Nodal Analisis.doc

Nodal System Analysis Report: Artificial Lift Application in Field

TM 6005. Advanced Production Engineering

Zulmi Ramadhana

22212078

ITB: Master Degree of Petroleum Engineering

Daftar isi

Daftar isi................................................................................................................................................ . 1

Pendahuluan ....................................................................................................................................... .. 2

Informasi umum buatan sistem mengangkat .......................................................................................... 2

Reservoir Pressure and Well Productivity ............................................................................ 2

Reservoir Fluid ............................................................................................................................ . 2

Advatages and Disadvantages of Some Types of Artificial Lift ...................................... 3

Production Before Artificial Lift .............................................................................................................. 5

Gas Lift Application ............................................................................................................................. ... 6

Gas Avaibility ................................................................................................................................ 6

Facility Constraints ..................................................................................................................... 7

Sucker Rod Pump Application .............................................................................................................. 26

Surface Pumping Unit Selection ............................................................................................ 26

Sucker Rod String Selection ................................................................................................... 26

Subsurface Pump Selection .................................................................................................... 27

Pump Displacement ................................................................................................................. 28

Plunger Movements (Ups and Downs) ................................................................................ 28

Pump Intake Curves ................................................................................................................. 30

Installation .................................................................................................................................. . 32

Electric Submersible Pump Application ................................................................................................. 46

Pump Performance Curve ....................................................................................................... 46

Pump Intake Curves ................................................................................................................. 48

Rate Selection ......................................................................................................................... ... 49

Installation .................................................................................................................................. . 50

Comparison of Production by Artificial Lift ............................................................................................ 64

Conclusions ........................................................................................................................................ . 66

1

Pendahuluan

Reservoar deskripsi dan tabung pemilihan bidang ini telah dijelaskan dalam pekerjaan

rumah # 4. Dalam laporan ini, akan menyimpulkan pilihan artificial lift dan studi kinerja

masing-masing artificial lift yang akan diterapkan di bidang ini dalam rangka

mengoptimalkan produksi masing-masing setiap sumur. artificial lift yang akan dibahas

adalah gas lifting, sucker rod pumping, dan submersible pumping. Berdasarkan analisis nodal

untuk setiap sistem, kinerja produksi lebih lanjut juga akan dijelaskan dan berapa banyak

tambahan produksi cairan dari setiap baik menghasilkan oleh setiap angkat buatan.

Dalam laporan ini, akan menggambarkan artificial lift yang akan diterapkan dan

perbandingan untuk setiap artificial lift, dan akan menyeleksi artificial lift terbaik yang akan

diterapkan dalam bidang ini

Syste Informasi umum sistem Artificial Lift

Umumnya, dalam artificial lift desain insinyur tersebut adalah dihadapkan dengan

pencocokan kendala fasilitas, artificial lift capability, reservoir tekanan dan sumur

produktivitas jadi bahwa suatu efisien instalasi mengangkat hasil.

Reservoir tekanan dan sumur produktivitas

Di antara faktor yang paling penting untuk dipertimbangkan adalah reservoir

tekanan dan sumur produktivitas Jika producing rate vs producing bottom hole pressure

diplot, inflow performance relationship (IPR) akan terjadi. Ketika tubing performance curve

(TPC) digariskan dalam grafik yang sama dengan (IPR) kurva, laju produksi optimal akan

menentukan.

Kombinasi dari IPR dan tubing performanca curve, yang juga dikenal sebagai system

Nodal System Analysis. Dengan menggunakan NSA, kinerja dari setiap sumur di bawah

berbagai kondisi untuk setiap artificial lift dapat diprediksi, dan dengan menggunakan future

IPR, prediksi masa depan dari kinerja sumur juga dapat dianalisis.

Pemilihan artificial lift, akan dianggap sebagai laju produksi tambahan yang dapat

dihasilkan oleh masing-masing artificial lift.Tingkat produksi addional ini diperkirakan dengan

menggunakan NSA kinerja suur di masa depan

Fluida Reservoir

The characteristics of the reservoir fluid must also be considered. Sand production can

be very detrimental to some types if lift. The producing gas-liquid ratio (GLR) is very

2

important to the lift designer. Free gas at pump intake is a significant problem to all of the

pumping lift methods but is beneficial for gas lift, which simply supplements the lift energy

already containe in the producing gas.

Advatages and Disadvantages of Some Types of Artificial Lift

Gas Lift

Advatages

Gas lift is the best artificial lift method for handling sand or solid materials.

Deviated or crooked holes can be gas lifted with minor lift problems.

Well maintenance/intervention can be easily done as gas lift permits the use of such

equipment.

Gas lift has a low profile, not too much surface equipment adjustment to support gas

lift installation.

Well subsurface equipment is relatively inexpensive and repair and maintenance of

this subsurface is normally low.

Installation of gas lift is compatible woth subsurface safety valves and other surface

equipment.

Disadvantages

Relatively high back pressure may seriouslu restrict production.

Gas lift is relatively inefficient, often resulting in large capital investements and high

energy operating costs.

Adequate gas supply is needed throughout the life of project. In addition,there must

be enough gas for easy start-ups.

Increasing water cut increases the flowing bottom hole pressure with a fixed gas lift

pressure.

Operation and maintenance of compressors can be expensive.

The difficulty increased when lifting low gravity crude oil.

Sucker Rod Pump

Sucker rod pumping systems are the oldest and most widely used type of artificial lift

for oil wells. Sucker rod pumping systems should be considered for new, low volume stripper

wells because operating personnel are usually familiar with these mechanically simple

3

systems and inexperienced operating personnel operate this type of equipment with greater

efectiveness than other types of artificial lift.

Sucker rod systems should also considered for lifting moderate volumes from shallow

depths and small volumes from intermediate depths. Most of the parts of the sucker rod

pumping system are manufactured to meet existing standards, which established by

theAmerican Petroleum Institute (API). The sucker rod string, parts of the pump and

unanchored tubing continously subjected to fatigue. Therefore, the system must be more

efficiently protetected against corrosion than any other lift system to insure long equipment

life.

Sucker rod pumping systems are incompatible for crooked holes. The ability of sucker rod

pumping systems to lift sand is limited. Paraffin and scale can interfere with the efficient operation

of sucker rod pumping system.

If the gas-liquid separation capacity of the tubing-casing annulus is too low, or if the

annulus is not used efficiently, and the pump is not designed and operated properly, the pump will

operate inefficiently and tend to gas lock. And other disadvantage of this systems is that the

polished rod stuffing box can leak. However, if the proper design and operating criteria are

considered and followed, those disadvantages can be minimized.

Electric Submersible Pump

Advantages

Adaptable to highly deviated wells (up to 80o)

Adaptable to required subsurface wellheads 6’ apart for maximum surface location

density

Permit use of minimum space for subsurface controls and associated production

facilities

Quit, safe and sanitary for acceptable operations in an offshore and

environmentally conscious area.

Generally considered a high volume pump - provides for increased volumes and

water cuts brought on by pressure maintenance and secondary recovery operations

Permits placing well production even while drilling and working over wells in

immidiate vicinity.

Disadvatages

4

Will tolerate only minimal percents of solids production

Costly pulling operations to correct downhole failures

While on a downhole failure, there is a loss of poduction during the time well is

covered by drilling operations in immediate vicinity

Not particularly adaptable to low volumes - les than 150 b/d gross

Long life of ESP equipment is required to keep production economical with high

water cuts, approximately greater than 90%.

Production Before Artificial Lift

Before artificial lift is applied in this field, Table 1 is shown the result of production

without any support from artificial lift, produced with tubing ID 2.992 inch. It can be seen

that during 1000 days, is the plateu production as the surface facility constraint (separator

capacity) is 10,000 b/d. . But, at t= 2500 days the production is declined below 50% of the

separator capacity. And at t= 3000 days, the production is only 22.45% of separator capacity.

Table 1. Production Before Artificial Lift

tqL (BPD)

Well 1 Well 2 Well 3Total Field Separator

Well 4 Well 5 Production (BPD) Efficiency (%) 0.00 2800 2400 800 2000 2000 10000 1001.37 2800 2400 800 2000 2000 10000 1002.74 2800 2400 800 2000 2000 10000 1004.11 2710 2345 775 1720 1630 9180 91.85.48 2075 1835 530 1310 1400 7150 71.56.85 1660 1350 320 652 880 4862 48.628.22 1200.00 549.00 150.00 176.16 170.00 2245.16 22.45

In Table 2, shown the cumulative production that resulted for 3000 days. As the

reservoir is supported by weak water drive, assumed that recovery factor (RF) is 40%. Based

on this assumption, the amount of original oil in place can be determine by using below

equation:

Where:

N = reserve (MMSTB)

Np = cumulative production (MMSTB)

5

Table 2. Cumulative Production Each Well for 3000 days

tNp (STB)

Well 1 Well 2 Well 3 Well 4 Well 5 0.00 0 0 0 0 01.37 1400000 1200000 400000 1000000 10000002.74 2800000 2400000 800000 2000000 20000004.11 4177500 3586250 1193750 2930000 29075005.48 5373750 4631250 1520000 3687500 36650006.85 6307500 5427500 1732500 4178000 42350008.22 7022500 5902250 1850000 4290500 4497500

The total of cumulative production from each well is 23.56 MMSTB, by using equation 1,

the amount of oil reserve of this field is 58.91 MMSTB.

Artificial will be applied in each well in order to get more production and maintain the

production for some period.,In this report, will discussed the additional production by using 3

artificial lift method, as below:

1. Gas Lift

2. Sucker Rod Pump (SRP)

3. Electric Submersible Pump (ESP)

Each artificial lift will start not in the same time, depends on each system and the

puposes. For example, pumping system (SRP and ESP) can not start when there is a huge

amount of produced gas. They will be installed before the produced gas is not high.

Next explaination will discussed the application of each artificial lift in detailed. Later the

additional production from each artificial lift will be compared in order to select the type of

artificial lift to be applied in this field.

Gas Lift Application

Gas Avaibility The avaibility of the gas in the field will be a significant factor for choosing gas lift

system. In this report, assumed that there is no limitation in gas avaibility. But there are some

conditions.

In this field, there is a produced gas from the production wells. This gas will be used for

injected gas lift, the excess gas will be put on sale (will not discuss on detailed, as only the

6

focus is on gas for lifting). But if the gas from production wells can not meet the need of

injected gas for lifting, assumed that there is a near gas well that drilled espcially for gas lift

purpose.

As the time goes on, the produced gas from each well will be increased. The system

need to be made to separate gas for sale and gas for lifting purpose. The important thing is,

the amount of gas for gas lift system have to be fixed, or the injected gas plus the gas released

from the reservoir will dominate the colomn of the production well. If this occur, the oil can

not be produced. That is why the amount of gas that need to be injected for each well have to

be controlled.

Facility Constraints From Table 1, after 2500 days of production water produce for each well are relatively

in small amount (below 50%). The produce gas which is shown in GLR data are varied,

Well#1 and Well# 3 have a small amount of gas released from the reservoir liquid. Well# 2,

Well# 4, and Well# 5 have a great amount of produced gas.

Each well performance at t = 2500 days (based on separator constraint) will be

described in the next explaination. The well performance will be analyze with the sensitivity of

Inflow Performance Relationship (IPR) to Tubing Performance Curve (TPC) under various total

Gas Liquid Ratio (GLR).

7

1000.00

900.00

800.00

700.00

600.00

500.00

400.00

300.00

200.00

100.00

0.00 0 500 1000 1500 2000 2500 3000 3500 4000

qL (bbl/d)

IPR GLR=512.4473 GLR=1500 GLR=2500 GLR=3500

Figure 1. Performance of Well 1 Under Gas Lift with Various Gas Injection Rate

1000.00

900.00

800.00

700.00

600.00

500.00

400.00

300.00

200.00

100.00

0.00 0 200 400 600 8001000120014001600180020002200240026002800

qL (bbl/d)



8

700.00

600.00

500.00

400.00

300.00

200.00

100.00

0.00 0 100 200 300 400 500 600 700 800 900 1000 1100 1200

qL (bbl/d)

IPR GLR=223.661 GLR=400

GLR=500 GLR=700 GLR=1000


700.00

600.00

500.00

400.00

300.00

200.00

100.00

0.00 0 100200300400500600 700 800 9001000110012001300140015001600

qL (bbl/d)



9

800.00

700.00

600.00

500.00

400.00

300.00

200.00

100.00

0.00 0 100200300400500600 700 800 90010001100120013001400150016001700180019002000

qL (bbl/d)



The optimum gas injection rate is based on the gas lift performance curve for each well.

after the optimum gas injection rate is determined, the master plot of gas lift will be made.

This master plot is used in order to know the avaibility of gas in the field is meet the need of

gas that will be injected for each well. Figure 6 - 10, are the gas lift performace curve for

each well.

10

1900

1850

1800

1750

1700

1650

1600 0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400

GLR (SCF/STB)

Figure 6. GLPC for Well#1 @t=2500 days

Table 3. Result of Gas Injection for Well 1 @t=2500 days

GLR (SCF/STB) qL (b/d) Pwf (psi)512.45 1660 590

1000 1800 5531500 1850 5452000 860 5402500 1861 538

ResultGLR opt 1135 SCF/STBGLR inj 622.55269 SCF/STBqg inj 1133045.9 scfd

1.1330459 MMSCFD

11

1430

1420

1410

1400

1390

1380

1370

1360

1350 0 500 1000 1500 2000 2500 3000 3500 4000

GLR (SCF/STB)

Figure 7. GLPC for Well#2@t=2500 days



2000 1400 4783000 1420 4734000 1425 471

ResultGLR opt 2380 SCF/STBGLR inj 1281.5263 SCF/STB

qg inj 1806952.1 scfd1.8069521 MMSCFD

12

600

500

400

300

200

100

0 0 500 1000 1500 2000 2500 3000 3500 4000 4500

GLR (SCF/STB)




400 377 458500 403 448700 435 431

1000 470 4192000 505 3993000 525 3904000 530 388


0.208512 MMSCFD

13

710

700

690

680

670

660

650

640 0 1000 2000 3000 4000 5000 6000

GLR (SCF/STB)



GLR (SCF/STB) qL (b/d) Pwf (psi)1379 650 4012000 672 3903000 688 3854000 695 3825000 698 3816000 695 383


0.729688 MMSCFD

14

950

940

930

920

910

900

890

880 0 500 1000 1500 2000 2500 3000 3500 4000

GLR (SCF/STB)




2000 935 4433000 943 4404000 930 442


0.816723 MMSCFD

Table 8. Optimum and Maximum Gas Injection Rate

Well

12345

Total

Opt. qg,inj Max. Qg,injMMSCFD MMSCFD

1.1330 2.76681.8070 4.13460.2085 2.00150.7297 2.52780.8167 1.48704.6949 12.9177

15

From each gas lift performance curve (GLPC) the optimum and maximum gas injection

rate for each well can be determine, so that the total gas injection that need need for gas lift for

this field can be determine too. Then, to distribute the amount of gas from compressor to each

well can be determine by using the master plot of gas lift, the detailed of master plot of gas lift

will discussed as follow.

Convert gas lift performace curve to gas injection rate vs. liquid production rate. Read

the liquid production every 0.25 MMCFD increase gas injection rate to determine the slope,

do this for each well. Then plot gas injection rate vs slope for all wells in the same graph

(Master Plot 1).

From slope 50 to 0, read the total gas injection rate then plot total gas injection rate per

slope vs slope (Master Plot 2). From this plot, determine the optimum gas injection rate and

see the slope. Go back to Master Plot 1, from the optimum slope in Master Plot 2 see the gas

injection rate for each well. These gas injection rate is the amount of gas injection that will be

distribute for each well for gas lifting. Next are the convert GLPC (qg vs qL) foreach well.

1900

1850

1800

1750

1700

1650

1600 0 0.5 1 1.5 2 2.5 3

qg (MMSCFD)

Figure 11. GLPC for Well#1

16

1450

1430

1410

1390

1370

1350 0 0.5 1 1.5 2 2.5 3 3.5 4 4.5

qg (MMSCFD)


550

500

450

400

350

300

250 0 0.5 1 1.5 2

qg (MMSCFD)


17

700

690

680

670

660

650

640 0 0.5 1 1.5 2 2.5 3 3.5

qg (MMSCFD)


950

940

930

920

910

900

890

880 0 0.5 1 1.5 2 2.5 3

qg (MMSCFD)


18

100

90

80

70

60

50

40

30

20

10

0 0 0.5 1 1.5 2 2.5 3 3.5 4 4.5

-10 qg (MMSCFD)

Well# 1 Well# 2 Well# 3 Well# 4 Well# 5

Figure 16. Master Plot 1

Table 9. Gas Injection Rate each Well for every 5-increase Slope

SlopeQg,inj (MMSCFD) @Well

1 2 3 4Qg,inj for Qg,inj for

5 all Well Well# 1,3&5 50 1.45 0 0.89 0.38 0.74 3.46 3.0845 1.49 0 1.12 0.5 0.8 3.91 3.4140 1.58 0 1.25 0.6 0.88 4.31 3.7135 1.29 0.3 1.31 0.73 0.92 4.55 3.5230 2 1.12 1.38 0.82 0.97 6.29 4.3525 2.6 1.32 1.43 0.9 1.03 7.28 5.0620 2.12 1.55 1.64 1 1.1 7.41 4.8615 2.2 2.1 1.79 1.28 1.2 8.57 5.1910 2.32 2.37 1.87 1.42 1.3 9.28 5.49

5 2.6 3.15 1.93 2.36 1.45 11.49 5.980 2.767 4 2 2.5 1.75 13.017 6.517

19

60

50

40

30

20

10

0 0 0.5 1 1.5 2 2.5 3 3.5 4 4.5 5 5.5 6 6.5 7 7.5 8 8.5 9 9.5 10

qg (MMSCFS)

Figure 17. Master Plot 2 for All Well

Table 10. Gas Injection Rate for Each Well and Resulted Liquid Production

From Master Plot 2: gas injection rate optimum (MMSCFD) 4.7slope 34.3

well

12345

total

gas injection productionrate (MMSCFD) rate (b/d)

1.68 1846.5600.35 1373.7321.31 394.0800.75 681.6340.91 937.153

5.0 5233.159

Setelah mempelajari semua faktor yang mempengaruhi aplikasi gas lift untuk bidang

ini. Ini menunjukkan bahwa, tidak semua sumur dapat menghasilkan secara efektif dengan

menggunakan gas lift sebagai dukungan. Beberapa sumur telah memiliki jumlah besar

reservoir gas, sehingga untuk menginstal gas lift di sumur ini tidak akan membawa manfaat

sama sekali, sebagai aliran di dalam sumur akan didominasi oleh gas dan cairan yang tersisa

di dalamnya. Sumur yang cocok untuk gas lift adalah well # 1, # 3 well, dan well # 5.

20

60

50

40

30

20

10

0 0 0.5 1 1.5 2 2.5 3 3.5 4 4.5 5 5.5 6 6.5 7 7.5 8 8.5 9 9.5 10

qg (MMSCFD)

Figure 18. Master Plot 2 for Well 1, 3, and 5

Table 11. Gas Injection Rate for Each Well and Resulted Liquid Production

From Master Plot 2: gas injection rate optimum (MMSCFD) 4.3slope 30

well gas injection rate production(MMSCFD) rate (b/d)

1 2 1852.8403 1.38 439.1745 0.97 938.746

total 4.35 3230.760

Gas yang akan digunakan untuk lifting gas akan berasal dari gas yang dihasilkan

dari sumur produksi yang lain. Tidak perlu untuk mengebor sumur gas tambahan atau

gas transportasi dari lapangan terdekat, sebagai gas yang tersedia di bidang ini.

Kelebihan gas (dari reservoir dan tidak digunakan sebagai lifting gas) akan mengangkut

ke titik penjualan.

Untuk t = 3000 hari, total GLR yang akan digunakan adalah total GLR setelah

injeksi gas lift. Lakukan analisis GLPC yang sama untuk t = 3000 hari untuk

menentukan laju injeksi gas dan tingkat produksi cair yang dihasilkan.

21

1300

1290

1280

1270

1260

1250

1240

1230

1220 0 500 1000 1500 2000 2500 3000

GLR (SCF/STB)



GLR (SCF/STB) qL (b/d) Pwf (psi)1135 1225 5001500 1270 4902000 1285 4822500 1290 4803000 1290 480

ResultGLR opt 1550 SCF/STBGLR inj 415 SCF/STBqg inj 528295 scfd

0.528295 MMSCFD

1300

1250

1200 0 0.5 1 1.5 2 2.5

qg (MMSCFD)


22

350

300

250

200

150

100

50

0 0 500 1000 1500 2000 2500 3000

qg (MMSCFD)



GLR (SCF/STB) qL (b/d) Pwf (psi)703 223 401

1000 249 3932000 283 3883000 301 360


0.15522 MMSCFD

350

300

250

200 0 0.25 0.5 0.75

qg (MMSCFD)


23

944

942

940

938

936

934

932

930

928 0 500 1000 1500 2000 2500 3000 3500 4000 4500



GLR (SCF/STB) qL (b/d) Pwf (psi)2000 935 4433000 943 4404000 930 442


0.5649 MMSCFD

950

940

930

920 0 0.5 1 1.5 2

qg (MMSCFD)


24

15

14

13

12

11

10

9

8

7

6

5

4

3

2

1

0

-1 0 0.2 0.4 0.6 0.8 1 1.2 1.4 1.6 1.8 2 2.2

-2 qg (MMSCFD)

Well# 1 Well# 3 Well# 5

Figure 26. Master Plot 1 at t= 3000 days for Well 1, 3, and 5

15

14

13

12

11

10

9 8

7

6

5

4

3

2

1

0 0 0.5 1 1.5 2 2.5 3 3.5 4 4.5 5 5.5 6 6.5 7 7.5 8 8.5 9 9.5 10

qg (MMSCFD)

Figure 27. Master Plot 2 at t= 3000 days for Well 1, 3, and 5

25

Table 15. Gas Injection Rate for Each Well and Resulted Liquid Production at t= 3000 days

From Master Plot 2: gas injection rate optimum (MMSCFD) 2.5slope 11

well

135

total

gas injection rate production(MMSCFD) rate (b/d)

1.17 1285.4280.7 302.6090.6 942.597

2.47 2530.634

Sucker Rod Pump Application

Surface Pumping Unit Selection

Semua jenis balok memompa Unit geomteries terbagi dalam dua kelas yang berbeda:

1. Kelas I sistem tuas, (Unit Konvensional)

2. Kelas III sistem tuas (Air Seimbang dan Lufkin Mark II)

Pilihan unit pompa akan didasarkan pada parameter baik, kondisi operasi,

biaya dan avaibility. Sebuah unit konvensional mungkin dipilih karena personil lapangan yang akrab

dengan itu, sedangkan ukuran yang relatif kecil, berat badan rendah dan gaya inersia dan gemetar rendah dari

Unit udara skor akan membuat menjadi pilihan yang baik untuk sebuah situs luar negeri atau permukaan tertutup lainnya

lokasi.

Dalam bidang ini, unit pompa permukaan yang akan digunakan adalah unit konvensional sebagai konvensional lebih umum daripada yang lain dan sumur di bidang ini hanya <3.000 ft.

Sucker Rod String Selection

Sucker Rod string adalah sistem getaran kompleks yang mengirimkan energi dari

peralatan permukaan ke pompa bawah permukaan. Tapered batang string digunakan untuk

meminimalkan berat total batang tali.

Tegangan maksimum di bagian atas rod string adalah puncak dipoles beban batang

(PPRL) dibagi dengan luas penampang batang atas. The minimum stres di jalan atas adalah

minimum dipoles batang oad (MPRL) dibagi dengan luas penampang batang atas.

Hubungan tegangan maksimum dan minimum adalah:

()

Dimana: T = kekuatan tarik minimum untuk batang (90.000 psi untuk API Grade C

batang

Dan 115.000 psi untuk API Kelas D batang)

26

SF = a service factor that depends on the type of rods and the operating conditions.

Table 16. List of Approximate Values of SF

Service API C API D

Noncorrosive 1.00 1.00

Salt Water 0.65 0.90

Hydrogen Sulfide 0.50 0.70

In this field will used Noncorrosive service with API Grade C rods.

Subsurface Pump Selection

Komponen utama dari pompa bawah permukaan adalah:

1. Barel Kerja, terhubung ke pipa

2. Plunger, terhubung ke batang pengisap

3. Katup Travelling, bagian dari perakitan plunger

4. Berdiri katup, yang terletak di bagian bawah laras bekerja

Di bagian bawah dari pompa, terhubung ke barel bekerja, biasanya ada

jangkar gas berlubang, yang allowa cairan formasi untuk memisahkan sebelum masuk pompa. Itu

juga mengarahkan banyak gas gratis ke casing-tabung anulus dan ditingkatkan pompa

efisiensi.

Pompa batang ditarik dapat dibagi menjadi tiga tipe dasar:

1. Pompa Tubing

2. Pompa Insert / batang

3. Pompa tubingLaras kerja pompa pipa merupakan bagian integral dari string tubing. Ini adalah menguntungkan dalam menyediakan untuk pembangunan pompa paling kuat, dan

memungkinkan diameter plunger maksimal menjadi hanya sedikit lebih kecil dari diameter pipa,

sehingga memaksimalkan volume cairan yang dapat dipompa. Kerugian dari pompa tabung

adalah bahwa seluruh tubing string yang harus ditarik untuk melayani barel kerja dan lainnya pompa hardware. Pompa Rod adalah kebalikan dari pompa pipa, untuk memiliki

pekerjaan pelayanan tidak diperlukan untuk menarik seluruh string, tetapi volume yang dapat dipompa kurang

dari tabung pompa.

27

Table 17. Maximum Pump Size Inside Production Tubing

Pump Type

Tubing one-piece, thin-wall barrel (TW)

Tubing one-piece, heavy-wall barrel (TH)

Rod one-piece, thin-wall barrel (RW)

Rod one-piece, heavy-wall barrel (RH)

Rod liner barrel (RL)

Tubing Size (in)

1.900 2 3/8 2 7/8 3.500

1 ½ 1 ¾ 2 ¼ 2 ¾

1 ½ 1 ¾ 2 ¼ 2 ¾

- 1 ¾ 2 ¼ 2 ¾

1 ¼ 1 ½ 2 2 ½

1 1/16 1 ¼ 1 ¾ 2 ¼

Pump Displacement

Pompa perpindahan teoritis diberikan:

Dimana: V = perpindahan pompa teoritis, b / d Ap = luas pompa plunger, in2 Sp = plunger stroke yang efektif, dalam N = kecepatan pompa, spm Hal ini berlaku jika konstan pompa didefinisikan sebagai:

The efektif plunger stroke diperkirakan 80% dari stroke permukaan. Persamaan b dapat ditulis sebagai:

Dimana S adalah stroke permukaan dalam inci. Untuk kasus ketika memompa luids sedikit kompresibel seperti cairan, dapat dianggap konstan dan sama dengan QSC ratw permukaan.

Plunger Movements (Ups and Downs)

Ketika bergerak turun, plunger bergerak turun di dekat bagian bawah stroke, fluida

bergerak naik melalui katup perjalanan terbuka sementara berat colomn cairan didukung

oleh

katup berdiri, whivh akibatnya dekat. Percepatan penurunan maksimum adalah

diberikan oleh:

28

When the sign plus for conventional units and the minus sign is for air balance or Mark II

units. c/p is the crank-to-pitman ratio.

If the travelling valve closes and standing valve opens at the instant the downward

acceleration is maximum, a force balance at the same instant yields PPRL:

PPRL = (weight of fluid colomn) + (weight of plunger) + (weight of rods) +

(acceleration term) + (friction term) - (upthrust from below on plunger)

The friction and the weight of the plunger not give a very significant effect compared to other

factors. The upthrust from belo on the plunger is the pressure of the produced fluid times the

plunger area. Hence:

Where P3 is the pump intake pressure. The first term on the right-hand side of above equation can

be written as:

The second term is the buoyancy force on the rods, given as:

( )( )Where ρs is the density of the steel (490 lb/ft3). As the API of oil in this field is 35o, the value of

the specific gravity is 0.85. Term 0.1273γf is equal to 0.108. So that the above equation can

expressed as Fb=0.108Wr. PPRL equation can be written as:

When moving up, the plunger is moving up near the bottom of the stroke. The

travelling valve is closed and standing valve is open. The upward acceleration isthe same with

downward acceleration, denoted by α2. But, the minus sign is for conventional units and the plus

sign is for air balance and Mark II units.

The instant upward is maximum, a force balance at the same instant yields MPRL:

MPRL = (weight of rods) + (weight of plunger) - (friction term) - (acceleration term)

- (buoyancy term)

As before, the weight of the plunger and friction term will be neglected. The buoyancy force

is given before. So MPRL equation can be written as:

29

Pump Intake Curves

Consideration of predicting intake curves for beam pumps are:

1. Pumping only liquid

2. Pumping gas with the liquid, assumed that all the associated gas is pumped with the

liquid

Pump intake pressure equation, from equation 10 can be written as:

[ ]PPRL and α1 relationship can be described by subtitute from equation 1, can be written as:

Subtitute αmin from :

Recall equation 11, the equation is written as:

α2 is upward accelaration, recall equation 5 by changing α1 to α2, then the above equation can be

written as :

( )So that, equation 13 can be written as:

( )After some algebraic manipulation, equation 12 now can be written as:

[ ][ ]

Note that, the plus sign is for conventional units and the minus sign is for air balanced or

Mark II units.

SN2 in equation 17, can be written as:

From equation 4, equation 18 can be written as:

30

Substituting equation 17 into equation 19 gives:

[ ][ ]

To simplify, equation 17 can be written as:

Where:

[ ][ ]

SN2 also can be written as:

Then,

Where:

[ ]

Note that,

, and

The minimum allowable intake pressure (or the maximum allowable production rate) can

be determined from the condition that the maximum stress in the top rod must not exceed the

allowable stress for the grade of the rods. The expression is given belo:

[( ) ]( )Inequallity in equation 28 gives the minimum allowable value of SN2 which, if subtituted in

equation 17, gives the minimum allowable intake pressure.

31

The procedure for constructing intake curves is given as follows:

1. Decide on the type of surface pumping unit.

2. Select a pump size, a sucker-rod string, and a c/p ratio.

3. Calculate Ap, K, and Wr. Determine γf, then calculate Wf.

4. Calculate a and b, as functions of N. And calculate c, as a function os S.

5. Assume various pump speeds and for each of these speeds, calculte b; then plot P3 vs

qsc.

6. Assume stroke lengths and for each of these lengths, calculate c; then plot P3 vs qsc.

7. Plot IPR Curve.

8. Determine the maximum allowable stress for the grade of rods used; then calculate the

minimum allowable value of SN2. Used this value of SN2 to calculate the minimum

allowabe intake pressure. Impose this value of P3 (horizontal line) on the plot prepared

before.

9. Read rates at the intersection of the pump intake curves (the staight line of step 5or the

quadratic curves of step 6) with IPR curve. Read the maximum allowable rate at the

intersection of the minimum allowable intake pressure with the IPR curve.

10. Plot the rate vs S and N. Impose the maximum allowable rate on the same plot.

11. Select a suitable rate.

Installation

The installation of sucker rod pumping is scheduled at t = 1500 days. When the total

liquid production already below the separator capacity and while the gas produced from the

reservoir is not really high tp prevent the occurance of gas lock (See Table 1).

To determine further production, when the value of length of the stroke (S) at t= 1500

days is already known, calculate the value of P3 (Intake Pressure) and speed of the stroke (N)

by using pressure intake equation that had been mentioned before. The value of this S is the

same for the future production time, until the length of the stroke is no longer capable to lift

the production liquid. When the stroke’s length is not changing, P3 and speed of the stroke are

changing as the watercut is changing by time. To face this situation, the initial value of N can

also be used as constraint, but due to it is easier to change the speed of the pump than change

the stroke’s length everytime.

When the initial stroke’s length is no longer capable, it need to be changed with the

smaller one depends on the pressure intake calculation that willbe done for that time. Here, the

speed of the pump will be very fast.

32

The next explaination will described how to determine the optimum value of S and N for

each well, the future performance of each well under the value of the initial S, and the

capability of the initial S in order to make the well always on production.

Well# 1

Surface pumping unit: ConventionalPump type: RWPlunger Diameter (in): 2.5c/p: 0.33Service Factor: 1Rod No 86

Rod String Size % rod /100 Wr (lb/ft)1 40.6% 0.96831

7/8 39.7% 0.9468453/4 19.7% 0.469845

Ap (in^2): 4.90625K (pump constant): 0.7280875Wr (Rod's weght, lbs): 2584.77237SG oil: 0.84984985SG fluida: 0.899160328Wf (fluid's weight, lbs): 5730.545459Atr (in^2): 0.785T (grade C, psi) 90000b (function of N): 0.021898364 Nc (function of S): 0.037595694 /Sa (psi) -2226.394318

33

1500 1400 1300 1200 1100 1000

900 800 700 600 500 400 300 200 100

0 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000

qL (b/d)

IPR N=0 N=20 N=30 N=40 N=50

N=60 N=80 N=90 S=1 S=5 S=15

S=25 S=35 S=45 S=55 S=70

Figure 28. IPR vs Intake Pressure for Various S & N Well#1 at t= 1500 days

90 70

80 60

7050

60

50 40

40 30

3020

20

10 10

0 00 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000

qL (b/d)

N S

Figure 29. Optimum Liquid Production Rate of Well#1 at t= 1500 days

The above graphis is plot of the resulted production liquid under various S and N, qL vs

S and qL vs N based on NSA in Figure 28 and plotted in the same graph. But, keep in mind

34

that there is also choke constraint, so there is limit of qL, it can be produce above the limit of

choke contraint.

When the value of S at t=1500 days is known, calculate the value for future N and P3 by

using pressure intake equation. In Table 18, shown the result of production by using SRP in

Well# 1. It can be seen that (see Figure 30) the value of initial stroke’s length that resulted from

Figure 29 is capable for production until t= 3000 days.

1500

1400 1300 1200 1100 1000

900 800 700 600 500 400 300 200 100

0 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500

qL (b/d)

IPR 1500 IPR 2000 IPR 2500 IPR 3000

S @t=1500 S @t=2000 S @t=2500 S @t=3000

Figure 30. Performance of Well#1 under the same Stroke’s Length

Table 18. Result of Production using SRP of Well# 1

t (days) Qsc (bpd) S (inch) P3 (psi) N (spm)1500 2080 52.13 893.68 68.52000 2000 52.13 660.15 65.872500 1920 52.13 443.31 63.233000 1850 52.13 271.21 60.93

35

Well# 2



7/8 39.7% 0.9468453/4 19.7% 0.469845

100.0% 2.385Ap (in^2): 4.90625K (pump constant): 0.7280875Wr (Rod's weght, lbs): 2412.454212SG oil: 0.84984985SG fluida: 0.91137095Wf (fluid's weight,lbs): 5421.142001Atr (in^2): 0.785T (grade C, psi) 90000b (function of N): 0.020438473 Nc (function of S): 0.035089314 /S

-a (psi) 2303.163871

36

1400

1200

1000

800

600

400

200

0 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000

qL (b/p)

IPR N=0 N=20 N=30 N=40 N=50

N=60 N=80 N=90 S=1 S=5 S=15

S=25 S=35 S=45 S=55 S=70


100 80

90 70

8060

70

60 50

50 40

40 30

3020

20

10 10

0 00 500 1000 1500 2000 2500 3000 3500 4000 4500

qL (b/p)

N S

Figure 32. Optimum Liquid Production Rate of Well#2 at t= 1500 days

37

1200 1100 1000

900 800 700 600 500 400 300 200 100

0 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000

qL (b/d)

IPR 1500 IPR 2000 IPR 2500 IPR 3000 S= 55


In Figure 33, by using 55 inch of stroke’s length is no longer capable at t= 3000 days. In

order to put the well on production at t= 3000 days, a workover job need to done to replace the

stroke with the smaller one. To determine the new value of S is the same as before. See Figure

34, it can be seen the performance of Well# 2 under the new stroke’s length at t= 3000 days. In

Table 19, shown the result of production using SRP of Well# 2.

650 600 550 500 450 400 350 300 250 200 150 100

50 0

0 200 400 600 800 1000 1200 1400qL (b/d)

IPR 3000 S=30 S=25 S=20 S=15

Figure 34. Performance of Well# 2 at t= 3000 days

38


t (days) Qsc (bpd) S (inch) P3 (psi) N (spm)1500 2180 55 728.81 68.052000 2100 55 519.94 65.552500 2000 55 274.51 62.433000 1067 15 160.65 112.98

Well# 3

Surface pumping unit: ConventionalPump type: Rod Liner BarrelPlunger Diameter (in): 2.25c/p: 0.33Service Factor: 1Rod No 86


7/8 36.0% 0.83343/4 27.1% 0.627365

100.0% 2.315Ap (in^2): 3.9740625K (pump constant): 0.589750875Wr (Rod's weght, lbs): 2159.444733 6366.25SG oil: 0.84984985SG fluida: 0.885230027Wf (fluid's weight, lbs): 4189.010221Atr (in^2): 0.785T (grade C, psi) 90000b (function of N): 0.027884407 Nc (function of S): 0.05910209 /Sa (psi) -3178.300913

39

900 850 800 750 700 650 600 550 500 450 400 350 300 250 200 150 100

50 0

0 200 400 600 800 1000 1200 1400 1600 1800qL (b/p)

IPR N=0 N=20 N=50 N=60 N=75

N=80 N=85 N=90 S=1 S=10 S=15

S=30 S=40 S=50 S=60 S=70


90

88

86

84

82

80

78

76

740 200 400 600

50454035302520151050

800 1000 1200 1400 1600 1800qL (b/p)

N S


40

900

800

700

600

500

400

300

200

100

0 0 200 400 600 800 1000 1200 1400 1600 1800

qL (b/d)

IPR 1500 IPR 2500 S=10 IPR 2000 IPR 3000


In Figure 37, for Well# 3 is produce by using 10 inch of stroke’s length due to choke

constraint of Well# 3 is 800 b/d. By using stroke’s length longer that 10 inch, the resulted

production liquid will be more than 800 b/d. Table 20 shown the result of proction using SRP

of Well# 3.



41

Well# 4



7/8 39.7% 0.9468453/4 19.7% 0.469845

100.0% 2.385Ap (in^2): 4.90625K (pump constant): 0.7280875Wr (Rod's weght, lbs): 2153.97698 5962.5SG oil: 0.84984985SG fluida: 0.92312555Wf (fluid's weight,lbs): 4902.73422Atr (in^2): 0.785T (grade C, psi) 90000b (function of N): 0.01824864 Nc (function of S): 0.03132974 /Sa (psi) -2429.3862

1000 900 800

700 600 500 400 300 200 100

0 0 500 1000 1500 2000 2500 3000 3500 4000

qL (b/p)

IPR N=0 N=20 N=30 N=40 N=50

N=60 N=80 N=90 S=1 S=5 S=15

S=25 S=35 S=45 S=55 S=70

Figure 38. IPR vs Intake Pressure for Various S & N Well#4 at t=1500 days

42

100 80

90 70

8060

70

60 50

50 40

40 30

3020

20

10 10

0 00 500 1000 1500 2000 2500 3000 3500

qL (b/p)

N S


1000

900

800

700

600

500

400

300

200

100

0 0 500 1000 1500 2000 2500 3000 3500 4000

qL (b/d)

IPR 1500 IPR 2000 IPR 2500 IPR 3000 S=35


43

In Figure 40, stroke’s length that used is 35 inch stroke’s length. But it will not capable

anymore after t= 2500 days. 35 inch stroke’s lenght is used at the beginning in order to get a

huge amount of liquid production. Table 21, shown the result of production using SRP of

Well# 3.



Well# 5



7/8 39.7% 0.9468453/4 19.7% 0.469845

100.0% 2.385Ap (in^2): 4.90625K (pump constant): 0.7280875Wr (Rod's weght, lbs): 2498.613291 6916.5SG oil: 0.84984985SG fluida: 0.920548429Wf (fluid's weight,lbs): 5671.294623Atr (in^2): 0.785T (grade C, psi) 90000b (function of N): 0.021168418 Nc (function of S): 0.036342504 /Sa (psi) -2245.32414

44

1000

800

600

400

200

0 0 500 1000 1500 2000 2500 3000 3500 4000

qL (B/P)

IPR N=0 N=20 N=30 N=40 N=50

N=60 N=80 N=90 S=1 S=5 S=15

S=25 S=35 S=45 S=55 S=70


100 80

90 70

8060

70

60 50

50 40

40 30

3020

20

10 10

0 00 500 1000 1500 2000 2500 3000 3500 4000

qL (b/p)

N S


45

1100

1000

900

800

700

600

500

400

300

200

100

0 0 500 1000 1500 2000 2500 3000 3500 4000

qL (b/d)

IPR 1500 IPR 2000 IPR 2500 IPR 3000 S= 55 S=30 S=5




Electric Submersible Pump Application

Pump Performance Curve

The performance curves of a submersible electrical pum represent the variation of head,

horsepower, and efficiency with capacuty. Capacity refers to the volume of the produced

fluid rate, which may include free and/or dissolved gas. The head (in feet per stage)

developed by centrifugal pump is the sane regardless of the type os specific gravity of the fluid

pumped. But when converting this head pressure, it must be multiplied by the gradient of the

fluid in question. Therefore, the following can be stated:

(pressure developed by pump) = (head per stage) x (gradient of fluid) x (number of

stages)

46

When pumping gas with the fluid, the capacity and consequently, the head per stage as

well as the pressure of the fluid is elevated from the intake value P3 to discharge value P2.

Thus, the above equation can ve written as follows:

Where:

dP = the differential pressure developed by the pump, psi

h = the head per stage, ft/stage

Gf = the gradient of the pumped fluid, psi/ft

d(St) = the differential number of stage

h and Gf are the functions of the capacity V. The gradient of the fluid at any pressure

and temperature is given by:

but:

where W is the weight of the capacity V at any pressure and temperature, which is equal to the

weight at standard condition. Hence:

Subtituting equation 3 to 2, gives:

( )ρsc is the weight of 1 bbl of liquid plus pumped gas (per 1 bbl of liquid) at standard condition,

or:

where ρgsc is the density of gas (in lb/scf) at standard conditions.

Subtituting equation 4 to 1, gives:

( )The number of stages is obtained by integrating the above equation between the intake

and the discharge pressures:

∫ ( )∫( )∫

47

Horsepower. The pump performance curves give the horsepower per stage based on a

fluid specific gravity equal to 1.0. This horsepower must be multiplied by the specific gravity of

the fluid under consideration. Thus, the following can be stated:

( )The total horsepower requirement is obtained by integrating the above equation

between the intake and the discharge pressure:

∫ ( )∫( )∫

For each pump, there is a capacity range within which the pump performs at near its

peak efficiency. The volume ranges of the selected rate between the intake and the discharge

pressures should, therefore, remain within the efficiency range of the pump. This range, can be

changed by using a variable frequency controller.

Pump Intake Curves

Predicting intake curves for submersible pump is considered for two cases:

1. Pumping only liquid

2. Pumping liquid and gas

Assumed that the pump is set at the bottom of the well and that wellhead pressure and the

tubing size are fixed. For case 2, assumed that all associated gas is pumped with the liquid.

The sensitivity variable seleced is the number of stages.

In this field, case 1 will be used. So that, the nodal analysis will be based on case 1.

Case 2 will not be described in this report.

Since liquid is only slightly compressible, the volume of the production rate can be

considered constant and equal to the surface rate qsc. Hence, the head per stage will also be

constant, and equation 7 can be integrated to give:

( )Solving equation 10 for P3, gives:

( )Equation 9 alsocan be integrated to give:

48

( )Subtituting equation 10 into 12, yields:

Procedures for the preparation of tubing intake curve:

Select a suitable pump as dictated by the casing size and the flow capacity of the

well.

Calculate ρfsc fom equation 33 (GLR=0) and γfsc fom equation 31 (V=qsc).

Assumes various production rates and, for each rate of these rates, do the followings:

a. Read the head per stage from the pump performance curves and calculate the

quantity (ρfsch/808.3141).

b. Determine the required discharge pressure from a pressure gradient correlation.

c. Assume various numbers of stages and, for each of these numbers, calculate the

intake pressure from equation 39.

Plot the intake pressure vs rate for each assumed number of stages on the same

graph as the IPR curve and to the same scale.

Read the rates at the intersection of the pump intake curves with the IPR curve.

For each rate, read the horsepower per stage from the pump performance curves;

then calculate the total horsepower requirement from equation 41.

Plot the rates vs the number of stages and horsepower requirements. Impose the

efficiency range of the pump on the same graph.

Select a suitable rate

Rate Selection

Whether pumping only liquid or pumping liquid with gas, the selected rate must satisfy the

following criteria:

1. Its volume range between the intake and the discharge pressures must remain within

the efficiency range of the pump.

2. It must be economically feasible.

As the number os stages and the production rate increase, the effect of frictio in the

tubing string becomes significant, causing the discharge pressure to increase. As a result, the

gain in the production rate per one stage continues to diminish until it becomes insignificant.

49

Installation

The installation of ESP is scheduled at t = 2000 days. When the total liquid production

already below the separator capacity and while the gas produced from the reservoir is not

really high(See Table 1). All well except Well# 3, will used Pump Curve Performance in

Figure 44, the consideration are based on the choke constraint of each well. Well# 3 will used

Pump Curve Performance in Figure 45.

Figure 44. Pump Performance Curve of 338-1500 Series with Range Q= 1000 - 2000 BPD

and Min. Casing Size 4.5”

50

Figure 45. Pump Performance Curve of 338-550 Series with Range Q= 420 - 700 BPD and

Min. Casing Size 4.5”

Well# 1

Well Data: OD (in): 3.5 γg: 0.8Depth (ft): 3000 γo: 0.85T (F): 200 γL: 0.90SG water: 1.07 Ρsc: (lb/scf): 315.21Water cut (%): 0.2305 Gf (psi/ft): 0.39

Table 23. Calculation for ESP under Various Number of Stages of Well# 1 at t= 2000 days

Q P2 h P3 for assumed # stages100 150 200 250 300 350 400 450 500

2500.00 1075.00 5.10 876.12 776.68 677.24 577.81 478.37 378.93 279.49 180.05 80.61

2250.00 1091.00 8.00 779.03 623.05 467.07 311.09 155.10 -0.88 -156.86 -312.84 -468.83

2000.00 1107.00 10.20 709.24 510.37 311.49 112.61 -86.27 -285.14 -484.02 -682.90 -881.78

1750.00 1125.00 12.00 657.05 423.08 189.10 -44.87 -278.84 -512.82 -746.79 -980.76 -1214.74

1500.00 1144.00 13.80 605.86 336.79 67.72 -201.35 -470.42 -739.49 -1008.56 -1277.63 -1546.70

1250.00 1168.00 15.00 583.07 290.60 -1.87 -294.34 -586.80 -879.27 -1171.74 -1464.21 -1756.67

1000.00 1195.00 16.00 571.07 259.10 -52.86 -364.83 -676.79 -988.76 -1300.72 -1612.69 -1924.65

750.00 1228.00 17.00 565.07 233.61 -97.85 -429.31 -760.78 -1092.24 -1423.70 -1755.17 -2086.63

500.00 1267.00 17.80 572.88 225.82 -121.24 -468.31 -815.37 -1162.43 -1509.49 -1856.55 -2203.61

250.00 1317.00 18.20 607.28 252.42 -102.44 -457.30 -812.16 -1167.02 -1521.88 -1876.74 -2231.60

51

1200.00

1000.00

800.00

600.00

400.00

200.00

0.00 0.00 500.00 1000.00 1500.00 2000.00 2500.00 3000.00 3500.00 4000.00 4500.00

qL (b/d)

IPR 2000 St 150 St 200 St 250 St 300

St 350 St 400 St 450 St 500

Figure 46. Performance of Well# 1 Under Various # of Stages (t=2000 days)

Table 24. From NSA and Pump Performance Curve of Well# 1

St Qp (BPD) hp HP150 2260 0.37 50.73200 2400 0.37 67.64250 2500 0.37 84.55

Efficiency 2550

2500

2450

2400

2350

2300

2250

2200 0 50 100 150 200 250 300

Stages or Horsepower St HP

Figure 47. The Efficiency og Liquid Production Rate and Horsepower of Well# 1

52

Table 25. Result of ESP at t= 2000 days of Well# 1

Result for t= 2000 days

Q 2400 b/dStage 200HP 67.64 HPEfisiensi 32 %

1000.00

900.00

800.00

700.00

600.00

500.00

400.00

300.00

200.00

100.00

0.00 0.00 500.00 1000.00 1500.00 2000.00 2500.00 3000.00 3500.00

qL (b/d)

IPR 2500 St 150 St 200 St 250

Figure 48. Performance of Well# 1 @t= 2500 days

Performance of Well# 1 @t= 3000 days 1000.00

900.00 800.00 700.00 600.00 500.00 400.00 300.00 200.00 100.00

0.00 0.00 500.00 1000.00 1500.00 2000.00 2500.00

qL (b/d)

IPR 3000 St 150 St 200 St 250


53

Table 26. Result of Production with ESP of Well# 1

t (days) Q (b/d) St hp HP2000 2400 200 0.37 67.642500 2220 200 0.37 68.183000 1925 200 0.36 67.36

Well# 2

Well Data:OD (in): 3.5 γg: 0.8Depth (ft): 3000 γo: 0.85T (F): 200 γL: 0.92SG water: 1.07 ρsc (lb/scf): 321.74Water cut (%): 0.3153 Gf (psi/ft): 0.40


Q P2 h100

P3 for assumed # stages

150 200 250 300 350 400 450 500

2500 1058 5.1 855.00 753.50 652.00 550.50 448.99 347.49 245.99 144.49 42.99

2250 1072 8 753.57 594.35 435.13 275.91 116.70 -42.52 -201.74 -360.95 -520.17

2000 1087 10.2 681.00 477.99 274.99 71.99 -131.01 -334.01 -537.02 -740.02 -943.02

1750 1103 12 625.35 386.52 147.70 -91.13 -329.95 -568.78 -807.61 -1046.43 -1285.26

1500 1121 13.8 571.70 297.05 22.40 -252.25 -526.90 -801.55 -1076.20 -1350.85 -1625.50

1250 1142 15 544.94 246.40 -52.13 -350.66 -649.19 -947.73 -1246.26 -1544.79 -1843.32

1000 1166 16 529.13 210.70 -107.74 -426.17 -744.61 -1063.04 -1381.48 -1699.91 -2018.34

750 1195 17 518.33 179.99 -158.35 -496.68 -835.02 -1173.36 -1511.69 -1850.03 -2188.37

500 1230 17.8 521.48 167.23 -187.03 -541.29 -895.55 -1249.81 -1604.07 -1958.32 -2312.58

250 1272 18.2 547.56 185.34 -176.88 -539.10 -901.31 -1263.53 -1625.75 -1987.97 -2350.19

1200.00

1000.00

800.00

600.00

400.00

200.00

0.00 0.00 500.00 1000.001500.00 2000.00 2500.00 3000.00 3500.00 4000.00

qL (b/d)

IPR 2000 St 150 St 200 St 250 St 300

St 350 St 400 St 450 St 500


54


St Qp (BPD) hp HP150 2170 0.36 50.39200 2250 0.37 69.05250 2380 0.37 86.31300 2450 0.37 103.57

2500

2450

2400

2350

2300

2250

2200

2150 0 100 200 300 400

Stages or HorsepowerSt HP



Result for t= 2000 daysQ 2170 b/dStage 150HP 50.39 HPEfisiensi 43 %

900.00 800.00 700.00 600.00 500.00 400.00 300.00 200.00 100.00

0.00 0.00 500.001000.001500.002000.002500.003000.003500.00

qL (b/d)

IPR 2500 St 200 St 250 St 300


55

650.00 600.00 550.00 500.00 450.00 400.00 350.00 300.00 250.00 200.00 150.00 100.00

50.00 0.00

0.00 200.00 400.00 600.00 800.00 1000.001200.00 1400.00qL (b/d)

IPR 3000 St 150 St 200 St 250



t (days) Q (b/d) St hp HP2000 2170 150 0.36 50.392500 1950 150 0.36 51.113000 950 150 0.36 52.37

Well# 3



Q P2 h100


150 200 250 300 350 400 450 500

800 1124 3.5 989.34 922.01 854.68 787.35 720.02 652.69 585.36 518.03 450.70

700 1138 10.1 749.41 555.12 360.82 166.53 -27.77 -222.06 -416.35 -610.65 -804.94

600 1153 16 537.41 229.62 -78.17 -385.97 -693.76 -1001.55 -1309.34 -1617.14 -1924.93

500 1168 18.8 444.69 83.03 -278.63 -640.28 -1001.94 -1363.60 -1725.25 -2086.91 -2448.57

400 1185 20.5 396.28 1.92 -392.44 -786.80 -1181.16 -1575.52 -1969.88 -2364.24 -2758.60

300 1203 22 356.57 -66.65 -489.86 -913.08 -1336.29 -1759.51 -2182.72 -2605.94 -3029.15

200 1222 22.9 340.94 -99.59 -540.12 -980.64 -1421.17 -1861.70 -2302.23 -2742.76 -3183.29

100 1237 23 352.09 -90.36 -532.81 -975.26 -1417.72 -1860.17 -2302.62 -2745.07 -3187.53

56

St 2b/d)

600.00

400.00

200.00

0.00 0.00 200.00 400.00 600.00 800.00 1000.00 1200.00 1400.00

IPR 2000 St 150 00 St 250 St 300

St 350 St 400 St 450 St 500



St Qp (BPD) hp HP100 675 0.121 10.91150 720 0.122 16.50200 745 0.122 22.01250 760 0.122 27.51300 770 0.126 34.09350 780 0.128 40.40400 785 0.129 46.54450 790 0.129 52.35500 795 0.129 58.17

820

800

780

760

740

720

700

680

660 0 100 200 300 400 500 600



57



Q 720 b/dStage 150HP 16.50 HPEfisiensi 38 %

600.00

500.00

400.00

300.00

200.00

100.00

0.00 0.00 200.00 400.00 600.00 800.00 1000.00 1200.00

qL (b/d)

IPR 2500 St 150 St 200 St 250


500.00 450.00 400.00 350.00 300.00 250.00 200.00 150.00 100.00

50.00 0.00

0.00 100.00200.00 300.00 400.00 500.00 600.00 700.00 800.00 900.00 qL (b/d)

IPR 3000 St 150 St 200 St 250


58


t (days) Q (b/d) St hp HP2000 720 150 0.122 16.502500 635 150 0.121 16.583000 599 150 0.122 16.58

Well# 4



Q P2 h100


150 200 250 300 350 400 450 500

2500 998 5.1 792.46 689.69 586.92 484.15 381.38 278.61 175.85 73.08 -29.69

2250 1009 8 686.59 525.38 364.17 202.97 41.76 -119.45 -280.65 -441.86 -603.07

2000 1022 10.2 610.92 405.38 199.85 -5.69 -211.23 -416.77 -622.31 -827.85 -1033.39

1750 1036 12 552.38 310.57 68.76 -173.05 -414.86 -656.67 -898.48 -1140.29 -1382.10

1500 1052 13.8 495.84 217.76 -60.33 -338.41 -616.49 -894.57 -1172.65 -1450.73 -1728.82

1250 1069 15 464.47 162.21 -140.05 -442.31 -744.58 -1046.84 -1349.10 -1651.36 -1953.63

1000 1090 16 445.17 122.76 -199.65 -522.07 -844.48 -1166.89 -1489.31 -1811.72 -2134.13

750 1114 17 428.87 86.31 -256.26 -598.82 -941.39 -1283.95 -1626.51 -1969.08 -2311.64

500 1143 17.8 425.63 66.94 -291.74 -650.43 -1009.11 -1367.80 -1726.48 -2085.17 -2443.85

250 1175 18.2 441.51 74.76 -291.98 -658.73 -1025.47 -1392.22 -1758.96 -2125.71 -2492.45

1200.00

1000.00

800.00

600.00

400.00

200.00 0.00

0.00 500.00 1000.00 1500.00 2000.00 2500.00 3000.00qL (b/d)

IPR 2000 St 150 St 200 St 250 St 300

St 350 St 400 St 450 St 500


59


St Qp (BPD) hp HP150 2170 0.36 51.01200 2250 0.37 69.91250 2380 0.37 87.39300 2450 0.37 104.86

2500

2450

2400

2350

2300

2250

2200

2150 0 100 200 300 400

Stages or HorsepowerSt HP



Result for t= 2000 daysQ 2170 b/dStage 150HP 51.01 HPEfisiensi 43 %

600.00

500.00

400.00

300.00

200.00

100.00

0.00 0.00 200.00 400.00 600.00 800.00 1000.00 1200.00 1400.00 1600.00

qL (b/d)

IPR 2500 St 200 St 250 St 300


60

300.00

250.00

200.00

150.00

100.00

50.00

0.00 0.00 50.00 100.00 150.00 200.00 250.00 300.00 350.00 400.00

qL (b/d)

IPR 3000 St 150 St 200 St 250



t (days) Q (b/d) St hp HP2000 1800 150 0.34 48.182500 1225 150 0.3 43.243000 310 150 0.2 29.42

Well# 5



Q P2 h100


150 200 250 300 350 400 450 500

2500 1098 5.1 893.22 790.83 688.44 586.04 483.65 381.26 278.87 176.48 74.09

2250 1113 8 791.77 631.16 470.55 309.93 149.32 -11.29 -171.91 -332.52 -493.14

2000 1128 10.2 718.44 513.65 308.87 104.09 -100.69 -305.48 -510.26 -715.04 -919.82

1750 1144 12 662.16 421.24 180.32 -60.60 -301.52 -542.44 -783.36 -1024.28 -1265.20

1500 1164 13.8 609.88 332.82 55.77 -221.29 -498.35 -775.41 -1052.47 -1329.53 -1606.58

1250 1185 15 582.70 281.55 -19.60 -320.75 -621.90 -923.05 -1224.20 -1525.35 -1826.50

1000 1210 16 567.55 246.32 -74.91 -396.14 -717.36 -1038.59 -1359.82 -1681.04 -2002.27

750 1240 17 557.39 216.09 -125.22 -466.52 -807.82 -1149.13 -1490.43 -1831.73 -2173.04

500 1276 17.8 561.27 203.90 -153.46 -510.83 -868.19 -1225.56 -1582.92 -1940.29 -2297.65

250 1319 18.2 588.21 222.81 -142.58 -507.98 -873.37 -1238.77 -1604.17 -1969.56 -2334.96

61

1200.00

1000.00

800.00

600.00

400.00

200.00

0.00 0.00 500.00 1000.00 1500.00 2000.00 2500.00 3000.00

qL (b/d)

IPR 2000 St 150 St 200 St 250 St 300

St 350 St 400 St 450 St 500



St Qp (BPD) hp HP150 2170 0.36 50.83200 2250 0.37 69.65250 2380 0.37 87.06300 2450 0.37 104.48

2500

2450

2400

2350

2300

2250

2200

2150 0 50 100 150 200 250 300 350



62



Q 2170 b/dStage 150

HP 50.83 HPEfisiensi 43 %

700.00

600.00

500.00

400.00

300.00

200.00

100.00

0.00 0.00 200.00400.00 600.00 800.001000.001200.001400.001600.001800.002000.00

qL (b/d)

IPR 2500 St 200 St 250 St 300


500.00 450.00 400.00 350.00 300.00 250.00 200.00 150.00 100.00

50.00 0.00

0.00 100.00 200.00 300.00 400.00 500.00 600.00 700.00 800.00 900.00qL (b/d)

IPR 3000 St 150 St 200 St 250


63


t (days) Q (b/d) St hp HP2000 1720 150 0.34 48.002500 1300 150 0.3 42.873000 550 150 0.23 33.52

Perbandingan produksi oleh angkat buatan Artificial Lift

Berikut adalah tabel perbandingan artificial lift. Dari tabel ini, dapat dikatakan bahwa

produksi tertinggi adalah dengan menggunakan ESP sebagai artificial lift dalam bidang ini dan

menghasilkan produksi cumuative tertinggi.

Table 43. Production Profile by Gas Lift

tqL (BPD)

Well 1 Well 2 Well 3 Well 4 Well 5

Total FieldProduction

(BPD)

SeparatorEfficiency (%)

0.00 2800.00 2400.00 800.00 2000.00 2000.00 10000.00 100.001.37 2800.00 2400.00 800.00 2000.00 2000.00 10000.00 100.002.74 2800.00 2400.00 800.00 2000.00 2000.00 10000.00 100.004.11 2710.00 2345.00 775.00 1720.00 1630.00 9180.00 91.805.48 2075.00 1835.00 530.00 1310.00 1400.00 7150.00 71.506.85 1852.84 1373.73 439.17 681.63 938.75 5286.13 52.868.22 1285.43 549.00 302.61 176.16 170.00 2483.20 24.83

Table 44. Cumulative Production by Gas Lift

tNp (STB)

Well 1 Well 2 Well 3 Well 4 Well 5 0.00 0 0 0 0 01.37 1400000 1200000 400000 1000000 10000002.74 2800000 2400000 800000 2000000 20000004.11 4177500 3586250 1193750 2930000 29075005.48 5373750 4631250 1520000 3687500 36650006.85 6355710 5433432.9 1762293.5 4185408.5 4249686.48.22 7140276.9 5914115.8 1947739.3 4399857.4 4526872.8

64

Table 45. Production Profile by SRP

tqL (BPD)


Total FieldProduction

(BPD)

SeparatorEfficiency (%)

0.00 2800.00 2400.00 800.00 2000.00 2000.00 10000.00 100.001.37 2800.00 2400.00 800.00 2000.00 2000.00 10000.00 100.002.74 2800.00 2400.00 800.00 2000.00 2000.00 10000.00 100.004.11 2080.00 2180.00 795 1840 1990 8885.00 88.855.48 2000.00 2100.00 775 1760 1950 8585.00 85.856.85 1920.00 2000.00 760 1120.00 1440.00 7240.00 72.408.22 1850.00 1070.00 750.00 645.00 0.00 4315.00 43.15

Table 46. Cumulative Production by SRP

tNp (STB)


Table 47. Production Profile by ESP

tqL (BPD)


Total Field SeparatorProduction Efficiency

(BPD) (%) 0.00 2800 2400 800 2000 2000 10000 1001.37 2800 2400 800 2000 2000 10000 1002.74 2800 2400 800 2000 2000 10000 1004.11 2710 2345 775 1720 1630 9180 91.85.48 2400 2170 720 1800 1720 8810 88.16.85 2220 1950 635 1225 1300 7330 73.38.22 1925.00 950.00 599.00 310.00 550.00 4334.00 43.34

65

Table 48. Produksi kumulatif by ESP

tNp (STB)


Kesimpulan

1. Gas lift adalah tidak benar-benar metode canggih artificial lift, seperti gas lift adalah hampir sama seperti aliran alami. Dan fasilitas permukaan untuk sistem angkat gas juga tidak terlalu sulit, yang paling penting adalah ada persediaan gas dan kompresor.

2. Gas lift tidak akan bekerja secara efisien ketika sudah ada banyak gas di sumur, referring baik akan didominasi oleh gas dan cairan akan tertinggal.

3. SRP cukup mudah untuk beroperasi sebagai begitu banyak bidang operator akrab dengannya..

4. Panjang stroke SRP lebih kecil, lebih cepat kecepatan stroke akan menghasilkan.

5. ESP dapat membawa banyak keuntungan karena itu dapat mengangkat banyak cairan dari sumur, tetapi itu akan tidak benar ketika ada banyak gas dan pasir.

6. Dalam bidang ini, ESP merupakan artificial lift terbaik untuk diinstal sebagai akan menghasilkan tingkat produksi cairan tambahan tertinggi dan pasti produksi kumulatif bidang ini.

66

Documents

Nodal Analisis.doc