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Artificial Lift Methods

Artificial Lift Methods. GAS LIFT SUCKER ROD PUMP ELECTRIC SUBMERSIBLE PUMP OTHERS. PENDAHULUAN (1). P wh. P sep. P sep. P wh. P wf <P sep +dP f +dP t. Flowing Well. No - Flow Well. P wf =P sep +dP f +dP t. P wf. P wf. PENDAHULUAN (2). Untuk mengangkat fluida sumur :

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Artificial Lift Methods

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

  2. PENDAHULUAN (1) Pwh Psep Psep Pwh Pwf<Psep+dPf+dPt Flowing Well No - Flow Well Pwf=Psep+dPf+dPt Pwf Pwf

  3. PENDAHULUAN (2) • Untukmengangkatfluidasumur: • Menurunkangradienalirandalam tubing • Memberikan energy tambahandidalamsumuruntukmendorongfluidasumurkepermukaan Psep Pwh Gradien ? No - Flow Well Energy ? Pwf

  4. PENDAHULUAN (3) Gas Lift Well ESP Well Sucker Rod Pump Well

  5. PENDAHULUAN GAS LIFT (1) • PersamaanUmum Pressure Loss • Pengurangangradienalirandenganmenurunkandensitasfluida Psep Pwh Pwf

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

  7. PENDAHULUAN GAS LIFT (3) Psep Pwh Pwf<Psep+dPf+dPt Pwf>Psep+(dPf+dPt) Pwf Berkurang

  8. GAS LIFT (1) • 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. SURFACE COMPONENTS SUB-SURFACE COMPONENTS RESERVOIR COMPONENTS

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

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

  12. Compressor Sub-System Horse Power Compressor Pintake Pdischarge Pinjection@wellhead DPgas Wellhead Qgas Qgas Pinjection@wellhead=Pdischarge - DP Separator Compressor Wellhead

  13. Surface Injection Pressure Production Choke Injection Choke Wellhead Pressure Production Fluid Gas Injection Wellhead Sub-System

  14. Pt Gas Injeksi Pc Pc Pc = Pt Pt Fluida Produksi Gas Lift Valve Sub-System

  15. Gas Lift Valve Gas Injection Tubing Pressure Close condition Open condition

  16. Kriteria Operasi Sumur Gas Lift 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.

  17. 2 Types of Gas Lift Operation 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.

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

  19. Evaluation of Gas Lift Potential • 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.

  20. Gas Injection Rates • Four gas injection rates are significant in the operation of gas lift installations: • 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). • Injection rates of maximum efficiency where a minimum volume of gas is required to lift a given amount of liquid. • Injection rate for maximum liquid flow rate at the ‘‘optimum GLR.’’ • 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

  21. CONTINUOUS GAS LIFT THE GAS IS INJECTED CONTINUOUSLY TO ANNULUS

  22. Continuous Gas Lift Operation 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. 13.4.

  23. Gas Lift OperationPressure vs Depth

  24. Parameter Design • Jumlah gas injeksi yang tersedia • Jumlah gas injeksi yang dibutuhkan • Tekanan Gas Injeksi yang dibutuhkan di setiap sumur • Tekanan Kompresor yang dibutuhkan

  25. Gas Injeksi yang diperlukan GAS LIFT PERFORMANCE CURVE

  26. Availability amount of Gas Injection 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. Kebutuhan Gas Injeksi (1) • Nodal Analysis: • IPR Curve • Tubing Performance Curve • GLR formasi • Variasi GLR • GLR-total (assume) • Qg-inj = Qtotal – Qq-f • Plot Qg-inj vs Qliquid

  28. Kebutuhan Gas Injeksi (2) • Qg-inj >> maka Qliq >> • Pertambahan Qliq makin kecil dengan makin meningkatnya Qg-inj • Sampai suatu saat dengan pertambahan Qg-inj, Qliq berkurang • Titik puncak dimana Qliq maksimum disebut sebagai Qoptimum

  29. Unlimited Gas Injection Case • 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).

  30. Unlimited Gas Injection Case • 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

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

  32. Gas Flow Rate Requirement • 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 qg = total output gas flow rate of the compression station, scf/day Sf = safety factor, 1.05 or higher Nw = number of wells

  33. Point of Injection

  34. Output Gas Pressure Requirement (1) • 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.

  35. Output Gas Pressure Requirement (2) Horse Power Compressor Pintake Pdischarge Pinjection@wellhead DPgas Wellhead Qgas Qgas Pinjection@wellhead=Pdischarge - DP Separator Compressor Wellhead 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

  36. COMPRESSOR

  37. Pt Gas Injeksi Pc Pc Pc = Pt Pt Fluida Produksi Output Gas Pressure Requirement (3) • The injection pressure at valve depth in the casing side can be expressed as: • It is a common practice to use Dpv = 100 psi. The required size of the orifice can be determined using the choke-flow equations presented in Subsection 13.4.2.3

  38. Tekanan Tubing @ Valve Gas Lift Dp @ tubing Pwf

  39. Surface Injection Pressure Production Choke Injection Choke Wellhead Pressure Production Fluid Gas Injection Output Gas Pressure Requirement (4) • Accurate determination of the surface injection pressure pc,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)

  40. Surface Injection Pressure Production Choke Injection Choke Wellhead Pressure Production Fluid Gas Injection Up-Stream Choke / Injection Choke • 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

  41. Gas Lift Injection Parameters Compressor Pressure Pwf

  42. Point of Injection

  43. Point of Balanced

  44. Unloading Valves Design Unloading ProcessGas Lift Wells

  45. Persiapan Operasi Sumur Gas Lift

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

  47. 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. No flow Permukaan Killing fluid Valve 1 : Terbuka Valve 2 : Terbuka Valve 3 : Terbuka Valve 4 : Terbuka

  48. 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 1 : Tertutup Permukaan Killing fluid Valve 2 : Terbuka Valve 3 : Terbuka Valve 4 : Terbuka Permukaan Fluida Res.

  49. 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. Valve 1 : Tertutup Permukaan Fluida Res. Valve 2 : Tertutup Valve 3 : Tertutup Valve 4 : Terbuka Permukaan Killing fluid

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