WC P Ile=270 bar P Garn=280 bar

5622 5862 6118 6237

50 100 200 300

40.3 41.2 42.3 43.2

11.5 16.2 22.8 27.8

2003 85% WC P Ile=290 bar P Garn=280 bar

5121 5759 6340 6579

50 100 200 300

14.5 19.9 23.1 24.3

14.5 19.0 26.0 31.5

Table 1. Norne well B-4 BH Nodal analysis results. Table 1 shows that the greatest amount of choking is

required initially (year 2001) when the Garn pressure is 290 bars and the Ile pressure only 245 bars. A gas influx of 100 kSm3/d is in the wellbore hydraulics program achieved with an orifice opening of 14/64". Corresponding delta P across the valve is 74 bars. The calculated orifice openings should only be regarded as indicative as a different choke model may better represent the actual gas lift valve.

We also see that as the Ile pressure increases relative to the Garn pressure the amount of choking decreases. Late 2003 when expected WC is 85%, 100 - 200 kSm3/d gas lift gas influx is obtained with a delta P of 20 - 23 bars. Corresponding choke openings are 19/64” and 26/64” respectively.

The chosen gas lift valve depth at top Garn perforations (565 m measured depth and 48 m true vertical depth above the Ile perforations) appears to be optimal for lifting the well during normal flowing conditions. Given sufficient injection pressure it is generally beneficial to place the gas lift valve as deep as possible. However, this depth may be too deep to unload the well during startup, as the static tubing pressure at valve depth may be too high compared to the available casing pressure at valve depth. For well B-4 BH this condition will occur sometime during year 2003 when the Garn pressure is 280 bar and the Ile pressure reaches 285 bars. At this point in time the static tubing pressure at specified valve depth equals the casing pressure and no influx of gas is possible any more. However, the bottom hole pressure is now high enough to lift the well without any gas lift unloading. As tubing pressure at valve depth decreases due to the draw down from production, gas influx can take place and the well can benefit from gas lift. That is, until the Ile pressure reaches about 300 bars and the flowing tubing pressure at valve depth becomes too high to allow gas influx from Garn.

Fig. 9 is a plot of orifice opening area vs. gas lift injection rates for the scenarios in Table 1. Included in the same plot is also the operating range (with the fixed positions indicated) for the 4 slot widths to choose from. As can be seen, choosing a too wide slot gives too high gas lift injection rates and


limited choke positions in the area of interest. The smallest slot width (1/16”) was chosen. The 1/16” slot gives maximum flexibility in the lower gas lift injection rate-range and will at maximum opening give gas lift injection rates of 310, 250 and 190 kSm3/d respectively for reservoir pressures 245, 270 and 290 bars. Numerical Simulation Approach A numerical reservoir model was built which consisted of non-adjacent gas and oil formations. Multi-segment wellbore module was used to model the completion geometry and flow characteristics.

Vertical flow performance for two-phase flow was generated for the tubing pressure gradient to link the flow from the reservoir/completion to the surface.

The reservoir simulation was run for a period of 1500 days. Gas lift is initiated after 200 days. Reservoir and aquifer parameters were tuned to match the performance expected by the full field model.

Different cases were run to study the effect of various gas lift scenarios on the well performance and cumulative oil production.

Fig. 10 presents the cumulative oil production and range of valve pressure drop versus the gas injection rate. The gas injection rate yielding maximum oil production is in the neighborhood of 250 kSm3/d. This gas throughput, however, might be on the high side from the viewpoint of surface gas handling capacity.

Fig. 11-13 show the performance of the 1/4”, 1/8”, and 1/16” gas lift valves. The shaded rectangular area is the operating region based on the ratio of the valve upstream and downstream pressures, and the gas throughput yielding maximum cumulative oil production. The objective is to choose a slot width that permits the valve to operate at the 40% or 60% position for the required gas throughput. This way if less or more gas is required, then the lower and higher openings can be used. These results show that the 1/16” width slot is the appropriate valve design. The results also show the following:

1. Gas throughput by gas lift has a marked effect on cumulative oil production.

2. Gas lift lessens the bottomhole pressure and prolongs the production with higher liquid flow rate.

3. Due to initial high oil rate and associated gas from the oil zone, there is no need to use gas-lift from initial production. In the model gas lift is initiated 200 days after start-up.

4. If pressure drop through the gas-lift valve is too small, i.e., inadequate choking, the high-pressure gas zone will suppress the oil zone and back flow occurs. Oppositely, if there is excessive choking, there will not be adequate lift.

5. Optimal valve slot width of 1/16” was determined based on feasible surface gas handling capacity

Gas Lift Valve Installation The 7” Subsea horizontal X-mas tree system had to be modified to accept the remotely operated in-situ gas lift solution. Normally the Norne X-mas trees are equipped with two penetrators; one hydraulic for the downhole safety valve and one electrical for the downhole temperature and pressure gauge. A third penetrator had to be included for the hydraulic control of the gas lift valve.

The Tubing Hanger also, had to be modified to allow another hydraulic feed through. The Subsea Control module was updated to accept and control the gas lift valve. The hydraulic surface pressure at Norne is supplied at 340 bars during normal operations. A special production Packer with feed through application for control lines was installed. The production packer is retrievable so the polished bore receptacle could be omitted from the completion string. A Full Bore Isolation Valve (FBIV) was included in the production string to avoid interventions when setting the production packer. This FBIV is operated by pressure cycling the tubing. An illustration of the well completion can be seen in Fig. 14.

Prior to perforating the well, a loss circulation material pill of 1.27 specific gravity (SG) was spotted across the Ile and Garn Formations. The overbalance during perforation was 70 bars in Ile and 22 bars in Garn. During running in hole, the 7” production tubing was filled with 0.82 SG base oil from the FBIV and up.

Due to depleted reservoir over the years, it has been a challenge to achieve necessary under-balance to cleanup the wells for kill fluid. Different solutions, such as base-oil and Nitrogen have been used to get the sufficient under-balance. Some wells have been displaced to nitrogen down to approx. 1000 m MD. For well B-4 BH, the gas lift solution combined with the FBIV allowed us to complete the well and get it on stream 3 to 4 days earlier than normally expected for Norne conditions. Thus, saving 3-4 rig days.

Post Installation Well Performance and Predictions After installation and cleanup (August 2001), well B-4 BH was tested to a water-free oil rate of 6128 Sm3/d when produced alone through the flowline to the FPSO. This is in excellent agreement with the predictions. The well started to cut water in September 2001, almost a year earlier than predicted (Fig. 15). By March 2002, the WC reached 33% and an attempt to operate the gas lift valve was made. A malfunction was discovered, as normal operation of the valve was not possible. A full investigation was conducted to try and find the cause of the malfunction, without any conclusive results. However, by applying and holding hydraulic pressure on the gas lift valve, it is possible to partly open it. Unfortunately, it is not possible to open it far enough for it to index into a known position. In other words, we are able to


achieve some gas influx, but do not know at which valve opening.

Fig. 16 shows the nodal analysis gas lift sensitivity plot for the conditions during the March 2002 test. The test points are included and show a good agreement between calculated and measured data. Sensitivity curves for 60% and 85% WCs are also included in Fig. 17 to illustrate the increased effect of gas lift as WC increases.

The March test indicates that it is possible to open the gas lift valve for a gas throughput of approximately 60 kSm3/d. From Table 1, this corresponds to a valve opening of approximately 11/64” or almost 20% (the smallest opening position had the valve been functioning normally). This limited opening will be too small for optimal gas lift performance, when Ile pressure and water cut increases. However, it can still give incremental liquid production rates up to approximately 2000 Sm3/d, for high water cuts and low Ile pressures (Fig. 6-8 and 17).

Believing that the pressure in Ile will increase, it is planned to retrieve the variable opening choke valve and replace it with a fixed opening (permanently open) choke. This will be done as soon as an intervention for other purposes is planned in the well. The fixed opening choke will be designed based on reservoir conditions, operational conditions and predictions at the time. Meanwhile, the well will continue to produce naturally until it is worthwhile to utilize the gas lift throughput that is available (currently 60 kSm3/d).

Despite the limited functionality of the gas lift valve, the potential benefits are clearly demonstrated by the installation in well B-4BH. The Norne licence therefore plans to install the same system in two new wells this year, and probably more in coming years (depends on reservoir conditions). Some modifications however, are made to the valve itself and the installation procedure to minimise the risk of failure.

Conclusions The following conclusions can be drawn from the design, installation and early production experiences from the remotely controlled in-situ gas lift installation in well B-4 BH on the Norne subsea field:

1. Installation of a remotely controlled in-situ gas lift

valve in the subsea well B-4 BH saved 3-4 rig days. 2. Currently, a gas lift rate of 60 kSm3/d is possible

through the gas lift valve, which can give incremental liquid production rates up to approximately 2000 Sm3/d, for certain reservoir conditions.

3. Despite the limited functionality of the gas lift valve, the potential benefits are clearly demonstrated by the installation in well B-4 BH.

4. Two more installations are planned on the Norne field this year and probably more in coming years, depending on reservoir conditions at time.

5. Both the nodal analysis and the numerical design approach concluded that the most appropriate slot width should be 1/16”.

6. Slot width design is very dependent on reservoir conditions and gas processing capacity.

Acknowledgement The authors would like to thank the management of Statoil and Shlumberger for their support and the partners of the Norne licence for their permission to publish this paper. References

1. Steffensen, I. and Karstad, P.I.: “Norne Field Development: Fast Track From Discovery to Production,” SPE 30148, JPT (Apr. 1996) 296.

2. Betancourt, S. et al.: “Natural Gas-Lift: Theory and Practice,” paper SPE 74391 presented at the 2002 SPE International Petroleum Conference and Exhibition in Mexico held in Villahermosa, Mexico, Feb. 10-12.


Fig. 1. Top reservoir – Norne field.

Fig. 2. Cross-section of the Norne field.

Fig. 3. Pressure development in Garn and Ile.

7

29

KILOMETERS

0 1 2

B2

C1

D1B

D-2

C2

F1

B3

E1

B1

C3

F2

E2F3

D3B

E4AE3A

B4B

F4

C4D4

7

29

KILOMETERS

0 1 2

B2

C1

D1B

D-2

C2

F1

B3

E1

B1

C3

F2

E2F3

D3B

E4AE3A

B4B

F4

C4D4

Norne

SW N E

Inje cto r

O ilG as

Inje cto r Inje cto r

Pro duce r with In-s itu Gas -lift

C o nve ntio nal Pro duce rC o nve ntio nal Pro duce rs

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Fig. 4. Inflow vs. outflow curves.

Fig. 5. Oil rate and cumulative production with and without gas lift.

Fig. 6. Sensitivity plot Ile pressure = 245 bar.



Fig. 9. Orifice opening vs. gas lift injection rate.

Inflow vs Outflow - Norne B-4 BH

0

50

100

150

200

250

300

350

400

0 5000 10000 15000

Liquid Rate (Sm3/d)

Dow

nhol

e Pr

essu

re (B

AR

g)

VLP WC=0% VLP WC=60% VLP WC=90%

IPR PIle=245 bar IPR PIle=300 bar IPR PIle=350 bar

Well Oil Rate With Gas LiftWell Oil Rate No Gas LiftCumulative Well Oil Production With Gas LiftCumulative Well Oil Production No Gas Lift

Sensitivity Plot - Norne B-4 BHP Ile=245 BAR

30003500400045005000550060006500700075008000

0 100 200 300 400 500 600

Gas Lift Injection Rate (kSm3/d)

Liqu

id R

ate

(Sm

3/d)

WC=0%

WC=30%

WC=60%

Se ns itivi ty Plot - No r n e B- 4 BHP Ile =27 0 BA R

3 0 0 0

4 0 0 0

5 0 0 0

6 0 0 0

7 0 0 0

8 0 0 0

0 2 00 4 0 0 6 00

Ga s Li ft Inj ec t ion Ra te (k Sm 3/d)

Liqu

id R

ate

(Sm

3/d)

W C= 0 %

W C =3 0%

W C =6 0%

S e n s iti vity P lo t - N or n e B -4 B HP Ile =290 B AR

3 0 0 03 5 0 04 0 0 04 5 0 05 0 0 05 5 0 06 0 0 06 5 0 07 0 0 07 5 0 08 0 0 0

0 2 0 0 4 0 0 6 0 0

G as L ift In je c t io n R ate (k Sm 3/d )

Liqu

id R

ate

(Sm

3/d

W C= 0 %

W C = 6 0 %

W C = 8 5 %

N o rn e B -4 B H G as L ift In jec tio n R ate vs . O rifice A rea

00 .0 5

0 .10 .1 5

0 .20 .2 5

0 .30 .3 5

0 .40 .4 5

0 .5

0 1 0 0 2 0 0 3 0 0 4 0 0 5 0 0

G as L ift Injec tion R a te (k S m 3 /d )

Orific

e Area

(sq.

inch)

P r =24 5 b a rP r =27 0 b a rP r =29 0 b a r1/ 4" s l o t w id t h3/ 16 " s l o t w id t h1/ 8" s l o t w id t h1/ 16 " s l o t w id t h


Fig. 10. Numerical approach cumulative oil production for different gas throughput rates.

Fig. 11. Gas lift valve performance and the operation envelope (1/8” slot width).



0

500

1000

1500

2000

2500

3000

0 500 1000 1500 2000 2500 3000 3500 4000Qg,inj (103SM3/d)

Np (1

03 SM

3 )

0

20

40

60

80

100

120

dp_v

alve (

bar)

Np

dpvalve (at beginning)

dpvalve (at end)

prediction for 1500 daysgas lift from t = 200 day

0

100

200

300

400

500

600

700

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1 1.1Pd/Pu

Qg (1

03 SM

3 /d)

0.20.40.60.81.0

position

slot width: 1/8"(optimal size)

0

200

400

600

800

1000

1200

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1 1.1P d/ P u

0.20.40.60.81.0

position

slot widt h: 1/4"(t o o larg e)

0

50

100

150

200

250

300

350

400

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1 1.1Pd/Pu

Qg (1

03 SM

3 /d)

0.20.40.60.81.0

position

slot width: 1/16"(too small)


Fig. 14. Schematic of well B-4 BH completion.

Fig. 15. Oil rate, cumulative oil production, water cut and gas oil ratio from full field simulations with gas lift.

Fig. 16. Nodal analysis gas lift sensitivity with Mar. test points.

Fig. 17. Same as Fig. 16 with 60% and 85% water cut included.

Well Oil Rate With Gas LiftCum. Oil Prod. With Gas Lift

Well Water Cut With Gas LiftWell GOR With Gas Lift

Ga s Lift S ens itivity Pl ot B- 4 BHP Ile=2 40 bar

50 00

50 50

51 00

51 50

52 00

52 50

53 00

53 50

54 00

54 50

0 1 00 2 0 0 3 00 4 0 0 5 00 6 0 0

Ga s Li ft Inj . Ra te (1000 Sm 3/ d)

Liqu

ide

Rate

(Sm

3/d)

L iqu id R a te , 33% W C:

M a r ch 2002 te s tpo in t s

Gas Lift Sensitivity Plot B-4 BHP Ile=240 bar

0

1000

2000

3000

4000

5000

6000

0 100 200 300 400 500 600

Gas Lift Inj. Rate (1000Sm3/d)

Liqu

ide

Rat

e (S

m3/

d)

Liquid Rate, 33% WC :March 2002 test pointsLiquid Rate, 60% WCLiquid Rate, 85% WC

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00077660_27 MARZO