Electrical Submersible Pump Optimization ( Artificial lift ) ( Case Study )

Transcription

1 Gharian High Engineering Institute Petroleum Engineering Department Electrical Submersible Pump Optimization ( Artificial lift ) ( Case Study ) Prepared By Wesam Altaher Abobaker Elhadi Seraj Abdulhameed Moez Abdulmajeed Supervised By Eng. Esam Saad

2 اإليداء إىل مو علمين العطاء بدوى انتظار... إىل مو أمحل أمس بكل افتخار والدي العشيش إىل معه ابح ابحهاى والتاان... إىل مو كاى دعائ ا صز جناح أم ابحبيبة إىل كل مو علمين حزفا.. إل كل مو أضاء بعلم طزيق يف ابحياة أصاتذت الكزام ال كل مو كاى ل عونا يف دراصيت إخوت وأصدقائ و سمالئ 2

3 `Table of Contents Abstract 5 Objective of The Study 6 1. Introduction to artificial lift techniques Introduction The need of artificial lift Selection of artificial lift system Artificial lift techniques Pump types Gas method Types of artificial lift methods Beam pump or sucker rod pump Hydraulic submersible pump Electrical submersible pump (ESP) Gas lift Introduction to ESP Classification of pumps Why and when we use the ESP ESP advantages ESP disadvantages 17 Equipment Components of ESP system Down hole components Motor Protector Pump intake or gas separator Submergible pump Cable Surface components Tubing head Transformers Electrical supply system Switchboard Junction box Optional equipment with ESP Down hole pressure and temperature monitors Variable speed drive VSD How ESP is run Design and horse power calculation Introduction

4 5.2. Calculation Conclusion Recommendations Reference.45 4

5 ABSTRACT In the oil industry, from the first day of complete the drilling of the well is put directly on the production, which in first period of production the flow is naturally with physical energy inherent the reservoir, but this continues for a sometime which after that the production of well is decline, and the reservoir becomes without enough energy to produce the oil, gas, or produce them at economic rates. As petroleum engineers, must find a solution for this problem. In this time we approach to raise the productivity by decreasing the pressure at the bottom of the well (by lowering bottom whole flowing pressure, or increasing drawdown), by using one of the artificial lift methods. The selection of the most suitable type of artificial lift required is influenced by several factors, such as producing characteristic (water cut, gas liquid ratio, liquid production rate, inflow performance), fluid properties (viscosity, formation volume factor), hole characteristic (depth, size of tubular, completion type, deviation), surface facilities, location, available power sources, operation problem, service availability, and relative economics. This study represented the ESPs main components (motor, pump, protector, gas separator... etc), the advantage and disadvantage of the system, as well as ESP design for one of WAHA company oil fields (Well: A W) 5

6 OBJECTIVE OF THE STUDY The main objective of this work is to discuss the advantages and disadvantages ESP's as well as to design an ESP for a specific well, also this study contains a general definitions about the artificial lift. 6

7 1. INTRODUCTION TO ARTIFICIAL LIFT TECHNIQUES 1.1 INTRODUCTION The artificial lift is Any system that adds energy to the fluid column in a wellbore with the objective of initiating and improving production from the well that refers to the use of artificial means to increase the flow of liquids, such as crude oil or water, from a production well. Generally this is achieved by the use of a mechanical device inside the well. Artificial lift is needed in wells when there is insufficient pressure in the reservoir to lift the produced fluids to the surface, but often used in naturally flowing wells. The produced fluid can be oil and/or water, typically with some amount of gas included generally less than fourth of producing oil wells flow naturally. When a reservoir lacks sufficient energy for oil, gas and water to flow from wells at desired rates, supplemental production method can help, gas, water injection for pressure support or secondary recovery maintain well productivity, but artificial lift is needed when reservoir drives do not sustain acceptable rates or cases fluids to flow at all in some cases. Lift processes transfer energy down hole or decrease fluid density in well bore to reduce the hydrostatic load on formations, so that available reservoir energy causes inflow, and commercial hydrocarbon volumes can be boosted or displaced to surface. Artificial lift also improves recovery by reducing the bottom hole pressure at which wells become uneconomic and are abandoned. Artificial lift systems use a ring of operating principles including; rod pumping, gas lift, electrical submersible pumps. 7

8 1.2 THE NEED OF ARTIFICIAL LIFT. Any liquid-producing reservoir will have a reservoir pressure some level of energy or potential that will force fluid (liquid and/or gas) to areas of lower energy or potential. You can think of this much like the water pressure in your municipal water system. As soon as the pressure inside a production well is decreased below the reservoir pressure, the reservoir will act to fill the well back up, just like opening a valve on your water system. Depending on the depth of the reservoir (deeper results in higher pressure requirement) and density of the fluid (heavier mixture results in higher requirement), the reservoir may or may not have enough potential to push the fluid to the surface. Most oil production reservoirs have sufficient potential to produce oil and gas - which are light - naturally in the early phases of production. Eventually, as water - which is heavier than oil and much heavier than gas - encroaches into production and reservoir pressure decreases as the reservoir depletes, all wells will stop flowing naturally. At some point, most well operators will implement an artificial lift plan to continue and/or to increase production. Most water production wells, by contrast, will need artificial lift from the very beginning of production because they do not benefit from the lighter density of oil and gas. 1.3 SELECTION OF ARTIFICIAL LIFT SYSTEM. The choice of an artificial lift system in a given well depends upon a number of factors such as:- 1. Well productivity (productivity index PI) and water cut percentage. 2. Gaslift availability, either from produced associated gas or from other nearby sources, and reservoir performance must be amenable to gas lift. 3. Space availability for gaslift processing units such as compression unit, and dehydration unit. 4. Crude oil properties such as viscosity, API gravity, GOR, and H2S. 5. Sand production, wax, and asphaltene which may cause a lot of problems to the ESP 6. Well type, vertical or deviated, as this has an impact in the productivity index of a well As a well becomes highly deviated it becomes much hard to lower some artificial lift deeper in the well.. 8

9 7. Power supply availability either electrical or hydraulic power. 8. Number of wells, some type of artificial lift becomes not economically viable if it only applies to a single well 9. Surface facility constraints i.e. separation capacity, water treatment etc. 10. Geographical and environmental consideration as some artificial lift only suits onshore field such as sucker rod pump. 11. Reservoir pressure, temperature, and long term reservoir performance. 12. Cost of artificial lift which including CAPEX and OPEX. 13. Flexibility of artificial lift over changing the operating conditions such as flow rate. 1.4 ARTIFICIAL LIFT TECHNIQUES. Artificial lift methods fall into two groups, those that use pumps and those that use gas: Pump types a) Progressive cavity pumps b) Electric submersible pumps c) Beam pump /sucker rod pumps (rod lift) Gas method a) Gas Lift 1.5 TYPES OF ARTIFICIAL LIFT METHODS Beam pump or sucker rod pump A sucker rod pumping system consists of a pumping unit at the surface and a plunger pump submerged in the production liquid in the well. The prime mover is either electrical motor or an internal combustion engine (Jonathan Bellarby ).The modern method is to supply each well with its own motor or engine. Electrical motors are most desirable because they can easily be automated. 9

10 The power from the prime mover is transmitted to the input shaft of a great reducer by a V-belt drive. The output shaft of a great reducer drives the crank arm at a lower speed (4 ~40 rpm depending on well characteristics and fluid properties) (Jonathan Bellarby ). The rotary motion of the crank arm is converted to an oscillatory motion by means of walking beam through a pitman arm (Jonathan Bellarby ).The horse s head and the hanger cable arrangement is used to ensure that the upwards pull on the sucker rod string is vertical at the all times, thus on bending Gas Lift Design and movement is applied to the stuffing box (Jonathan Bellarby ). The polished rod and stuffing box combined to maintain a good liquid seal at the surface and thus force fluid to flow into the T connection below the stuffing box. Figure (2.1) sucker road pump (After, Jonathan Bellarby ) Hydraulic Submersible Pump It operates in a way similar to ESP, using multistage centrifugal pumps, but hydraulic submersible pump uses downhole turbine to drive the pump. The pump is operated at higher speed than ESP, around three-four times higher revolutions/min. Therefore it (HSP) requires less stage and is much smaller than ESP. A high power fluid is used to drive the turbine; the 10

11 fluid is pumped from the surface to drive the downhole turbine. The power fluid can be comingled with the reservoir fluids and returned to the surface (Jonathan Bellarby ). Figure (2.2) shows HSP (After, Jonathan Bellarby ) ELECTRIC SUBMERSIBLE PUMPS (ESP) The use of mechanical lift as a means of bearing fluids to the surface when bottom hole pressure is not adequate in a new or previously naturally flowing well. With time production may be decline to the point that mechanical lift is no longer effective. The lease operation may try changing the mechanical lift system to compensate for the declining production by adjusting the length of the stroke on the pumping unit and changing the sheaves to increase the number of strokes per minute. Along stroke pumping unit with lighter counterweights may be installed (Gabor Takacs ). 11

12 Submersible system has a wide performance range and is one of the more versatile lift methods. Standard surface electric drives power outputs from 100 to 30,000 HP and variable speed drives add pump rate flexibility high GOR fluids can be handled but large gas volumes can lock up and destroy pumps corrosive fluids are handle by using special materials and coatings. Modified equipment and procedures allow sand and abrasive particles to be pumped without adverse effects (Gabor Takacs ). As a production of natural gas and crude oil continues to diminish and water production increases, particularly in water driven reservoirs, the lease operator may being water flood, an enhanced oil recovery method in which water is injected in to the reservoir at one well to drive hydrocarbons to the other wells (Gabor Takacs ). However, with time oil production will continue to fall a water production increase. As this occurs, the pumping time is increased until the lease pumper is producing the well twenty four hours a day (Gabor Takacs ). At this time the most practical way to improve production is to install a system with greater production capacity.one of the choices, especially in high volume water flood operations, is the electrically driven submersible pump. A submersible pump is one that is lowered into the fluid to be pumped (Gabor Takacs ). Submersible pumps are also used in oil wells. By decreasing the pressure at the bottom of the well (by lowering bottomhole flowing pressure, or increasing drawdown), significantly more oil can be produced from the well compared to natural production. This makes Electric Submersible Pumping (ESP) a form of "artificial lift" (as opposed to natural flow) along with Gas Lift, Beam Pumping, Plunger Lift and Progressive cavity pump. New varieties of ESP can include a water/oil separator which permits the water to be re injected into the reservoir without the need to lift it to the surface (Gabor Takacs ). 12

13 1.5.4 Gas lift Figure (2.3) ESP pumps (From Schlumberger Website 8 ). Gas lift is a process of injecting compressed gas at relatively high pressure via casing deeper down into the well in order to lift the liquid by reducing the wellbore pressure, and hence increasing pressure drawdown. There are two types of gas lift systems used in the oil fields. These are continuous gas lift and intermittent gas lift (Jonathan Bellarby ) 2. Introduction to ESP. The first submersible pumping unit was installed in an oil well in 1928 and since that time the concept has proven itself throughout the oil producing world. Presently, it is considered as an effective and economical means of lifting large volumes of fluids from great depths under a variety of well conditions. Submersible pumping equipment is used to 13

14 produce as low as 200 b/d and as high as 15,000 b/d of fluid from depths up to 15,000 ft. The oil cut may also vary within very wide limits, from negligible amounts to 100%. A submersible pump is a pump which has a hermetically sealed motor close-coupled to the pump body. The whole assembly is submerged in the fluid to be pumped. The advantage of this type of pump is that it can provide a significant lifting force as it does not rely on external air pressure to lift the fluid. A typical submersible pumping unit Figure (1) consists of an electric motor, seal section, intake section, multistage centrifugal pump, electric cable, surface installed switchboard, junction box, transformers and well head supports. Additional miscellaneous components of installation will include check and bleeder valves, means of securing the cable alongside the tubing. Optional equipment may include a pressure sentry for sensing bottom-hole temperature and pressure. Figure (1) 14

15 2.1Classification of Pumps: Pumps are classified in several ways on the applications they serve, the materials from which they are made, the liquids they handle, their orientation in space, or the type of driving system. All such classifications are limited in scope and, in many instances, overlap each other. Another way of classifying the pumps is based on the principle of transferring the energy to the fluid. According to this system, the pumps are classified into two basic groups - dynamic pumps and displacement pumps. Each of these groups can be further classified into several subgroups depending upon design features and characteristics. In dynamic pumps, energy is continuously added to the fluid and is utilized to increase the velocity of the fluid. The velocity difference is subsequently converted into pressure energy. The centrifugal pump basically consists of a moving part, known as an impeller, which is mounted on a rotating shaft and a stationary part, called a diffuser, which is a series of stationary passages with gradually increasing cross-sectional areas. The rotation of the impeller with appropriately shaped blades sets the fluid particles in motion from the inlet towards the discharge. As the fluid Kinetic energy increases. This energy is partially converted into potential energy (pressure or head) in the impeller and in the diffuser. In displacement pumps, energy is periodically added by application of force to one or more movable boundaries of any number of enclosed fluid-containing volumes. Under the action of the force, pressure of the volume increases sufficiently to force the fluid through valves and other resistances into discharge section. submersible pumping systems have a wide range of applications, offer, efficient and economical lift methods. Wells deeper than 15,000 ft, hotter than 220 deg C, and ranging from 200 bbl/d to 15,000 bbl/d are potential electrical submersible pump (ESP) wells. Even if sand production, high GOR, and viscosity are concerns, you can find the right ESP for your well and improve production. From onshore high-water-cut applications to complex offshore, deep-water, or subsea applications, we have a system to meet your needs. We not only supply ESP components but also provide monitoring systems, surface electrical equipment, engineering services, and optimization services to complement the ESP system. By integrating 15

16 technology and service, we can provide an optimum lift system for your well and optimize pump and well performance while reducing operating costs. 2.2 Why and when we use the ESP? Submersible pumps are used in oil and water wells. By decreasing the pressure at the bottom of the well (by lowering bottom hole flowing pressure, or increasing drawdown), when the reservoir pressure can't lift the fluids inside the tubing, significantly more oil can be produced from the well compared to natural production. This makes Electric Submersible Pumping (ESP) a form of "artificial lift" (as opposed to natural flow) along with Gas Lift, sucker rode pump. New varieties of ESP can include a water/oil separator which permits the water to be re injected into the reservoir without the need to lift it to the surface. 16

17 2.3 Electric Submersible Pumping System Advantages. 1. High Volume and Depth Capability 2. High Efficiency Over 12,000 BPD 3. Low Maintenance 4. Minor Surface Equipment Needs 5. Good in Deviated Wells 6. Adaptable to All Wells With 4-1/2 Casing and Larger 7. Use for Well Testing 2.4 Electric Submersible Pumping System Disadvantages. 1. Only applicable with high voltage electric power 2. Repair of ESP equipment in oilfield conditions is difficult, faulty equipment must be sent to the manufacturers repair shop 3. Expensive to change equipment to match declining well productivity 4. Gas and sand production are troubles. 5. Continuous change of equipment to match declining flow rates 6. High well temperature is a limiting factor 7. Running and pulling costs are high because need work over rigs 17

18 3. ESP Equipments: 18

19 3. Components of the Submersible Pumping System: Electrical submersible pump consists of surface and subsurface components. The submergible pumping system major components are (electric motor, protector, intake, multi-stages pump and power cable). Which are run into the well below the tubing string and submerged into the well fluids. Surface components are (electric power supply, transformer, switchboard, junction box, and wellhead). Additional miscellaneous components will normally include (special well heads, cable clamps, check and bleeder valves, Y-tool, centralizersand flat cable guards). Optional equipment may include (a downhole pressure sensor to monitor well bore condition, and variable-speed drive) Down hole component Should be set above the perforations of the well for motor cooling. Must be sized (design) to the wells productivity. Should be monitored for changes in well and\or unit Performance (well testing). Refer to Figure (2) for more details. Figure (2) Down hole components 19

20 3.1.1 Motor: The first component that is lowered into the well is the electric motor. The motor size is designed to lift the estimated volume of production. Is a two pole, three phase, Ac, induction type, A, V. Rotates at approximately 3500 RPM@ 60HZ.and HZ. Is made-up of rotors (Rotating part) and stator (stationary part). Contains mineral ( Di-electric) oil for lubrication and cooling Protector (Seal Section). Figure (3) Motor The protector located between the pump and the motor, and the main functions besides providing mechanical link between the diving and driven shafts are: 1. Prevents well fluids from entering the motor. 2. Provides a reservoir for motor oil expansion and contraction caused by temperature and pressure changes. 3. Equalizes the internal pressure of the motor with the pressure in the well annulus, and 4. Absorbs the pump shaft thrust on the seal thrust bearing Figure (4) shows the cross section of one of the seal sections currently available. 20

21 Figure (4)Protector or (seal section) Seal section is a main element in long system run life. The principle of operation of seal section differs from one manufacture to another. The main difference in the way that the motor oil is isolated from the well fluid. It works by simply keeping the pressure inside the unit same as the pressure outside the unit. Some submersible pump applications have required that two or more protectors be bolted in tandem to achieve adequate protection. The Modular protector eliminates the cost of tandems by combining multiple protector section in one unit Pump Intake or a Gas Separator: The pump intake is used to allow fluid to enter the pump, when the gas liquid ratio (GLR) greater than can be handle by the pump (greater than 10 % in generally). It may also have a gas separator which is a bolt-on section between the protector and the pump where it serves as the pump intake, and designed to separate a greater portion of any free gas in the produced fluid The rotary separator Figure (4A) uses centrifugal force to separate the free gas. The gas/fluid mixture enters the intake ports and moves to the screw type inducer. Here, the pressure of the 21

22 fluid is increased and moved to the centrifuge where the separation occurs. The fluid is forced to the outside of the separator and on to the first pump stage. The lighter gas rises through the flow divider and is vented to the annulus. Vortex style gas separators Figure (4B) use a natural vortex action created by a special inlet configuration, axial flow inducer, propeller, retention chamber, and discharge crossover. These separators provide efficiency over broader flow rang than rotary separators. Figure (4A) A rotary gas separator Figure (4B) Vortex gas separator Submergible Pump : Figure (5A) shows a typical single housing pump. Submergible pumps are multi-staged centrifugal pumps. Each stage consists of a rotating impeller and a stationary diffuser, see Figure (5B) and Figure (5C). The type of stage used determines the volumes of fluid to be produced. The number of stages determines the total head generated and the horsepower required. The pressure-energy change is accomplished as the liquid being pumped surrounds the impeller, and as the impeller rotates, it imparts a rotating motion to the liquid. Actually, there are two components of the motion imparted to the liquid by the impeller. One motion is in a radial direction outward from the center of the impeller. This motion is caused by centrifugal force. The other motion moves in a tangential direction to the outside diameter of the impeller. The result of these two components is the true direction of flow. 22

23 The diffuser's function is to change some of the high velocity energy into relatively low velocity energy while directing the flow to the eye of the next impeller. Figure (5A) Shows a typical single housing pump Figure (5B) Shows an impeller and diffuser for one stage 23

24 Figure (5C) Shows the position of stages The flow rate of a submersible centrifugal pump depends on the following operational parameters; Speed of rotation. Size of impeller. Impeller design. Number of stages. The total dynamic head against which the pump is operating. The physical properties of the fluid being pumped. For deeper applications, the impellers are of the floating or balanced type. In higher volume, larger units, a fixed type impeller is used. 24

25 In a floater pump, the impellers move axially along the shaft. And in a fixed pump, the impeller is fixed to the shaft and cannot move axially. In a combination pump, a certain percentage of the stages are floater and the remaining fixed. So, we can say that, the centrifugal pumps are divided into three groups: Radial-flow pumps. Axial-flow pumps. Mixed-flow pumps Cable A cable leads out of the top of the motor, up the side of the pump, is strapped to the outside of every joint of tubing from the motor to the surface of the well, and is extended on the surface to the control junction box. The power cable is a major component of the ESP system which carries the electrical power from surface to the down-hole motor, and carries pressure and temperature signals from the down-hole monitoring unit to surface. TINNED COPPER CONDUCTOR (solid or compacted) EPDM JACKET METALLIC ARMOR EPDM INSULATION POLIMERIC INNER FILLER LEAD JACKET AND NYLON TAPE WF cables use annealed lead alloy coated copper conductors. Each phase is individually insulated and the insulation is physically bonded to the conductor with adhesive. These 25

26 insulated conductors may then have a protective barrier and/or braid applied over them. Then the cable is jacketed for mechanical and chemical protection and finally, it is usually armored for good mechanical protection. Success or failure of the ESP system depends directly on the proper selection of the cable size, type and configuration for the application. In very deep or severe wells that require special cable features, the cable can be the most expensive component of the system. WF s modular cable allows the user to customize the required cable for his specific well conditions. The modular cable is available in either round or flat configuration and with stranded, compacted or solid conductors. Full range of ESP cable provided: 1. High temperature up to 450F 2. Lead Sheath for gaseous conditions 3. Injection tubing if require 26

27 3.2. Surface Components: Tubing head The tubing head is designed to support the tubing string and provide a seal to permit the electrical line to pass through the head Transformers: Figure (6) Tubing head The transformers are usually located at the edge of the lease site. They transform the electricity provided over the power lines so that it is the correct voltage and amperage to operate the pump motor. 27

28 Figure (7) Transformer Electrical supply system: This is generally the commercial power distribution system. The highest available voltage produces the most efficient performance Switchboard (Motor Controller) : The primary purpose of the switchboard Figure (8A) is to control the pump motor and provide overload and under load protection 28

29 Figure (8A) Motor controller system. Protection during under load, a condition where the pump is not displacing its design volumes, is needed because low flow rates will not allow adequate cooling of the motor. Protection against overload, a condition where excessive amperage flows through the motor, is needed to prevent the burning of the motor windings. Additionally, the switchboard may be used to record amperage on a continuous basis using typically a 24-hour chart or weekly chart (ammeter chart). These ammeters can helps to determine causes of failures and give an indication of pump and well performance, see Figure (8B) 29

30 Figure (8B) An example for ammeter chart The switchboard can also be used as an adjustable time, automatic restart control. If a pump, for example, shuts down because the well is pumped off, you may set the control to begin pumping again in a fixed number of hours. This control will provide automatic restart as needed The modem switchboard provided with variable speed drive (VSD), which will allow altering the frequency and / or voltage at the out put terminals. The main basic components of the switchboard are; Main switch. Selector switch. Fuses. Potential transformer. Over load relays. Under load relays. Ammeter chart recorder. Current transformer. 30

31 Junction Box (Vent Box) The next component of our system is the junction box Figure (9). This component provides a point at which to connect the power cable from the switchboard to the power cable from the wellhead. Junction box is necessary to vent to the atmosphere any gas that may migrate up the power cable from the well, this prevent accumulation of gas in the switchboard that can result in an explosive and unsafe operation condition. A junction box is used for three basic functions; 1. Provides a vent to the atmosphere for any gases that might migrate up the cable. 2. Provides for easy access to test points for electrically checking the down hole equipment. 3. To change the direction of pump rotation Figure (9) Junction box or (vent box) The junction box should be located at least 15 ft from the wellhead and should be locked at all times for security reasons. 31

32 3.3. Optional Equipment with ESP : Down hole pressure and temperature monitors Valuable reservoir and pump performance data can be made available with the use of down hole pressure and temperature monitoring systems. See Figure (10). Figure (10) Monitoring systems There are different types of down hole pressure and temperature sensors available from submersible pump suppliers. This system has the capability of continuously monitoring bottom hole pressure and temperature at the pump's setting depth, and of detecting electrical failures, such as shorts to ground. These units also allow the operator to calculate reservoir parameters by running drawdown or build up tests as stopped or started. 32

33 Variable-Speed Drive VSD : The variable speed drive (VSD) is a highly sophisticated switchboard controller. It performs three distinct functions: 1. It varies the capacity of the ESP by varying the motor speed by changing the voltage frequency supplied to the motor. 2. Protects downhole components from power transients. 3. Provides soft-start capability. A new generation of variable frequency controllers is available, see Figure (11). The system includes a digital data recorder, programmable logic functionality and a high-speed internal communications bus for easy system expansion. Figure (11) Shows a Variable Speed Drive VSD 33

34 4. How ESP is running? An electric submersible pump (ESP) is a type of pump with an electric motor enclosed in a protective housing such that the assembly may be submerged in the fluid to be pumped. A system of mechanical seals may be employed to prevent the fluid being pumped from entering the motor and causing a short circuit. When used in an oil well, an operating ESP decreases the pressure at the bottom of the well and allows significantly more oil to be produced from the well when compared to natural production. 34

35 5. Design and horse power calculation WELL: A123 59W FIELD: WAHA The Study Area 5.1 Introduction: The selected area for study is Gialo oil field Gialo Paleocene that located in Sirt Basinn. The Sirt Basin is located in the north central part of Libya. An active subsidence and block faulting as a result of the collapse of the Sirt Arch in late Early Cretaceous time developed this basin. This Chapter represents general view about field history and some information about its reservoir. General Background of Gialo Field: Gialo oil field was discovered in 1961, and considered as one of the giant fields, located in the eastern part of the Sirt Basinn, concession 59 which belongs to Waha Oil Company, between coordinates a longitude of and E and latitudes of and N Table (3.1)reservior data summary as of january 1,2009 Paleocene zelten limewstone reservior-gialo cone.59e 35

36 Basic reservior data Formation producing Top of pay formation Avrage datum depth Productive acreage Avrage weel spasing Development well spacing Avrage net pay Original bhp at datum Reservior tempreture Paleocene limistone 6300 ft 5900 ft 15,008 acre 517.5acre/well 480 acre/well 47.6ft 2726psig 186deg Avrage rock properties Porosity 25.2% Permeability (horizontal) 14.5 md Water saturation 37.4% Fluid properties Saturation pressure Differential solution GOR Flash solution GOR 770 psi 440 scf/stb 300 scf/stb 36

37 f.v.f at original pressure Current reservior pressure Api gravity at 60deg f rb/stb 2102 psig 39.4 deg API RESERVES Oginal oil_in place Racovery mechanism 923 mmstb Water drive Oil recovery factor 27.1% Recoverable oil 250.2mmstb Optimizing ESP run life is essential to avoid additional workover costs and maintain production levels. Although some failures may require specialist equipment or solutions, the vast majority of short runlives are preventable. The problems usually result from a lack of consideration of the entire ESP system during the design phase or shortcomings during the installation and operation phases. 37

38 CURRENT PERFORATIONS DATA Reservoir Top of perfs. (ft KB) Bottom of perfs.( ft KB) WAHA PRODUCTION CASING/LINER & Tubing DATA Casing/Liner Tubing Size (in) Weight (#/ft) Grade (ft KB) Casing 9 5/8" 47 7" LINER Tubing 3 1/ Well RESERVOIR & FLUID DATA Reservoir Temperature (deg F) 186 Water Cut (%) 20 SBHP (psig) 1940 API Gravity 38 Productivity Index (b/d/psi) 2.3 GOR 400 Well-head Pressure (psig) 140 Bubble Point (psig) 1500 Well-head Temperature (deg F) 110 Gas Gravity 0.77 Required flow rate (bpd) 1000 Water specific gravity

39 5.2 Calculation Step (1):- Calculate P wf PI 2.3 B / D / Psi P e 1940 Psi Calculate P wf? P wf P wf P e Q 1940 t BBL / PI 1000 / Psi Step (2):- Calculate average liquid gradient (ALG): ALG= (oil gradient*oil cut) + (water gradient*water cut) ALG 0.433* *oil cut 0.433* * Water cut oil API 0.433*0.835* *1.04*0.2 γ 141.5/ oil ALG ALG Psi/ft water P ρ D ρ (lb/gal) oil oil P / D ρ oil γ ρ / ρ oil oil WATER ρ γ *ρ oil oil WATER ρ 8.33 lb/gal WATER P / D 0.052* γ * ρ oil WATER P / D 0.433* γ oil Or Step (3):- Calculation Production liquid level (LD) LD Datume P /ALG wf Datume Bottom of Perfs - Top of Datume / ft LD / ,625ft perfs 39 2 Top of perfs

40 Step (4):- Calculation total tubing friction loss (TTFL) Read tubing friction loss (ft/1000 ft) from fig (1) By using (desired rate, tubing size) '' 1 Tubing Size 3 OD, '' ID 2 Q t 1000 B / D BBL / d Tubing friction loss Per =0/1000 ft TTFL=0 40

41 Step (5):- Change P th value in term of feet L P / ALG th th 140 / ft Step (6):- total dynamic head TDH LD TTFL L th ft Step (7):- Minimum Pump depth (MPD) Step (8):- select pump type from chart: Q t MPD Datum P P /ALG wf sat MPD / ft (B/D) 1,000 B / D N Pump type efficiency 1 DN Hz,400 series 50 % 2 DN Hz, 400 series 55 % 3 DN Hz, 400 series 54 % So we select pump with DN Hz,400 Series. Step (9):- Read the head (ft/stage) from Fig (2) by using Q t =1,000 B/D. ft / 100 Stage 2,300 ft / stage 23 41

42 Step (10):- Calculate number of stage:- TNS TDH / ft/stage 2994 / stage Step (11):- Read (HP/100 stage) from Fig by using Q t :- HP / 100 stage 30 HP / stage 0.3 HP 0.3TNS hp 42

43 DESIGN SPECIFICATIONS ESP Type (ft KB) Stages HP DN Motor Calculation: Fluid velocity beside the motor, Vf: Vf = 1.19 * ( ) =. 9 ( (. ) ( ) ) = 5 ft/s ID = Casing inside diameter. OD = Motor outside diameter. Voltage drop = 53 V = Surface voltage: Vs = Motor voltage + Voltage drop = = 2628 V Motor Amperes = 36 A KVA =. =. = KVA MOTOR SELECTION Vf Amp Vs KVA Cooling efficiency GOOD 43

44 5.3 Conclusions: From the study conducted using the manual procedure calculation as a method to design the more and the most sufficient suitable pump that can be used for oil artificial lifting. The following conclusion can be drawn: It has been found that the output results from such calculation methods are reliable method to design the pump for its purpose and applicable for this well. The gas lift was negligible because the lift was low effectiveness. The lift by ESP is attractive and more useful due to economic consideration. 5.4 Recommendations: Standard operating procedure should be followed to increase the ESP running life. The fluid velocity around the ESP s motor is very important for motor cooling system. Running and pulling of the ESP equipment should be handled carefully to avoid damaging the cable during trip. It is recommended to use ESP more than any other system to increase the production. 44

45 6. REFERENCE: 1. Artificial lift manual part 2A Gas lift design guide 2. Management of artificial lift systems ( shell co 1993). 3. ESP Design 9 steps from baker huges 4. Basic artificial lift Canadian oil well systems company ltd. 5. Artificial lift solutions. 6. Types of artificial lift methods from (Jonathan Bellarby.2009). 7. ESP general introduction from (Gabor Takacs.2009). 8. Figure (2.3) ESP pumps (From Schlumberger Website). 45