59241760-espfinalreport

ESPfinal reportsteve23.doc

Max Bough/ Luis M. Sandoval 1 of 2 6/7/2003

___________________________________________

ESP FEASIBILITY STUDY FOR KUROVDAG FIELD

Prepared by: Max Bough (IPM) Revised by: Luis M. Sandoval N.( IPM )



CONTENT

I. HISTORY II. ESP JUSTIFICATION

III. METHODOLOGY (ESP CANDIDATE SELECTION) IV. ADDITIONAL CONSIDERATIONS V. CONCERNS

VI. RISKS VII. RESULTS AND RECOMMENDATIONS

VIII. DESIGNS IX. COST ESTIMATES X. INSTALLATION PROGRAM AND GUIDELINES

XI. ATACHTMENTS



I. HISTORY The Kurovdag field had some ESP installations in the past (around 20-30 in the 90’s) with about 13-14 wells as recently as 2000. Shirvan’s approach was to pump high water -cut high volume wells. According to interviewed field personnel, there were several probable causes for cancellation of the ESP program. The ESP program was discontinued as a result of the following probable reasons: poor management decisions (such as imprudent water handling that became expensive), company’s financial problems at the time and internal politics (most likely cause). The company providing ESP services at the time for Shirvan was Azneft, which charged around $35 per installation on daily basis. The service covered ESP systems completely: completion design, servicing, troubleshooting were all handled by Azneft at its expense. Virtually all ESP-associated risk was handled by this service company. Recently, Schlumberger held a business meeting with Azneft regarding future possibilities of using their services. Given certain assurances, they are willing to work under similar schemes as before. II. ESP JUSTIFICATION Having reviewed the producing potential of the active wells in the field, current installations (Rod Pumps) and previous ESP experience, the Schlumberger team concluded that only introduction of an alternative artificial lift technology in the field will drastically improve field’s production. The current rod pump systems are not well suited for the application: they have a high failure rate due to emulsion/sand problems and are operated under poor engineering practices. All of these results into intensive maintenance, high operational costs and, obviously, in a limited production on beam pupm. A more flexible reliable artificial lift system is needed to improve efficiency, profitability and production in the field. Such systems could be ESPs, PCPs and potentially jet pumps. III. METHODOLOGY (ESP CANDIDATE SELECTION) Extensive criteria have been applied to producing wells to come up with the best 10 candidates (See Table 1 for Criteria). First, all active wells were scanned for current production, water cut, and dynamic fluid levels, which resulted into the pool of 59 wells. Second, the wells were broken down into 3 production tiers and IPR curves were constructed for the first 16 wells. The results indicated that wells with lesser production, higher watercut and lower pressures do not appear very attractive economically, so the first 16 were retained for further study. Third, the wells were re-ranked based on their PI and minimum expectation of incremental oil at Pwf of 500 psi (3.4 MPa) (roughly equivalent to 400 m of fluid column above the upper perf). The top 10 candidates were screened with DCS using geological and reservoir criteria. Finally, all 10 were reviewed with the field geologists and engineers for wellbore conditions. Table 2 and Figure 1 through 3 present the results of the study. Note that the geological and reservoir uncertainties were mitigated in all calculations. In cases where PI computations were affected by lack of data or a range of uncertainties, the most conservative guesses were used to eliminate the risk of overestimation. Similarly, reserve estimates are presented rather conservatively. In addition, uphole potential was often minimized, and in reality should be a higher number.



IV. ADDITIONAL CONSIDERATIONS There are several additional considerations that will be addressed during further development of the ESP project. It is suspected that the most wells in the field have a rather significant skin caused by either drilling in the past or current operating practices. While the presented here results reflect the current operating conditions of the wells, much better deliverability could be expected if the skin damage is remove d. Therefore, the IPM team is actively searching for ways to address this issue (i.e. organic solvents or other products which may be provided by local chemical companies). Finding a solution may yield significant economic benefits for the project. Wellbore cleanout is another issue being studied by the IPM team. It has been observed that some of the perforations in the field were sanded off with the consequent re-completion in the upper zones, avoiding attempts to bail the produced sand. A practice of bailing the produced sand and cleaning the perfs properly may prove an economic project of its own and may also improve expected deliverability of the wells. Cement condition (mechanic & hydraulic ) behind the casing is extremely critical to achieve incremental oil production without an iflux of water, which may be caused by improper cement isolation and channelling from adjacent zones. In additon, appropriate cement isolation will minimize problems with the ESP downhole equipment and extend the lifetime of the installation. Precise knowledge of wellbore configuration in terms of real casing ID clearance is a big issue . Casing collapse and non-standard tubular installation (irregular csg design) are quite common problems in the Kurovdag wells . For that reason dummy runs must be done before any ESP installation. Understanding the flowline configuration along with the appropriate well test data before and after ESP installation are crucial for a good well performance assessment and confirmation of the incremental value incorporated by this type of artificial lift system. Knowing that some formations in Kurovdag Field are susceptible to sand production even with beam pump system, it is recommended to control the speed of the ESP (variable speed drives). This way the inflow of the well could be reduced and the amount of fines controlled to prevent premature problems for ESP subsurface equipment. Utilization of down hole sensors, such as pressure and temperature will be needed to verify data supplied by the Echometer. Such sensors will allow to confirm well P Is. With introduction of ESP lift system, paraffin deposition should slow down along the tubing string due to higher temperatures and flowrates and move to the surface facilities. This issue has to be addressed in more detail with possible chemical treatment and adjustments at the surface.



V. CONCERNS There was some disagreement with the Shirvan field people. Field geologists insist than none of the studied wells would benefit from ESP lift. According to them, any additional drawdown created by ESPs would change the producing regime of the formation, bringing in a lot of sand into the wellbore and killing the well. In addition, several other reasons were brought up such as imprudent usage of reserves with ESP lift (appare ntly ESP are supposed to decrease the final recovery!!!) and low permeability of the aforementioned wells (those are the highest PIs in the field!!!). Instead, they offered a list of wells they want to put on ESPs, which incidentally have 90% and above watercut (in most cases producing from the same sands as chosen by IPM). When asked whether these high watercut wells would have any of the mentioned sand problems, they simply propose staying a sufficient amount of distance from the perfs to let the sand settle. Incidentally, an ESP specialist who worked in Kurovdag extensively in the past says that only few formations gave his ESPs any sand-associated problems such as Apsherons (PS series was said to be manageable). Ultimately, this sand producing theory has to be studied more carefully to have some kind of technical/empirical answer to those claims. The answer just may be Shirvan’s old local mentality of delaying production and accelerating production in high water cut wells to keep them active. VI. RISKS As it was mentioned before, a comprehensive list of criteria was applied to the studied wells trying to filter out any apparent risk associated with ESPs. Nevertheless, there are further studies needed to evaluate potential risks of the following. First is sand production. Sand theories given by Shirvan field geologist are not consistent and are not based on any hard evidence (same as with their GOR estimates). Thus, a more detailed quantitative evaluation of the sand problems involving fluid samples and review of sand production history is required. In addition, ESP local specialists, preferably with an extensive knowledge of the Kurovdag Field, can be a useful source of experience and will help to formulate the required forward plan and mitigate known risks. Second potential risk may be presented by wellbore conditions. The discussed wells were reviewed with the field geologists and were deemed suitable. Nevertheless, a dummy run, preferably following a wellbore clean up, is recommended before running the equipment. Paraffin is another consideration worth mentioning. With introduction of ESP lift, paraffin deposition should slow down along the tubing string due to higher temperatures and flowrates and move to the surface facilities. This issue will be addressed in more detail with possible chemical treatment and adjustments at the surface. A comprehensive risk-weighted decision tree will eventually be constructed to evaluate effects of the potential risk on the expected cash flow in case of ESP installation.



VII. RESULTS AND RECOMMENDATIONS Based on the reserve estimates, expected flowrates and other aforementioned criteria, the following wells deserve further attention and should be considered for further evaluation: 1030, 1045, 1126, 1263, 1220 and 1355. These wells have significant reserves to back up expected high PIs, which range from 8,500 to 44, 000 recoverable reservoir cubic meters (~59,000 – 300,000 stb) and significant uphole potential (See Table 2 and Figure 1 through Figure 3 for reference). Their expected incremental oil deliverability ranges from 5 to 26 tonne/d (~ 38-200 stb/d for assumed Pwf of 500 psi). These wells present a low risk investment from the reservoir and deliverability standpoint, and in the case of successful introduction of ESPs or PCPs should yield significant financial returns. The rest of the wells listed in the report (345, 751, 1181, and 1222) appear unsuitable for ESP application due to a series of reasons, such as a risk of depletion, watering out or limited drainage area (See Table 2 for details). These wells are still decent producers and should be considered for low-cost optimisation with the current lift equipment or other low-cost alternatives. Note, that some of them, specifically 751 and 1181, have decent uphole potential and could be considered for ESP lift if recompleted in the above zones. VIII. DESIGNS Preliminary designs were generated for each of the selected wells to identify the type of downhole and surface equipment required (See attached designs). Note, that at this point there are ranges of uncertainties for such input variables as GOR, gas rates and PI estimates. In addition, well test data have in some case are uncertain. IX. COST ESTIMATES Table 3 summarises ESP costs for benchmarking purposes (Azerbaijan, Russia n and USA made ESPs are compared). At this point, the most attractive ESP vendor would most probably be Azneft. Because of the low cost (possibly ~$35-40/day/well), knowledge of the field and complete service that mitigates the risk for Schlumberger and the client, this company appears as the most likely choice. In addition, this company has experience putting together and running various equipment of local, Russian and Western manufacturing, that gives them extra flexibility in design of the systems. Some contractual assurances would have to be given to Azneft to solidify Shirvan’s and Schlumberger’s commitment.



X. INSTALLATION PROGRAM AND GUIDELINES Below is the outline for ESP program w ith description and important guidelines for ESP installation in the Kurovdag Field. Prior to the job:

• Reconfirm input data for ESP design is accurate • Perform a representative well test prior to ESP installation (to confirm Oil, Water, Gas,

GOR, BSW, API, Fluid level among other parameters). This will serve as a benchmark for ESP performance.

• Design the most adequate E SP system according to the well potential deliberability • Have a written detailed operational program, including roles and responsibilities for SLB

personnel and for the Operator • Obtain agreement and signatures from the corresponding parties • Confirm that pulling unit or work-over rig to be used has adequate personnel, and tools to

execute the job in an efficient and safe way • Confirm that both production and operation people in the field are in the loop and receive

additional production from the well (satellites-Production Areas-Tank Farm) During the job:

• Perfom a coordination meeting with all the personnel involved in the ESP installation • Review the program and clarify doubts (roles & responsibilities) • Confirm that all the required equipment and personnel are available at the well site • Ensure the well is controlled and the required flow barriers are in place (keep control fluid

in surface as a contingency) • POOH existing completion configuration and monitor permanently static fluid level

condition ( avoid kick of the well ). Fill out well with control fluid • Do service for EPM motor and seal section then RIH ESP equipment (Temperature &

Pressure sensors, motor, seal section, pump or gas separator if the last one is required ) • RIH ESP equipment slowly, following manufacturer’s guidelines to protect equipment and

cable • Verify integrity of the ESP power cable at least every 500 m (avoid turning pipe and cable

while RIH ESP). No more than three splices on the cable must be done . • Hang tubing string on tubing hanger and install back pressure valve (BPV) • Remove BOPs to install X-tree • Install Test valve and perform X-tree test for at least 15 minutes • Remove test valve • Make up flow line and connect it to test separator • Perfom hydraulic test on flowline an test separator • Check electric conditions on surface (vent box, transformer, VSD or swithboard) • Prepare surface equipment to receive fluid production (flowline, test separator, satellite.

Hand radios are extremely useful! )



• Set operating parameters on VSD or switchboard • Perform quick coordination meeting just before start up ESP • Start ESP pump and monitor permanently well parameters and ESP performance • Execute a short test approximately six (6) hours before release work over rig or pulling unit

After the job:

• Perform a representative well test (approximately 24 hrs) to get the control fluid or dead fluid displaced by the ESP pump. The following parameters must be collected every 30 minutes to quantify the value added ( incremental production by ESP)

o ESP frequency o ESP motor voltage o ESP amperage ( three phases ) o Down hole Pressure o Down hole temperature o Well head pressure o Casing pressure o Dynamic fluid level o Separator pressure o Separator temperature o Fluid production o Oil production o Water production o Gas production o API gravity o Gas specific gravity o Water gravity

Note: Charts will be a good indication for well evaluation.



XI ATTACHMENTS Table 1: ESP Candidate Selection Criteria Table 2: Summary for Top 10 ESP Candidates Table 3: ESP Vendors and Costs Figure 1: Reserves and Expected Incremental Oil Figure 2: Reserves and Total Expected Oil Figure 3: Reserves and Uphole Potential Attached ESP designs for 6 wells

Table 1: ESP Candidate Selection Criteria

Initial ScreeningProduction HistoryProductivity index ( PI ) or well reservoir fluid deliverabilityWater cut ( BSW ) and GOR

GeologyPerforation history, block details, reservoir boundaries Quality of sands, adjacent producers and production performance of sands Water contacts, water injection

ReservoirOOIP estimates, Cumulative production history, illegal perfs, remaining reservesDrainage area (boundaries), water injection, w. conningCurrent and post production declineUphole Potential

OperationsParafin/asphaltenes production, emulsion problems, sand/fine productionVerification of casing size, condition of casing, cement behind casingWellhead and flowline conditionsTubing condition and availabilitySurface equipment capacity to handle additional volumes Surface facilities to perform well test, additional testing equipmentPower supply system availability to be transmited to ESP motorWellsite conditions (Access road, location)Well deviation

D/Current/ESPESPCandSteveFigures.xls 6/5/2003

Table 2: Summary for Top 10 ESP Candidates

Perfs P Csg P Csg Parafin Pr Estimate Recent FL Mid-Perf

Well Block PA Zone m mm Condition Problems Mpa Above MP, m (m) oil, t/d W, m3/d WC, %

345 BL04 PA01 S PS02 3115-3123 146 good severe 17 1,552 3,119 9.6 3.2 23

751 BL12 PA03 PS04,05,06-09 2154-2275 152 X 127 good no info 14 1,350 2,472 8 6.5 42

1030 BL01 PA01 N PS 01+PS02 2805-2978 146 good severe 23 2,058 2,892 8.6 13.2 62

1045 BL13 PA03 PS08+PS09 2887-2990 146 X 178 good moderate 36 flowing 2,951 15.1 5.4 24

1126 BL10 PA03 PS07+PS08 2820-3025 146 X 168 good no info 25 1,890 2,938 9.3 3.5 25

1181 BL01 PA01 S PS03 2869-2930 146 good moderate 22 1,773 2,899 9.6 18.3 64

1222 BL01 PA01 N PS02+PS03 3023-3093 146 good severe 24 1,954 3,058 12.4 6.9 33

1263 BL13 PA03 PS09+PS10 2856-2936 140 X 146 X 168 good no info 36 flowing 2,896 25 0.3 1

1220 BL01 PA01 N PS 04+06 3094-3328 146 good severe 23 2,210 3,211 24.3 0 01355 BL01 PA01 N PS03+PS04 3046-3308 146 good severe 22 1,862 3,148 11.5 4.4 26

Total Liq Total Oil Uphole P.,

Well m3/d oil, t/d Low Med High Low Med High Rm3

345 25 17.3 7.7 11.0 13.7 0 0 7,800 0 May be close to depletion

751 32 16.7 8.7 11.1 13.4 0 0 5,800 17,800 May be close to depletion, decent uphole sands (>50m)

1030 56 19.3 10.7 12.0 14.1 24,600 40,400 56,000 4,300 Excelent current reserves, little uphole

1045 60 41.2 26.1 31.6 36.0 37,000 44,500 52,000 32,000 Huge reserve potential (up to 120,000 drained by 1045 and 1263 (360 m away). Uphole P > 100m

1126 29 19.6 10.3 22.9 32.1 44,000 55,000 66,000 18,000 Huge reserve potential (up to 100,000 in the block drained only by 1126)

1181 48 15.6 6.0 10.1 14.1 0 0 0 12,500 PS 03 - bad quality, offset producers show water coming in 1181

1222 40 24.4 12.0 14.1 16.4 5,000 7,200 9,400 6,800 Thin sand, limited drainage (wtr), small uphole potential

1263 50 44.6 19.6 23.6 27.0 32,000 39,500 47,000 38,000 Huge reserve potential (up to 120,000 drained by 1045 and 1263 (360 m away). Uphole P > 200m

1220 33 29.3 5.0 7.9 9.6 31,000 36,500 42,000 3,500 Good reserves, low decline

1355 29 19.1 7.6 10.7 14.0 8,400 10,500 12,600 3,400 Ok reserves, little uphole potential

Incr. Oil 3 Est., t/d Remaining Rec Reserves, Rm3

Production March'03

*Expected Performance (Pwf ~ 500 psi (3.4 Mpa))

Comments

D/Current/ESP/ESPCandSteveFigures.xls 6/5/2003

Table 3: ESP Cost Estimates and Benchmarking

VENDOR COST VSD SERVICE REPRESENTATIVE MANUFACTURING NOTES (Complete System), K$ Variable Speed Drive (supervision, repairs, troubleshooting)

Alnas (Russia) 40 K(VSD not available) N/A extra RU (Moscow, Tatarstan) Russia cost includes delivery

Borets (Russia) 28-30 K (35-40 w VSD) available 2003 extra Moscow Russia cost includes delivery

Reda (US) 100-150K (200K w VSD) YES extra $500/hr Moscow Oklahoma/Dubai delivery will cost more

ESP Woodgroup (US) $130-160K (w VSD) YES extra Moscow Dubai delivery will cost 20-30% more

Weatherford (US) 150-200 K (w VSD) YES extra Austria Dubai delivery will cost more

CentrLift (US) 150-200 K (w VSD) YES extra Baku Dubai delivery will cost more

Azneft ESP (Azerbaijan) $35/well/day* N/A included Baku Baku local cost, also can equipment others

Figure 1: Reserves and Expected Minimum Incremental Oil Rates 6/5/2003

Reserves and Initial Increments (ESP Candidates)

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10,000

20,000

30,000

40,000

50,000

60,000

345 751 1030 1045 1126 1181 1222 1263 1220 1355

Wells

Res

erve

s, R

m3

0

10

20

30

40

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Init

ial I

ncr

emen

tal O

il R

ates

, to

nn

e/d

Reserves, Rm3 Initial Incremental Oil Rates, tonne/d

Figure 2: Reserves and Total Minimum Expected Oil Rates 6/5/2003

Reserves and Total Oil Rates Expected (ESP Candidates)

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10,000

20,000

30,000

40,000

50,000

60,000

345 751 1030 1045 1126 1181 1222 1263 1220 1355

Wells

Res

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10

20

30

40

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Init

ial T

ota

l Oil

Rat

es, t

on

ne/

d

Reserves, Rm3 Initial Total Oil Rates, tonne/d

Figure 3: Reserves and Uphole Potential Combined 6/5/2003

Reserves and Uphole Potential (ESP Candidates)

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10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

345 751 1030 1045 1126 1181 1222 1263 1220 1355

Wells

Res

erve

s, R

m3

Reserves, Rm3 Uphole Potential, Rm3

ESP DESIGNS FOR THE BEST SIX CANDIDATES (Curves Attached) WELL 1355 GENERAL DESCRIPTION Company Name: Schlumberger Well Name: 1355 Field Name: Kurovdag Reservoir Name: PS Analyst: Eduardo Escobar D. Calculation Type: Rigorous Design Location: Comments: Date: 06/03/2003

WELLBORE DATA OD Wt ID Rough. Bottom MD Top MD No. in lb/ft in in ft ft Tubing 1 2.875 6.50 2.441 0.0006500 9600.00 Casing 1 5.500 15.50 4.950 0.0006500 10800.00 0.00 Pump Depth, ft: 9600.00 Top of Perfs. or Datum Pt. (MD), ft: 10051.00 Reservoir Temperature, °F: 150.0 Wellhead Temperature, °F: 70.0

SEAL DATA Manufacturer: Reda Series: 325-375 Bearing Type: 325 HL Chamber Selection: PF SB HTM HL Bearing Cap., lb: 3144.5 Operating Thrust Load, lb: 791.1 Maximum Thrust Load, lb: 1190.2 Power Consumption, HP: 0.4

PUMP DATA 1 Manufacturer: Reda Series: 338 Model: A400 Minimum Recommended Rate, Bbl/D: 158.84** Maximum Recommended Rate, Bbl/D: 397.11** Rate at Peak Efficiency, Bbl/D: 208.00** Power at Peak Efficiency, HP: 23.5** Frequency, Hz: 52.0 ** = Corrected for Frequency & Viscosity Number of Stages, : 624 Stages with Free Gas: 624 Additional Stages due to Gas: 0 Viscosity Correction Factors User Entered Rate: 1.000 No Head: 1.000 No Power: 1.000 No Efficiency: 1.000 Design 624 Stages Total Dynamic Head (TDH), ft: 6384.71 6427.15 Surface Rate (O+W), Bbl/D: 300.00 301.04 Avg. Pump Rate (O+G+W), Bbl/D: N/A 345.35 Pump Intake Pressure, psig: 1171.0 1163.1 Operating Power, HP: N/A 40.9 Min. Efficiency, %: N/A 33.6 Pump Derating Derating Factor for Rate, %: 92.0 Derating Factor for Head, %: 92.0 Derating Factor for Power, %: 115.0 Housing Data Hsg. # Hsg. Type Length, ft # of Stages 100 FL 14.80 208 100 FL 14.80 208 100 FL 14.80 208 Total 300 44.40 624 Blank Stages Input: 0 Net Stages in Pump: 62

MOTOR DATA Manufacturer: Reda Series: 375 Type: 87 - Double Name Plate Power, HP: 76.5 Name Plate Frequency, Hz: 60 Name Plate Voltage, Volts: 1500.00 Name Plate Current, Amps: 37.0 Adjust for Motor Slip: Yes Operating Current, Amps: 29.3 Design Frequency, Hz: 52.0 Operating Voltage, Volts: 1300.00 Operating Motor Load, HP: 43.5 Operating Power Factor, frac: 0.611 (@ Design Frequency) Operating Motor Load, : 65.65 Operating Efficiency, %: 74.82 Operating Speed, RPM: 3021 Fluid Velocity, ft/sec: 0.342 Well Fluid Temperature, °F: 146.4 Speed Increase Heating, °F: 0.0 Skin Temperature Rise, °F: 42.0 Harmonic Heating due to VSD, °F: 4.3 Avg. Winding Temp. Rise over Skin, °F: 25.0 Total Winding Temp., °F: 213.4 If Sine Wave Filter is used in VSD operation, Harmonic Heating is zero. Catalog Actual Total Stages 624 624 Slip Stages 0 0 Total Dynamic Head (TDH), ft 6427.15 6381.87 Surface Rate (O+W), Bbl/D 301.04 299.82 Avg. Pump Rate (O+G+W), Bbl/D 345.35 343.95 Pump Intake Pressure, psig 1163.1 1172.3 Operating Power, HP 40.9 40.9 Min. Efficiency, % 33.6 33.8 Operating Speed, RPM 3033 3021

CABLE DATA Manufacturer: Reda Type: Redalead Size: 4 Cu Shape: Round Conductor Type: Solid Max. Cond. Temp., °F: 400.0 Cable Length, ft: 9700.00 Solve for: Surface Voltage Electric Cost, $/kWH: 0.00 Design Freq. Frequency, Hz 52 Conductor Temp., °F 156.3 Max. Allowable Amps, Amps 147.9 Amperage, Amps 29.3 Kilovolt Amper, KVA 73.6 Kilowatts, KW 45.0 Kilowatts, $/mo 0 Surface Voltage, Volts 1452.3 Voltage Drop @ 68.0 °F, Volts 129.5 Voltage Drop @ 150.0 °F BHT, Volts 152.3 Kilowatt Loss, KW 4.7 Cost of Voltage Loss, $/mo 0 Required Motor Voltage, Volts 1300.0 Downhole Voltage at Motor, Volts 1300.0 In-rush Motor Voltage Drop, Volts 609.0 Motor Startup Voltage, Volts 843.2 Startup/Operating Ratio, ratio 0.6

WELL 1220 GENERAL DESCRIPTION Company Name: Schlumberger Well Name: 1220 Field Name: Kurovdag Reservoir Name: PS 04/05 Analyst: Eduardo Escobar D. Calculation Type: Rigorous Design Location: Comments: Date: 06/03/2003


SEAL DATA Manufacturer: Reda Series: 325-375 Bearing Type: 325 HL Chamber Selection: PF SB HTM HL Bearing Cap., lb: 3285.9 Operating Thrust Load, lb: 876.1 Maximum Thrust Load, lb: 1301.6 Power Consumption, HP: 0.4

PUMP DATA 1 Manufacturer: Reda Series: 338 Model: A400 Minimum Recommended Rate, Bbl/D: 167.21** Maximum Recommended Rate, Bbl/D: 418.02** Rate at Peak Efficiency, Bbl/D: 363.00** Power at Peak Efficiency, HP: 49.1** Frequency, Hz: 55.0 Number of Stages, : 624 Stages with Free Gas: 624 Additional Stages due to Gas: 0 Viscosity Correction Factors User Entered Rate: 1.000 No Head: 1.000 No Power: 1.000 No Efficiency: 1.000 Design 624 Stages Total Dynamic Head (TDH), ft: 7469.33 7489.49 Surface Rate (O+W), Bbl/D: 300.00 300.52 Avg. Pump Rate (O+G+W), Bbl/D: N/A 351.35 Pump Intake Pressure, psig: 966.3 963.2 Operating Power, HP: N/A 46.5 Min. Efficiency, %: N/A 33.4 Pump Derating Derating Factor for Rate, %: 92.0 Derating Factor for Head, %: 92.0 Derating Factor for Power, %: 115.0 Housing Data Hsg. # Hsg. Type Length, ft # of 100 FL 14.80 208 100 FL 14.80 208 100 FL 14.80 208 Total 300 44.40 624 Blank Stages Input: 0 Net Stages in Pump: 624

MOTOR DATA Manufacturer: Reda Series: 375 Type: 87 - Double Name Plate Power, HP: 67.5 Name Plate Frequency, Hz: 60 Name Plate Voltage, Volts: 990.00 Name Plate Current, Amps: 51.5 Adjust for Motor Slip: Yes Operating Current, Amps: 45.2 Design Frequency, Hz: 55.0 Operating Voltage, Volts: 907.50 Operating Motor Load, HP: 49.1 Operating Power Factor, frac: 0.664 (@ Design Frequency) Operating Motor Load, : 79.36 Operating Efficiency, %: 77.29 Operating Speed, RPM: 3181 Fluid Velocity, ft/sec: 0.340 Well Fluid Temperature, °F: 146.0 Speed Increase Heating, °F: 0.0 Skin Temperature Rise, °F: 51.8 Harmonic Heating due to VSD, °F: 4.3 Avg. Winding Temp. Rise over Skin, °F: 25.0 Total Winding Temp., °F: 222.8 If Sine Wave Filter is used in VSD operation, Harmonic Heating is zero. Catalog Actual Total Stages 624 624 Slip Stages 0 0


WELL 1126 GENERAL DESCRIPTION Company Name: Schlumberger Well Name: 1126 Field Name: Kurovdag Reservoir Name: PS 07/08 Analyst: Eduardo Escobar D. Calculation Type: Rigorous Design Location: Comments: AN550 Date: 06/03/2003

WELLBORE DATA OD Wt ID Rough. Bottom MD Top MD No. in lb/ft in in ft ft Tubing 1 2.875 6.50 2.441 0.0006500 8800.00 Casing 1 5.500 15.50 4.950 0.0006500 10000.00 0.00 Pump Depth, ft: 8800.00 Top of Perfs. or Datum Pt. (MD), ft: 9282.00 Reservoir Temperature, °F: 150.0 Wellhead Temperature, °F: 70.0 Tubing Outflow Correlation: Hagedorn & Brown (1963)

SEAL DATA Manufacturer: Reda Series: 325-375 Bearing Type: 325 HL Chamber Selection: PF SB HTM HL Bearing Cap., lb: 3285.9 Maximum Thrust Load, lb: 3001.0 Power Consumption, HP: 0.6

PUMP DATA 1 Manufacturer: Reda Series: 338 Model: AN550 Minimum Recommended Rate, Bbl/D: 301.50** Maximum Recommended Rate, Bbl/D: 527.62** Rate at Peak Efficiency, Bbl/D: 532.95** Power at Peak Efficiency, HP: 72.1** Frequency, Hz: 57.0 Number of Stages, : 652 Stages with Free Gas: 652 Additional Stages due to Gas: 0 Viscosity Correction Factors User Entered Rate: 1.000 No Head: 1.000 No Power: 1.000 No Efficiency: 1.000 Design 652 Stages Total Dynamic Head (TDH), ft: 7439.40 7515.67 Surface Rate (O+W), Bbl/D: 350.00 352.21 Avg. Pump Rate (O+G+W), Bbl/D: N/A 389.16 Pump Intake Pressure, psig: 780.6 768.1 Operating Power, HP: N/A 75.3 Min. Efficiency, %: N/A 22.4 Pump Derating Derating Factor for Rate, %: 80.0 Derating Factor for Head, %: 80.0 Derating Factor for Power, %: 120.0 Housing Data Hsg. # Hsg. Type Length, ft # of Stages ** = Abrasion Resistant 100 CR** 14.80 163 100 CR** 14.80 163 100 CR** 14.80 163 100 CR** 14.80 163 Total 400 59.20 652 Net Stages in Pump: 652



WELL 1045 GENERAL DESCRIPTION Company Name: Schlumberger Well Name: 1045 Field Name: Kurovdag Reservoir Name: PS 08 Analyst: Eduardo Escobar D. Calculation Type: Rigorous Design Location: Comments: AN550 Date: 06/03/2003


SEAL DATA Manufacturer: Reda Series: 325-375 Bearing Type: 325 STD Chamber Selection: PF SB HTM Bearing Cap., lb: 963.1 Maximum Thrust Load, lb: 513.5 Power Consumption, HP: 0.3

PUMP DATA 1 Manufacturer: Reda Series: 338 Model: AN550 Minimum Recommended Rate, Bbl/D: 306.89** Maximum Recommended Rate, Bbl/D: 537.06** Rate at Peak Efficiency, Bbl/D: 467.50** Power at Peak Efficiency, HP: 10.8** Frequency, Hz: 50.0 ** = Corrected for Frequency & Viscosity Number of Stages, : 145 Stages with Free Gas: 145 Additional Stages due to Gas: 0 Viscosity Correction Factors User Entered Rate: 1.000 No Head: 1.000 No Power: 1.000 No Efficiency: 1.000 Design 145 Stages Total Dynamic Head (TDH), ft: 667.40 573.35 Surface Rate (O+W), Bbl/D: 490.00 485.55 Avg. Pump Rate (O+G+W), Bbl/D: N/A 606.93 Pump Intake Pressure, psig: 2064.3 2088.2 Operating Power, HP: N/A 8.9 Min. Efficiency, %: N/A 29.8 Pump Derating Derating Factor for Rate, %: 92.0 Derating Factor for Head, %: 92.0 Derating Factor for Power, %: 110.0 Housing Data ** = Abrasion Resistant 90 CR** 13.30 145 Total 90 13.30 145 Blank Stages Input: 0 Net Stages in Pump: 145

MOTOR DATA Manufacturer: Reda Series: 375 Type: 87 - Single Name Plate Power, HP: 25.5 Name Plate Frequency, Hz: 60 Name Plate Voltage, Volts: 760.00 Name Plate Current, Amps: 25.0 Adjust for Motor Slip: Yes Operating Current, Amps: 17.7 Design Frequency, Hz: 50.0 Operating Voltage, Volts: 633.33 Operating Motor Load, HP: 11.3 Operating Power Factor, frac: 0.548 (@ Design Frequency) Operating Motor Load, : 53.01 Operating Efficiency, %: 71.44 Operating Speed, RPM: 2919 Fluid Velocity, ft/sec: 0.554 Well Fluid Temperature, °F: 139.0 Speed Increase Heating, °F: 0.0 Skin Temperature Rise, °F: 22.6 Harmonic Heating due to VSD, °F: 4.3 Avg. Winding Temp. Rise over Skin, °F: 25.0 Total Winding Temp., °F: 186.6 If Sine Wave Filter is used in VSD operation, Harmonic Heating is zero. Catalog Actual Total Stages 145 145 Slip Stages 0 0 Total Dynamic Head (TDH), ft 573.35 577.50 Surface Rate (O+W), Bbl/D 485.55 485.64 Avg. Pump Rate (O+G+W), Bbl/D 606.93 607.05 Pump Intake Pressure, psig 2088.2 2087.7 Operating Power, HP 8.9 9.0 Min. Efficiency, % 29.8 23.2 Operating Speed, RPM 2916 2918


WELL 1030 GENERAL DESCRIPTION Company Name: Schlumberger Well Name: 1030 Field Name: Kurovdag Reservoir Name: PS 01/02 Analyst: Eduardo Escobar Calculation Type: Rigorous Design Location: Comments: Date: 06/03/2003


SEAL DATA Manufacturer: Reda Series: 325-375 Bearing Type: 325 HL Chamber Selection: PF SB HTM HL Bearing Cap., lb: 3285.9 Power Consumption, HP: 0.1

PUMP DATA 1 Manufacturer: Reda Series: 338 Model: A400 Minimum Recommended Rate, Bbl/D: 182.59** Maximum Recommended Rate, Bbl/D: 456.48** Rate at Peak Efficiency, Bbl/D: 396.00** Power at Peak Efficiency, HP: 37.1** Frequency, Hz: 60.0 ** = Corrected for Frequency & Viscosity Number of Stages, : 363 Stages with Free Gas: 363 Additional Stages due to Gas: 0 Viscosity Correction Factors User Entered Rate: 1.000 No Head: 1.000 No Power: 1.000 No Efficiency: 1.000 Design 363 Stages Total Dynamic Head (TDH), ft: 5239.77 5235.88 Surface Rate (O+W), Bbl/D: 360.00 359.67 Avg. Pump Rate (O+G+W), Bbl/D: N/A 379.38 Pump Intake Pressure, psig: 1135.9 1137.6 Operating Power, HP: N/A 39.1 Min. Efficiency, %: N/A 35.6 Pump Derating Derating Factor for Rate, %: 92.0 Derating Factor for Head, %: 92.0 Derating Factor for Power, %: 110.0 Housing Data NO HOUSINGS SELECTED

MOTOR DATA Manufacturer: Reda Series: 375 Type: 87 - Double Name Plate Power, HP: 51.0 Name Plate Frequency, Hz: 60 Name Plate Voltage, Volts: 1260.00 Name Plate Current, Amps: 30.0 Adjust for Motor Slip: Yes Operating Current, Amps: 27.2 Design Frequency, Hz: 60.0 Operating Voltage, Volts: 1260.00 Operating Motor Load, HP: 42.7 Operating Power Factor, frac: 0.678 (@ Design Frequency) Operating Motor Load, : 83.72 Operating Efficiency, %: 77.99 Operating Speed, RPM: 3473 Fluid Velocity, ft/sec: 0.410 Well Fluid Temperature, °F: 145.2 Speed Increase Heating, °F: 0.0 Skin Temperature Rise, °F: 25.4 Harmonic Heating due to VSD, °F: 0.0 Avg. Winding Temp. Rise over Skin, °F: 25.7 Total Winding Temp., °F: 196.3 Catalog Actual Total Stages 363 371 Slip Stages 0 8 Total Dynamic Head (TDH), ft 5235.88 5235.82 Surface Rate (O+W), Bbl/D 359.67 359.56 Avg. Pump Rate (O+G+W), Bbl/D 379.38 379.27 Pump Intake Pressure, psig 1137.6 1138.2 Operating Power, HP 39.1 39.1 Min. Efficiency, % 35.6 35.6 Operating Speed, RPM 3500 3473

CABLE DATA Manufacturer: Type: Size: Shape: Round Conductor Type: Solid Max. Cond. Temp., °F: 0.0 Cable Length, ft: 8800.00 Solve for: Surface Voltage Electric Cost, $/kWH: 0.00 Design Freq. Frequency, Hz 60 Conductor Temp., °F 0.0 Max. Allowable Amps, Amps 0.0 Amperage, Amps 27.2 Kilovolt Amper, KVA 0.0 Kilowatts, KW 0.0 Kilowatts, $/mo 0 Surface Voltage, Volts 0.0 Voltage Drop @ 68.0 °F, Volts 0.0 Voltage Drop @ 150.0 °F BHT, Volts 0.0 Kilowatt Loss, KW 0.0 Cost of Voltage Loss, $/mo 0 Required Motor Voltage, Volts 0.0 Downhole Voltage at Motor, Volts 0.0 In-rush Motor Voltage Drop, Volts 0.0 Motor Startup Voltage, Volts 0.0 Startup/Operating Ratio, ratio 0.0

WELL 751 GENERAL DESCRIPTION Company Name: Schlumberger Well Name: 751 Field Name: Kurovdag Reservoir Name: PS 05 Analyst: Eduardo Escobar D. Calculation Type: Rigorous Design Location: Comments: Date: 06/03/2003


SEAL DATA Manufacturer: Reda Series: 325-375 Bearing Type: 325 STD Chamber Selection: PF SB HTM Bearing Cap., lb: 963.1 Operating Thrust Load, lb: 669.3 Maximum Thrust Load, lb: 1038.6 Power Consumption, HP: 0.3

PUMP DATA 1 Manufacturer: Reda Series: 400 Model: DN440 Minimum Recommended Rate, Bbl/D: 75.93** Maximum Recommended Rate, Bbl/D: 417.63** Rate at Peak Efficiency, Bbl/D: 366.67** Power at Peak Efficiency, HP: 30.8** Frequency, Hz: 50.0 Number of Stages, : 429 Stages with Free Gas: 429 Additional Stages due to Gas: 0 Viscosity Correction Factors User Entered Rate: 1.000 No Head: 1.000 No Power: 1.000 No Efficiency: 1.000 Design 429 Stages Total Dynamic Head (TDH), ft: 5655.92 5606.11 Surface Rate (O+W), Bbl/D: 260.00 258.22 Avg. Pump Rate (O+G+W), Bbl/D: N/A 310.59 Pump Intake Pressure, psig: 557.9 566.0 Operating Power, HP: N/A 30.2 Min. Efficiency, %: N/A 33.1 Pump Derating Derating Factor for Rate, %: 92.0 Derating Factor for Head, %: 92.0 Derating Factor for Power, %: 115.0 Housing Data 13.40 161 90 FL 13.40 161 60 FL 9.20 107 Total 240 36.00 429 Blank Stages Input: 0 Net Stages in Pump: 429



WELL 1355

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Reda 338 A400 / 624 Stgs / 52.0 Hz

Pump Performance (TDH) 1355.sp6

Reg: Authorized User - Schlumberger

Pump Curve at 52.0 Hz Pump Curve at 42.0 Hz Pump Curve at 47.0 Hz Pump Curve at 57.0 Hz Pump Curve at 62.0 Hz Min-Max Optimum Rate Well System Curve Design Point

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Inflow Performance 1355.sp6

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WELL 1220

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Reda 338 A400 / 624 Stgs / 55.0 Hz




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WELL 1126

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Reda 338 AN550 / 652 Stgs / 57.0 Hz




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WELL 1045

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1045



Inflow @ Perfs , Case 2 Inflow @ Perfs , Case 3 Inflow @ Pump , Case 2

Inflow @ Pump , Case 3 Design Point

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Reda 338 AN550 / 145 Stgs / 50.0 Hz



Pump Curve at 50.0 Hz Pump Curve at 40.0 Hz Pump Curve at 45.0 Hz Pump Curve at 55.0 Hz Pump Curve at 60.0 Hz Min-Max Optimum Rate Well System Curve(Truncated) Design Point

WELL 1030

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Reda 338 A400 / 371 Stgs / 60.0 Hz




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WELL 751

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Reda 400 DN440 / 429 Stgs / 50.0 Hz




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