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GAS LIFT SUCKER ROD PUMP ELECTRIC SUBMERSIBLE PUMP OTHERS Artificial Lift Methods 1.

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Presentasi berjudul: "GAS LIFT SUCKER ROD PUMP ELECTRIC SUBMERSIBLE PUMP OTHERS Artificial Lift Methods 1."— Transcript presentasi:

1 GAS LIFT SUCKER ROD PUMP ELECTRIC SUBMERSIBLE PUMP OTHERS Artificial Lift Methods 1

2 PENDAHULUAN (1) P wf P wh P sep P wf P wh P sep P wf =P sep +dP f +dP t P wf


3 PENDAHULUAN (2) Untuk mengangkat fluida sumur:  Menurunkan gradien aliran dalam tubing  Memberikan energy tambahan di dalam sumur untuk mendorong fluida sumur ke permukaan P wf P wh P sep No - Flow Well Energy ? 3 Gradien ?

4 PENDAHULUAN (3) Gas Lift WellESP WellSucker Rod Pump Well 4

5 PENDAHULUAN GAS LIFT (1) 5 Persamaan Umum Pressure Loss Pengurangan gradien aliran dengan menurunkan densitas fluida P wf P wh P sep

6 PENDAHULUAN GAS LIFT (2) Densitas Campuran Gradient ElevasiGradient Friksi Gradient Akselerasi ? ? 6

7 PENDAHULUAN GAS LIFT (3) P wf P wh P sep P wf

P sep +(dP f +dP t ) Berkurang

8 GAS LIFT (1) 8 Gas lift technology increases oil production rate by injection of compressed gas into the lower section of tubing through the casing–tubing annulus and an orifice installed in the tubing string. Upon entering the tubing, the compressed gas affects liquid flow in two ways: (a) the energy of expansion propels (pushes) the oil to the surface and (b) the gas aerates the oil so that the effective density of the fluid is less and, thus, easier to get to the surface.

9 9 SURFACE COMPONENTS SUB-SURFACE COMPONENTS RESERVOIR COMPONENTS

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11 Detail Gas Lift Surface Operation 11 Injected Gas Res. Fluid + Inj. Gas

12 12 Sistem Sumur Gas Lift Gas Injection Line PtPt PcPc Compressor Subsystem intake system outlet system choke pressure gauge injection rate metering Flow Line Separator Wellhead Subsystem : Production subsystem wellhead production choke pressure gauge Injection subsystem injection choke Valve Subsystem Wellbore Subsystem: perforation interval tubing shoe packer Separator Subsystem: separator manifold pressure gauges flow metering Unloading Gas Lift Mandrells Gas Injection Valve

13 13 Compressor Sub-System  Pgas Compressor Wellhead Separator P intake P discharge Horse Power Compressor P P discharge -  P Q gas Wellhead

14 14 Wellhead Sub-System Production Choke Injection Choke Surface Injection Pressure Wellhead Pressure Gas Injection Production Fluid

15 15 Gas Lift Valve Sub-System PtPt PcPc PcPc PtPt Gas Injeksi Fluida Produksi P c = P t

16 16 Gas Lift Valve Gas Injection Tubing Pressure Close condition Open condition

17 Kriteria Operasi Sumur Gas Lift 17 There are four categories of wells in which a gas lift can be considered:  High productivity index (PI), high bottom-hole pressure wells  High PI, low bottom- hole pressure wells  Low PI, high bottom- hole pressure wells  Low PI, low bottom-hole pressure wells Wells having a PI of 0.50 or less are classified as low productivity wells. Wells having a PI greater than 0.50 are classified as high productivity wells. High bottom-hole pressures will support a fluid column equal to 70% of the well depth. Low bottom-hole pressures will support a fluid column less than 40% of the well depth.

18 Continuous Gas Lift Intermittent Gas Lift A continuous gas lift operation is a steady-state flow of the aerated fluid from the bottom (or near bottom) of the well to the surface. Continuous gas lift method is used in wells with a high PI (0:5 stb=day=psi) and a reasonably high reservoir pressure relative to well depth. Intermittent gas lift operation is characterized by a start-and- stop flow from the bottom (or near bottom) of the well to the surface. This is unsteady state flow. Intermittent gas lift method is suitable to wells with (1) high PI and low reservoir pressure or (2) low PI and low reservoir pressure Types of Gas Lift Operation

19 Materi Perencanaan Sumur Gas Lift 19 This chapter covers basic system engineering design fundamentals for gas lift operations. Relevant topics include the following: 1. Liquid flow analysis for evaluation of gas lift potential 2. Gas flow analysis for determination of lift gas compression requirements 3. Unloading process analysis for spacing subsurface valves 4. Valve characteristics analysis for subsurface valve selection 5. Installation design for continuous and intermittent lift systems.

20 Evaluation of Gas Lift Potential 20 Evaluation of gas lift potential requires system analyses to determine well operating points for various lift gas availabilities. The principle is based on the fact that there is only one pressure at a given point (node) in any system; no matter, the pressure is estimated based on the information from upstream (inflow) or downstream (outflow). The node of analysis is usually chosen to be the gas injection point inside the tubing, although bottom hole is often used as a solution node.

21 Gas Injection Rates 21 Four gas injection rates are significant in the operation of gas lift installations: 1.Injection rates of gas that result in no liquid (oil or water) flow up the tubing. The gas amount is insufficient to lift the liquid. If the gas enters the tubing at an extremely low rate, it will rise to the surface in small semi-spheres (bubbly flow). 2.Injection rates of maximum efficiency where a minimum volume of gas is required to lift a given amount of liquid. 3.Injection rate for maximum liquid flow rate at the ‘‘optimum GLR.’’ 4.Injection rate of no liquid flow because of excessive gas injection. This occurs when the friction (pipe) produced by the gas prevents liquid from entering the tubing

22 THE GAS IS INJECTED CONTINUOUSLY TO ANNULUS 22 CONTINUOUS GAS LIFT

23 Continuous Gas Lift Operation 23 The tubing is filled with reservoir fluid below the injection point and with the mixture of reservoir fluid and injected gas above the injection point. The pressure relationship is shown in Fig

24 Gas Lift Operation Pressure vs Depth 24

25 Parameter Design 25 Jumlah gas injeksi yang tersedia Jumlah gas injeksi yang dibutuhkan Tekanan Gas Injeksi yang dibutuhkan di setiap sumur Tekanan Kompresor yang dibutuhkan

26 GAS LIFT PERFORMANCE CURVE 26 Gas Injeksi yang diperlukan

27 Unlimited amount of lift gas Unlimited amount of lift gas Limited amount of gas In a field-scale valuation, if an unlimited amount of lift gas is available for a given gas lift project, the injection rate of gas to individual wells should be optimized to maximize oil production of each well. If only a limited amount of gas is available for the gas lift, the gas should be distributed to individual wells based on predicted well lifting performance, that is, the wells that will produce oil at higher rates at a given amount of lift gas are preferably chosen to receive more lift gas. 27 Availability amount of Gas Injection

28 Kebutuhan Gas Injeksi (1) 28 Nodal Analysis:  IPR Curve  Tubing Performance Curve  GLR formasi Variasi GLR  GLR-total (assume)  Q g-inj = Q total – Q q-f Plot Q g-inj vs Q liquid

29 Kebutuhan Gas Injeksi (2) 29 Q g-inj >> maka Q liq >> Pertambahan Q liq makin kecil dengan makin meningkatnya Q g-inj Sampai suatu saat dengan pertambahan Q g- inj, Q liq berkurang Titik puncak dimana Q liq maksimum disebut sebagai Q optimum

30 Unlimited Gas Injection Case 30 If an unlimited amount of gas lift gas is available for a well, the well should receive a lift gas injection rate that yields the optimum GLR in the tubing so that the flowing bottom- hole pressure is minimized, and thus, oil production is maximized. The optimum GLR is liquid flow rate dependent and can be found from traditional gradient curves such as those generated by Gilbert (Gilbert, 1954).

31 Unlimited Gas Injection Case 31 After the system analysis is completed with the optimum GLRs in the tubing above the injection point, the expected liquid production rate (well potential) is known. The required injection GLR to the well can be calculated by

32 Limited amount of gas injection 32 If a limited amount of gas lift gas is available for a well, the well potential should be estimated based on GLR expressed as

33 Gas Flow Rate Requirement 33 The total gas flow rate of the compression station should be designed on the basis of gas lift at peak operating condition for all the wells with a safety factor for system leak consideration, that is, where q g = total output gas flow rate of the compression station, scf/day S f = safety factor, 1.05 or higher N w = number of wells

34 34 Point of Injection

35 Output Gas Pressure Requirement (1) 35 Kickoff of a dead well (non-natural flowing) requires much higher compressor output pressures than the ultimate goal of steady production (either by continuous gas lift or by intermittent gas lift operations).Mobil compressor trailers are used for the kickoff operations.

36 Output Gas Pressure Requirement (2) 36 The output pressure of the compression station should be designed on the basis of the gas distribution pressure under normal flow conditions, not the kickoff conditions. It can be expressed as  Pgas Compressor Wellhead Separator P intake P discharge Horse Power Compressor P P discharge -  P Q gas Wellhead

37 COMPRESSOR 37

38 Output Gas Pressure Requirement (3) 38 The injection pressure at valve depth in the casing side can be expressed as : It is a common practice to use  p v = 100 psi. The required size of the orifice can be determined using the choke-flow equations presented in Subsection PtPt PcPc PcPc PtPt Gas Injeksi Fluida Produksi P c = P t

39 Tekanan Valve Gas Lift 39 P wf  tubing

40 Output Gas Pressure Requirement (4) 40 Accurate determination of the surface injection pressure p c,s requires rigorous methods such as the Cullender and Smith method (Katz et al., 1959). However, because of the large cross-sectional area of the annular space, the frictional pressure losses are often negligible. Then the average temperature and compressibility factor model degenerates to (Economides et al., 1994) Production Choke Injection Choke Surface Injection Pressure Wellhead Pressure Gas Injection Production Fluid

41 Up-Stream Choke / Injection Choke 41 The pressure upstream of the injection choke depends on flow condition at the choke, that is, sonic or subsonic flow. Whether a sonic flow exists depends on a downstream- toupstream pressure ratio. If this pressure ratio is less than a critical pressure ratio, sonic (critical) flow exists. If this pressure ratio is greater than or equal to the critical pressure ratio, subsonic (subcritical) flow exists. The critical pressure ratio through chokes is expressed as Production Choke Injection Choke Surface Injection Pressure Wellhead Pressure Gas Injection Production Fluid

42 Gas Lift Injection Parameters 42 Compressor Pressure P wf

43 Point of Injection 43

44 Point of Balanced 44

45 UNLOADING PROCESS GAS LIFT WELLS 45 Unloading Valves Design

46 Persiapan Operasi Sumur Gas Lift 46

47 47 Katup Unloading sudah dipasang. Sumur masih diisi killing fluid Fluida produksi masih belum mengalir ke dalam tubing Valve 1 : Terbuka Valve 2 : Terbuka Valve 3 : Terbuka Valve 4 : Terbuka Permukaan Killing fluid No flow Choke Tutup TAHAP O

48 48 Tahap I Pada Gambar 1 ditunjukkan penampang sumur yang siap dilakukan proses pengosongan (unloading). Pada tubing telah dipasang empat katup, yang terdiri dari 3 katup, yaitu katup (1), (2) dan (3), yang akan berfungsi sebagai katup unloading. Sedangkan katup (4) akan berfungsi sebagai katup operasi. Sebelum dilakukan injeksi semua katup dalam keadaan terbuka. Sumur berisi cairan work-over, ditunjukkan dengan warna biru, dan puncak cairan berada diatas katup unloading (1). Gas mulai diinjeksikan, maka gas akan menekan permukaan cairan work over kebawah, dan penurunan permukaan cairan ini akan mencapai katup unloading (1). Pada saat ini gas akan mengalir dalam tubing melalui katup (1) yang terbuka. Valve 1 : Terbuka Valve 2 : Terbuka Valve 3 : Terbuka Valve 4 : Terbuka Permukaan Killing fluid No flow

49 49 Tahap II Pada Gambar 2 gas injeksi mendorong permukaan cairan work-over, dan telah me-lampaui katup unloading (1) dan mencapai katup unloading (2). Pada saat ini katup unloading (1) tertutup dan gas injeksi mendorong permukaan cairan kebawah. Bagian bawah tubing yang semula berisi cairan work-over ditempati oleh fluida for-masi. Pada saat ini gas akan masuk kedalam tubing, melalui katup unloading (2) yang terbuka. Dengan masuknya gas injeksi tersebut kedalam tubing maka kolom cairan dalam tubing akan lebih ringan dan aliran cairan work over ke permukaan akan berlanjut. Valve 2 : Terbuka Valve 3 : Terbuka Valve 4 : Terbuka Valve 1 : Tertutup Permukaan Killing fluid Permukaan Fluida Res.

50 50 Tahap III Pada Gambar 3 gas injeksi mendorong permukaan cairan work-over, sampai me- lampaui katup unloading (1), (2) dan (3). Setiap saat permukaan kolom cairan work-over mencapai katup unloading, maka gas injeksi akan mengalir masuk kedalam tubing dan aliran cairan work- over dalam tubing akan tetap berlangsung. Jika per-mukaan kolom cairan work-over mencapai katup unlaoding (3), maka katup unloading (2) akan tertutup, dan gas injeksi akan masuk melalui katup unloading (3). Selama ini pula permukaan cairan formasi akan bergerak ke permukaan. Pada saat cairan work-over mencapai katup terakhir, yaitu katup operasi (4), maka katup unloading (3) akan tertutup dan seluruh cairan work-over telah terangkat semua ke permukaan, dan hanya katup operasi yang terbuka. Permukaan Killing fluid Permukaan Fluida Res. Valve 1 : Tertutup Valve 2 : Tertutup Valve 3 : Tertutup Valve 4 : Terbuka

51 TAHAP IV 51 Pada Gambar 4 ditunjukkan bahwa semua cairan work-over telah terangkat dan sumur berproduksi secara sembur buatan. Katup operasi (4) akan tetap terbuka, sebagai jalan masuk gas injeksi kedalam tubing. Katup ini diharapkan dapat bekerja dalam waktu yang lama. Dimasa mendatang akan terjadi perubahan perbandingan gas-cairan dari formasi, yang cenderung menurun serta peningkatan produksi air, maka jumlah gas injeksi dapat ditingkatkan dan diharapkan katup injeksi dapat menampung peningkatan laju injeksi gas tersebut. Dengan demikian pemilihan ukuran katup injeksi perlu direncanakan dengan baik. Fluida Produksi Valve 1 : Tertutup Valve 2 : Tertutup Valve 3 : Tertutup Valve 4 : Terbuka

52 52

53 GAS LIFT VALVE GAS LIFT VALVE MECHANICS 53 Unloading Valves Design

54 Gas Lift Valve 54

55 Gas Lift Valve 55

56 56 Contoh Penampang Sumur Gas Lift } Gas Lift Mandrell Gas Lift Valves Gas Lift Valves: Mandrell + Dummy Valves Mandrell + Valves Valves Operating Conditions: Casing pressure Test Rack Opening Pressure Port Size Lab. Jenis Valves

57 Gas Lift Valve 57 PtPt PcPc PcPc PtPt Gas Injeksi Fluida Produksi P c = P t

58 Penampang Gas Lift Valve 58

59 Jenis Gas Lift Valves 59

60 Gas Lift Valve 60 Gas Injection Tubing Pressure Close condition Open condition

61 MEKANIKA VALVE CLOSING & OPENING PRESSURE 61 Valve Mechanics

62 Mekanika Valve (Membuka+Menutup) 62 Dome berisi gas Nitrogen yang mempunyai tekanan tertentu. Gas Nitrogen ini menekan bagian dasar dome, Pd, pada luas penampang bellow, Ab Port terbuka untuk dilalui gas masuk kedalam tubing, jika ujung stem tidak menempel pada port. Jika gaya membuka sedikit lebih besar dari gaya menutup.

63 Posisi Valve Tertutup Gas Lift - Design 63 Perkalian antara tekanan dalam dome, Pd, dengan luas penampang bellow, Ab, menghasilkan gaya kebawah yang mendorong stem dan ujung stem kebawah, sehingga menutup port. Gaya ini disebut sebagai gaya menutup. Gaya menutup= F c = P d A b

64 Posisi Valve Terbuka Gas Lift - Design 64 Gaya membuka ini berasal dari tekanan gas injeksi dari anulus, Pc yang menekan bellow ke atas, pada luas penampang efektif sebesar (Ab-Ap) serta tekanan fluida dari tubing, Pt (melalui port) yang menekan ujung stem keatas. Gaya membuka = Pc (Ab - Ap) + Pt Ap

65 Keseimbangan Gaya Membuka dan Menutup Gas Lift - Design 65 Dalam keadaan seimbang, yaitu sesaat katup akan membuka, gaya membuka sama dengan gaya menutup, hal ini dapat dinyatakan sebagai berikut: Untuk tekanan tubing, Pt tertentu, gas akan mengalir kedalam katup apabila: Jika persamaan (2) dibagi dengan Ab, maka diperoleh persamaan berikut:

66 Penentuan Tekanan Injeksi Katup Terbuka/Tertutup Gas Lift - Design 66 Apabila R = A p /A b, maka Harga tekanan injeksi, Pc, dapat ditentukan dengan persamaan berikut : Persamaan diatas dapat digunakan untuk menentukan tekanan gas injeksi yang dibutuhkan untuk membuka katup dibawah kondisi operasi.

67 Contoh Soal Gas Lift - Design 67 Katup sembur buatan ditempatkan di kedalaman 6000 ft. Tekanan dome dan tekanan tubing di kedalaman tersebut masing- masing sebesar 700 psi dan 500 psi. Apabila A b katup sebesar 1.0 in2 dan A p = 0.1 in2, tentukan tekanan gas di annulus yang diperlukan untuk membuka katup. Perhitungan: R=A p /A b = 0.1/1.0 = 0.1 P d =700 psi P t =500 psi Dengan menggunakan persamaan (5), tekanan gas injeksi yang diperlukan untuk membuka katup sebesar: P c =( (0.1) / ( ) = 722 psi

68 Penentuan Tekanan Dome Gas Lift - Design 68 P d = ? Pada Temperature Di kedalaman Valve Diubah menjadi Tekanan pada Temperatur Bengkel Test Rack Opening Pressure

69 DOME PADA GAS LIFT VALVE Gas Lift - Design 69 Dome pada Gas Lift Valve, diisi gas Nitrogen sejumlah mole tertentu, sehingga dapat memberikan tekanan tutup valve yang sesuai. Sesuai dengan P V=Z n R T P-dome Vol. dome Temperatur di sekitar dome

70 70 Gas Lift - Design Penentuan Tekanan Dome Tekanan T D = P d Tekanan D = P c Test Rack (di Bengkel) Tekanan T D convert Tekanan 60 o F (Tabel 5-3) Tekanan buka valve, p D Tabel 5-3 Gradien gas injeksi Gradien tubing

71 Temperatur pada Valve Gas Lift - Design 71 T-surface T-bottom Gradient Geothermal ( o F/ft) Gradient Temperatur Aliran Retreivable valve Non-Retreivable valve

72 72 Penentuan Opening/Closing Pressure di Bengkel

73 Penentuan Test Rack Opening Pressure Gas Lift - Design 73 P 1 = P c P 2 = 0

74 Ptro (1) Gas Lift - Design 74 Keseimbangan Gaya Buka dan Gaya Tutup, pada Pt = Patm : Dimana Pvc = tekanan tutup di bengkel Jika R = Ap/Ab, maka Maka P-dome di bengkel :

75 Ptro (2) Gas Lift - Design 75 Gaya Buka hanya dipengaruhi oleh Pvc, yaitu: Pd di set pada temperatur bengkel (60 o F) Perlu dilakukan koreksi terhadap temperatur pada kedalaman valve

76 76 Gas Lift - Design Faktor Koreksi Tekanan Gas Nitrogen Dalam Dome (pada Temperatur Bengkel 60 o F) PV = Tv PV = 60 o F

77 77 Gas Lift - Design Perhitungan Bellow secara Analitis P(x) = tekanan rata-rata yang bekerja pada bellow P vi = P(x) yang diperlukan untuk membuka katup z = pergerakan stem dari posisi tertutup k = cp/cv A b = luas permukaan bellow P di = tekanan dome awal Pd(x)=tekanan dome jika stem bergerak sejauh x

78 78 Gas Lift - Design Penentuan Ukuran Port Valve Q= laju alir gas, MCF/d C d = discharge coefficient A p = luas penampang port P u = tekanan injeksi gas dalam annulus, psia k= c p /c v R= perbandingan antara tekanan upstream dengan downstream T= temperatur aliran  g = specific gravity gas Atau dengan menggunakan Grafik, yang dibuat pada kondisi Laju Alir pada kondisi kritik : Specific Gravity gas= 0.65 Temperatur alir= 60 o F Tekanan dasar= psia k = c p /c v = 1.27 Discharge coeficient= 0.865

79 79 Gas Lift - Design Penentuan Ukuran Port : R Berdasarkan rate injeksi (di permukaan – Mscf/d), q gi, sc tentukan rate T D Berdasarkan P t dan P c, gunakan Gambar 5-22, untuk menentukan ukuran Port P t = downstream press P c = upstream press

80 PENEMPATAN VALVE UNLOADING VALVE SPACING 80 Unloading Valve Design

81 81 Various methods are being used in the industry for designing depths of valves of different types. They are the universal design method, the API-recommended method, the fallback method, and the percent load method. However, the basic objective should be the same: 1. To be able to open unloading valves with kickoff and injection operating pressures 2. To ensure single-point injection during unloading and normal operating conditions 3. To inject gas as deep as possible

82 82 No matter which method is used, the following principles apply: The design tubing pressure at valve depth is between gas injection pressure (loaded condition) and the minimum tubing pressure (fully unloaded condition). Depth of the first valve is designed on the basis of kickoff pressure from a special compressor for well kickoff operations. Depths of other valves are designed on the basis of injection operating pressure. Kickoff casing pressure margin, injection operating casing pressure margin, and tubing transfer pressure margin are used to consider the following effects:  Pressure drop across the valve  Tubing pressure effect of the upper valve  Nonlinearity of the tubing flow gradient curve.

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