Production all Slides

BASICS OF PRODUCTION TECHNOLOGY : 

BASICS OF PRODUCTION TECHNOLOGY Petroleum Production Engineering

Slide 2: 

Petroleum Production System

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Petroleum Reservoirs Dissolved Gas Drive

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Gas-Cap Drive Petroleum Reservoirs

Slide 5: 

Water Drive Petroleum Reservoirs

Slide 6: 

Typical Producing Oil Well

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Wellhead Configuration

Slide 8: 

X-MAS Tree Configuration

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Producing Oil Wells – Mainly oil, Multiphase Flow Producing Gas Wells – Mainly gas, very high GOR Basics of Production Technology

Slide 10: 

A plumbing system connecting reservoir drainage boundary to the first stage separator at surface. Several Nodes are formed. Inflow Curve (IPR) Measures Reservoir Capacity to Produce. Outflow Curve (TIC) measures ability to lift fluid to surface. Inflow/outflow intersection provides solution point or natural flowing point. Wellbore Hydraulics (Nodal Analysis)

Slide 11: 

Basics of Production Technology Inflow vs. Outflow Curve

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Multiphase flow (Vertical/Inclined), known as Outflow or Tubing Intake Curve (TIC) Vs. IPR, known as Inflow. Basics of Production Technology

Slide 13: 

Actual Behaviour of P. I. Basics of Production Technology

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Typical performance curves for an active water-drive reservoir Basics of Production Technology

Slide 15: 

Typical performance curves for a solution gas-drive reservoir Basics of Production Technology

Slide 16: 

Typical performance curves for a gas-cap expansion-drive reservoir Basics of Production Technology

Slide 17: 

Combination of constant PI and Vogel Behaviour, when P r → P b Basics of Production Technology

Slide 18: 

Computer-generated Inflow Performance Relationships at various recovery percentage values for a solution gas-drive reservoir Basics of Production Technology

Slide 19: 

Concept of Productivity Index (P. I.) P. I. = Q / (P r – P wf ) Where , P. I. = Productivity index. Q = Total quantity of fluid. P r = Reservoir Pressure. P wf = Flowing bottom hole pressure. Now, Q  (P r – P wf )  Q = K (P r – P wf )  K = Q / (P r – P wf ) Where K is a constant, known as P. I. Basics of Production Technology

Slide 20: 

Inflow Performance VOGEL’S WORK ON IPR From general IPR equation i.e. J = q o / (P r – P wf ) ...............(1) When P wf = 0 , q o = q max That is J = q max / ( P r – 0) or J = q max / P r ............... (2) Contd......

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VOGEL’S WORK ON IPR Comparing equation (1) by (2), q o / q max = (P r – P wf ) / P r or q o / q max = 1 – ( P wf / P r ) since IPR curve below bubble point is not a straight line , he created a parabolic equation from the above. Contd....... Inflow Performance

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VOGEL’S WORK ON IPR He distributed {P wf / P r } in the following manner 20 % of { P wf / P r } & 80 % of {P wf / P r }² Therefore , the new equation is established as :- q o / q max = 1 – [0.2 × {P wf / P r }] – [0.8 × {P wf / P r }²] He then plotted dimensionless IPRs in two dimensional plane , where X- axis represents q o / q max and Y- axis represents P wf / P r Contd...... Inflow Performance

Slide 23: 

STANDING’S EXTENSION OF VOGEL’S IPR FOR DAMAGED OR IMPROVED WELL According to him, flow efficiency is defined as F. E. = actual drawdown / ideal drawdown = (P r – P' wf ) / ( P r – P wf ) ..... (1) Where, P' wf = P wf + Δ P skin Δ P skin defined by Van Everdingen is Δ P skin = Sq  / 2 k h Contd..... Inflow Performance

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Future IPR Prediction For planning future requirement of Artificial Lift, Surface and Down-hole equipment Basics of Production Technology

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Multiphase Correlations Usefulness of multiphase correlations Basics of Production Technology Flow Patterns

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Number of flow regimes may be divided into two broad divisions Where one phase is continuous. Eg ; Bubble, Spray & Froth flow. Liquid is the continuous phase in bubble flow, while gas is the continuous phase in the other two. Where both phases are continuous. Multiphase Flow

Slide 27: 

SINGLE PHASE FLOW Refers to one fluid medium only MULTIPHASE FLOW Refers to more than one fluid medium, for example Oil, Water and Gas. Single & Multiphase Flow

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MULTIPHASE FLOW HORIZONTAL FLOW VERTICAL / INCLINED FLOW STRATIFIED INTERMITTENT ANNULAR DISPERSED BUBBLE SMOOTH WAVY SLUG ELONGATED BUBBLE BUBBLE SLUG CHURN ANNULAR Multiphase Flow

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STRATIFIED SMOOTH FLOW Low gas & liquid flow rates – Phases separated by gravity STRATIFIED WAVY FLOW Same as above, with relatively high gas flow rate Fig 2.2A Fig 2.2B Multiphase Horizontal Flow

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INTERMITTENT SLUG FLOW Intermittent flow of liquid & gas – gas pockets develop ELONGATED BUBBLE FLOW Same as above; earlier than slug flow, when gas flow rates are lower Fig 2.2C Fig 2.2D Multiphase Horizontal Flow

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ANNULAR FLOW gas occupies central portion like a cylinder and liquid remains near the pipe wall; central portion entrains liquid droplets. occurs at very high gas flow rate. Fig 2.2E Multiphase Horizontal Flow

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DISPERSED BUBBLE FLOW At very high liquid flow rate, liquid phase is continuous & gas phase is dispersed all around liquid in the form of discrete bubbles. Fig 2.2F Multiphase Horizontal Flow

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BUBBLE FLOW Occurs at relatively low liquid rates. Multiphase Vertical/Inclined Flow

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SLUG FLOW Symmetric about the pipe axis Gas phase -like a large bullet shaped gas pocket with a diameter almost equal to pipe diameter Gas pocket is termed as “Taylor Bubble” Multiphase Vertical/Inclined Flow

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CHURN FLOW Similar to slug flow, though it is chaotic with no clear boundaries between the two phases. Flow pattern is characterised by oscillatory motion. Occurs at high flow rates; liquid slugs become frothy. Multiphase Vertical/Inclined Flow

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ANNULAR FLOW Liquid film thickness is almost uniform around pipe wall. Characterised by a fast moving gas core. Liquid film is highly wavy due to high interfacial stress. Multiphase Vertical/Inclined Flow

Slide 37: 

Effect of variables Line Size Flow Rate Gas-Liquid Ratios Water Cut Viscosity Slippage Kinetic energy term Multiphase Flow

Slide 38: 

Effect of Variables Pipe Diameter – Pressure loss ( dP ) decreases rapidly with increase in Pipe Diameter. Flow Rate – Higher flow rate increases dP GLR – Increased GLR increases friction, hence more dP , unlike to vertical flow. Viscosity – Viscous crude offers more problem in horizontal flow mode. Water Cut – Its effect is not pronounced. Slippage – Its effect is not pronounced. Kinetic Energy – For High flow rates & low density it is considered for computation. Multiphase Horizontal Flow

Slide 39: 

Effect of variables Tubing Size Flow Rate, Density Gas-Liquid Ratio Water Cut Viscosity Slippage ,Kinetic Energy term Inclination Angle Multiphase Horizontal Flow

Slide 40: 

Effect of Variables Tubing Size – It has pronounced effect in deciding FBHP requirement.. Flow Rate – It establishes the required FBHP, which influences tubing size selection. GLR – Increase GLR reduces FBHP requirement, after a point reversal takes place. Density – Higher density increases dP . Viscosity – Higher viscosity increases dP . Water Cut – Higher watercut increases dP . Slippage – It is observed during unstable flow region. Kinetic Energy – For High velocity & low density it is considered for computation. Multiphase Vertical/Inclined Flow

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FLOW CORRELATIONS HORIZONTAL FLOW VERTICAL FLOW INCLINED FLOW Multiphase Flow

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Assumptions Common to all Correlations Fluid must be free from emulsion. Fluid must be free from scale / paraffin build up. Mashed or kinked joints should not exist. Flow patterns should be relatively stable. No severe slugging should occur. Oil should not be very viscous. Multiphase Flow

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Multiphase Horizontal Flow

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Multiphase Vertical Flow

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Multiphase Inclined Flow

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Usefulness of Various Correlations Selecting tubing sizes. Predicting when the well will cease to flow. Designing of artificial lift. Determining flowing bottom hole pressures from the wellhead pressures. Determining the flowing bottom hole pressure, which in turn help in determining P.I. of the well. Predicting maximum flow rates possible. Predicting whether the well is able to flow as per the present & future profile . Multiphase Flow

Slide 47: 

Vertical/Horizontal Gas Flow Mostly gas with little oil. Flow of gas offers resistance to flow in both vertical and horizontal conduits & in that respect it differs from oil flow. Basics of Production Technology

Choke performance: 

Choke performance Wellhead chokes : - limit production rates for regulations - protect surface equipment from slugging - avoid sand problems due to high drawdown - control flow rate to avoid water or gas coning. Types of wellhead chokes : positive (fixed) chokes (2) Adjustable chokes

Slide 49: 

Single phase liquid flow through choke : C = flow coefficient ;C d = discharge coefficient

Slide 50: 

Flow coefficient is plotted against Reynolds number Choke flow coefficient for nozzle-type chokes

Slide 51: 

Choke flow coefficient for orifice-type chokes

Slide 52: 

Single phase gas flow through choke : For single phase gas flow, another parameter ‘Y’ is multiplied. Y is a function of -specific heat ratio (c p /c v =k) -diameter ratioof orifice throat to inlet pipe -ratio of downstream to upstream pressure Multiphase choke flow : Gilbert’s formula for critical flow condition : P wh = well head pressure, psig R = gas liquid ratio, Mscf/bbl q = liquid flow rate, STB/day S = choke size (1/64 inch)

Slide 53: 

SUCKER ROD PUMP − Prof. SSP Singh

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55 SUCKER ROD PUMPING (SRP) SYSTEM PUMPING UNIT MAIN PARTS DRIVING SHEAVE PRIME MOVER GEAR REDUCER DRIVEN SHEAVE VEE BELT CRANK PITMAN WALKING BEAM SAMPSON POST UNIT BASE HORSEHEAD BRIDDLE CARRIER BAR

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Reciprocating Rod Lift system Applications Virtually all applications, including sandy, gaseous, and high viscosity Wide range of fluid levels from near surface to seating nipple depth Low to medium volume lift capabilities All types of wells, including horizontal, slant, directional and vertical reservoir Industry standard for On land and remote applications

Slide 59: 

Rod Lift System Application Considerations Insert table Slide 3 of 12 Typical Range Maximum Operating Depth 100 - 11,000’ TVD 16,000’ TVD Operating Volume 5 - 1500 BPD 5000 BPD Operating Temperature 100° - 350° F 550° F Wellbore Deviation 0 - 20° LandedPump 0 - 90° Landed <15°/100’ Build Angle Corrosion Handling Good to Excellent w/ Upgraded Materials Gas Handling Fair to Good Solids Handling Fair to Good Fluid Gravity >8° API Servicing Workover or Pulling Rig Prime Mover Type Gas or Electric Offshore Application Limited System Efficiency 45%-60%

Slide 60: 

Reciprocating Rod Lift System Advantages High system efficiency Optimization controls available Economical to repair and service Positive displacement/strong drawdown Upgraded materials reduce corrosion concerns Flexibility - adjust production through stroke length and speed High salvage value for surface & downhole equipment

Slide 61: 

Reciprocating Rod Lift System Limitations Potential for tubing and rod wear Gas-oil ratios most systems limited to ability of rods to handle loads – volume decreases as depth increases Environmental and aesthetic concerns

Slide 62: 

Reciprocating Rod Lift Systems Conventional Pumping Units Long-Stroke Pumping Units Low-Profile Pumping Units Nitrogen-Over Hydraulic Units Rod Pumps & Accessories Sucker Rods

Slide 63: 

Conventional Pumping Units Production rates up to 3,000 barrels per day. Well depth to 16,000 feet. High overall system efficiency (electrical and mechanical). Very low lifting cost per barrel. Runs on natural gas, propane, diesel or electric power.

Slide 64: 

Long-Stroke Pumping Units First successful long-stroke pumping unit in 40 years 24 foot stroke length for sucker rod pumps High production capability High system efficiency and cost effectiveness for deep, troublesome and high-volume wells Use in place of electric submersible or hydraulic subsurface pumps

Slide 65: 

Low Profile Pumping Units Reducer sizes 114 up to 320 Low profile and OVP (slanthole) models available Naturally compact, low height High efficiency geometry High well clearance Low internal structural stresses Folding roller post

Slide 66: 

Nitrogen-Over-Hydraulic Units Developed for fields with heavy crude oil, wells with rod fall problems and better well control. Lifts greater loads using less energy Handles PPRL’s up to 40,000 lbs. Pumps depths to 10,000 ft. Changes strokes per minute with turn of a switch in either direction Srokes per Minute can be as slow as 0 and as fast as 9 (depending on model)

Slide 67: 

Rod Pumps Variety of API pumps & accessories - heavy wall - thin wall combination heavy wall/stoke through Speciality pumps - three-tube - hollow-valve - large volume stroke through - sandy fluid

Slide 68: 

Sucker Rods Continuous Corod® Sucker Rods API Sucker Rods Ultra High-Strength EL® Sucker Rods High-Strength XD Sucker Rods Sucker Rod Couplings.

Slide 69: 

69 GENERAL WELL DESIGN

Slide 70: 

70 SUCKER ROD PUMPING (SRP) SYSTEM OPERATION OF PUMPING SYSTEM PRIME MOVER LOW R.P.M POLISHED ROD REDUCTION GEAR BY VEE BELT ROTARY MOTION CONVERTED TO LINEAR MOTION THROUGH SUCKER ROD SUB-SURFACE SUCKER ROD PUMP OIL PRODUCTION

Slide 71: 

71 SUCKER ROD PUMPING (SRP) SYSTEM TYPES OF SUB SURFACE SUCKER ROD PUMPS INSERT (ROD PUMP) STATIONARY BARREL TOP HOLD DOWN STATIONARY BARREL BOTTOM HOLD DOWN TRAVELLING BARREL TUBING PUMP

Slide 72: 

Tubing Pumps vs. Insert Pump Tubing Pumps Barrel Assembly of this type pump is screwed onto, and becomes part of the tubing. Larger bore than a rod pump, thus it produces a greater volume of fluid in any give diameter of tubing Insert Pump The complete pump is attached to, and inserted into the well tubing with the sucker rod string. As a complete unit, this pump may be pulled out of the well without pulling the tubing.

Slide 73: 

Rod Pump Operation - Concept Visualization of Rod Pump Working (A) Pump grabs a “bite” of fluid on each downstroke of the pump, as the “mouth” of the traveling valve opens on the downstroke, and grabs a bite of whatever is within the compression chamber. (A) (B) (C)

Slide 74: 

Rod Pump Operation - Concept Visualization of Rod Pump Working (B) Upstroke closes the traveling valve, traps the fluids in the chamber and physically lifts them up the well a few feet. This bite is simply stacked below the previous bite until enough bites start running out at the surface of the well. (A) (B) (C)

Slide 75: 

Rod Pump Operation - Concept Visualization of Rod Pump Working (C) Standing Valve opens at the start of upstroke to admit fluids into the compression chamber from the reservoir, and closes on downstroke of pump to prevent these fluids from returning to the formation. (A) (B) (C)

Slide 76: 

Double Traveling Valve & Standing Valves Advantages Disadvantages Extra set of valves offer backup seal in the event of trash or valve wear. Extra set of valves reduces the un area in the pump, which reduces the compression ratio, thus limiting the pumps ability to handle gas. More parts = more expensive pump

Slide 77: 

Solutions to “Well” Known Problems Gas Locking Sand Problems Heavy Oil

Slide 78: 

What is Gas Locking? Gas Lock Occurs when a barrel is completely filled with Gas. Gas can not be compressed enough to overcome the Hydrostatic head acting on the traveling valve. Consequently both valves remain closed and the pump is gas locked.

Slide 79: 

Gas Locking vs Gas Interference vs a Pumped Off Condition (A) Gas Locking No valves open during pumping cycle. No fluid lifted to surface. (B) Gas Interference Valves function properly, but reduced efficiency as gas takes place of some fluid. (C) Pumped Off Condition Pumping rate exceeds ability of fluid to flow into pump. Well does produce some fluid. (A) (B) (C)

Slide 80: 

Rod Pump Gas Locking Not enough pressure generated in compression chamber on down stroke to open traveling valve. Produced fluid in tubing rides up and down with traveling valve, which is not opening. CAUSES EFFECTS No fluid produced to the surface. Fluid level on backside continues to rise as no fluids are removed from well.

Slide 81: 

Rod Pump - Gas Locking SOLUTIONS Increase compression ratio in pump through better design/assembly. Increase compression ratio in pump through longer stroke or smaller plunger. Install II stager valve to remove hydrostatic pressure from traveling valve. Reduce gas intake into pump through better down hole separation. Increase pump intake pressure by allowing higher fluid level on backside.

Slide 82: 

Rod Pump Gas Interference Poor gas separation, prior to fluid entering the pump, allows gas to take the place of fluid in the compression chamber. Pump shows poor efficiency because only fluid is being measured. Pump is actually operating properly, but fluid production is limited by gas in pump. CAUSES EFFECTS Separate gas from fluid before it gets to pump intake through better down hole separation. Increase rate of well by lengthening stroke, changing strokes per minute or changing bore size. This increases both gas and fluid which are produced through the pump. SOLUTIONS

Slide 83: 

Combating Gas Locking Gas Breakers Two Stager Gas Compression Valves Gas Compression Plugs Sliding Top Valve

Slide 84: 

Conventional (Poor Boy) Gas Anchor

Slide 85: 

What causes Sand Problems? Sand can come from the reservoir or a sand-Frac. If sand is present from a sand-Frac, it is usually a temporary problem that will clear itself as the well is pumped. If the sand is from the reservoir the problem will be ongoing and special attention must be given to the design of the pump and its material selection.

Slide 86: 

How do you Minimize Sand Problems? Pressure-Actuated Plunger Combo Plunger Actuated Plunger Chrome Plated Grooved Plunger Sand Hogg 3-Tube Pump

Slide 87: 

Designs to Handle Solids Best Particulate Producers Traveling Barrel Pump , Top Holddown Pump,& Tubing Pump Stroke Through Pump Short Barrel, Long Plunger Special Pumps 3 Tube Pump Others Bottom Discharge Valve, Top Seal Assembly & Plunger Wipers

Slide 88: 

Sandy Fluid/ Pampa Pump Traveling barrel pump designed for use in wells where abrasive or dirty fluids are produced. Pump has a smooth plunger which extends through a relatively short hardened-liner section Due to length of Plunger, the ends do not enter the liner section at either the top or bottom of the stroke Plunger is wiped clean on each stroke, and foreign material (sand, etc) is not carried into the liner. When Pump is shut down, the Traveling valve on top of the pump serves as check valve.

Slide 89: 

System and Equipment Overview Electric Submersible Pumping Systems Prof. SSP SINGH

Electric submersible pumping systems: 

Electric submersible pumping systems A high-volume production tool that can operate in extremely deep wells. Consist of a rotating, highly engineered series of components. Demands very little surface space and can operate in highly deviated wells. When properly designed each system requires little or no maintenance during its run life.

Centrifugal Pump: 

Centrifugal Pump Connected and driven by the motor via the shaft connection of the seal and gas separator Pump consists of stages that move the fluid through the pump and up into the production string - Each stage consists of 1 impeller and 1 diffuser - The impeller is the driver of the fluid while the diffuser directs the flow.

Centrifugal Pump: 

Centrifugal Pump Impeller Impellers are connected to the pump shaft and turn when the motor is on. Impeller transfers the fluid upward to each impeller above it, through the pump discharge and into the production string. Each impeller is housed within a diffuser. The diffuser directs the flow of the fluid from each impeller

Electric Submersible Systems : Application Considerations: 

Electric Submersible Systems : Application Considerations Typical range maximum Operating depth 1,000’ - 10,000’ TVD 15,000’ TVD Operating volume 200 - 20,000 BPD 30,000 BPD Operating temperature 100° - 275° F 400° F Wellbore deviation 10° 0 - 90° Pump Deviation Placement - <10° Build Angle Corrosion Handling : Good Gas Handling : Fair Solids Handling : Fair Fluid Gravity : >10° API Servicing : Work over or Pulling Rig Prime Mover Type : Electric Motor Offshore Application : Excellent System Efficiency : 35%-60%

Electric Submersible Pumping System : Advantages: 

Electric Submersible Pumping System : Advantages High Volume and Depth Capability High Efficiency Over 1,000 BPD Low Maintenance Minor Surface Equipment Needs Good in Deviated Wells Adaptable to All Wells With 4- 1/2” Casing and Larger Use for Well Testing

Electric Submersible Pumping System : Limitations: 

Electric Submersible Pumping System : Limitations Available Electric Power Limited Adaptability to Major Changes in Reservoir Difficult to Repair In the Field Free Gas and/or Abrasives High Viscosity Higher Pulling Costs

Surface equipment: 

Surface equipment Surface Control Board (SB) or Variable Speed Controller (VSD) Vented Junction Box Wellhead

Wellhead: 

Wellhead Attached to top of casing Holds production tubing that holds the submersible system in the casing annulus. Allows power cable to pass through and into the well Tight seal around the cable preventing production fluids from leaking out of the well Allows produced hydrocarbons to pass from the production tubing to the surface flow line.

Down hole Equipment: 

Down hole Equipment Electric motor Seal section Gas separator: Not Shown Centrifugal pump Motor extension lead Down hole Power Cable

Electric Motor: 

Electric Motor A two-pole three-phase induction motor that rotates an internal shaft. Nominal speeds - 3450 rpm / 60 hertz or 2916 rpm / 50 hertz Filled with a light mineral oil that is required for lubrication and cooling During operation the oil in the motor heats up and expands. The excess oil travels from the motor up and into the seal section. When the system is idle the oil cools, condenses, and is drawn down from the seal back into the motor. REMINDER : Motor must be completely filled with oil at all times.

Seal Section: 

Seal Section Connected above the motor Motor shaft and seal shaft connected via a coupler. Acts as oil reservoir for motor Contains a thrust module that absorbs thrust generated by the shafts of the gas separator and pump .

Power Cable: 

Power Cable Power cable transmits electrical current from the surface to the down hole system. Begins at the transformers Passes through the surface controller, junction box and wellhead Attached to the production tubing and run the entire length of the well into motor.

Gas Separator: 

Gas Separator Separates and removes free gas from the hydrocarbons. Gases are discharged through a series of passages/ports into the annulus. Assembled between the seal section and centrifugal pump Separator shaft is connected to the seal shaft below and the centrifugal pump shaft above. All connections use couplings.

DESIGNING ESP SYSTEM: 

DESIGNING ESP SYSTEM

: 

The pressure increase is usually expressed as pumping head, the equivalent height of fresh water that the pressure differential can support.

Certain operating variables can severely limit ESP applications. These are : : 

Certain operating variables can severely limit ESP applications. These are : - Free gas in oil - Temperature at depth - Viscosity of oil - Sand content fluid - Paraffin content of fluid

The following factors are import to know for designing an ESP application: : 

The following factors are import to know for designing an ESP application: -P.I of well -Casing and tubing sizes -Static liquid level

Slide 108: 

The following procedures can be used for selecting an ESP : (1) Starting from well IPR, determine a desirable liquid production rate Q Ld . Then select a pump size from manufacturer’s specification that has a minimum delivering flow rate Q Lp , i.e., Q Lp > Q Ld . (2) From the IPR, determine the flowing bottom home pressure Pwf at the pump-delivering flow rate Q Lp , not the Q Ld .

Slide 109: 

(3) Assuming zero casing pressure and neglecting gas weight in the annulus, calculate the minimum pump depth by Where D pump = minimum pump depth, ft D = depth of production interval, ft P wf = flowing bottom hole pressure, psia P suction = required suction pressure of pump, 150 –300 psi γ L = specific gravity of production fluid, 1.0 for fresh water.

Slide 110: 

(4) Determine the required pump discharge pressure based on wellhead pressure, tubing size, flow rate q Lp , and fluid properties. This can be carried out quickly using the computer spreadsheet HagedornBrownCorrelation.xls. (5) Calculate the required pump pressure differential and then required pumping head by Eq (3-1).

Slide 111: 

(6) From manufacturer’s pump characteristic curve, read pump head or head per stage. Then calculate required number of stages. (7) Determine the total power required for the pump by multiplying the power per stage by the number of stages.

Slide 112: 

A 10,000-ft-deep well produces 32°API oil with GOR 50 scf/stb and zero water cut through a 3-in. (2.992 in. I.D.) tubing in a 7-in. casing The oil has a formation volume factor of 1.25 and average viscosity of 5 cp. Gas specific gravity is 0.7. The surface and bottom hole temperatures are 70°F and 170°F, respectively.

Slide 113: 

System & Equipment Overview Prof. SSP SINGH PROGRESSING CAVITY PUMPING SYSTEM

Operating Principle: 

Operating Principle As the rotor turns eccentrically in the stator, a series of sealed cavities form between the stator and rotor surfaces to move fluid from the intake to the discharge end of the pump. The differential pressure between the pump intake and discharge provides the lift necessary to move produced fluid to the surface. The result is a non-pulsating positive displacement flow with a discharge rate proportional to the rotational speed of the rotor and the differential pressure across the pump.

Progressing Cavity Pumping System: Advantages: 

Progressing Cavity Pumping System: Advantages Low Capital Cost Low Surface Profile for Visual and Height Sensitive Areas High System Efficiency Simple Installation, Quiet Operation Pumps Oils and Waters with Solids Low Power Consumption Portable Surface Equipment Low Maintenance Costs Use In Horizontal/Directional Wells

Progressing Cavity Pumping System: Limitations: 

Progressing Cavity Pumping System: Limitations Limited Depth Capability Temperature Sensitivity to Produced Fluids Low Volumetric Efficiencies in high-Gas Environments Potential for Tubing and Rod Coupling Wear Requires Constant Fluid Level above Pump

Progressing Cavity System Application Considerations: 

Progressing Cavity System Application Considerations Typical Range Maximum Operating depth 2,000 --4,500’ TVD 6,000’ TVD Operating volume 5 - 2,200 BPD 4,500 BPD Operating temperature 75 -150° F 250° F Wellbore deviation N/A 0 - 90° Landed Deviation Pump - <15°/100’ Build Angle Corrosion Handling : Fair Gas Handling : Good Solids Handling : Excellent Fluid Gravity : < 35° API Servicing : Work over or Pulling Rig Prime Mover Type : Gas or Electric Offshore Application: Good (ES/PCP) System Efficiency : 40%-70%

Wellhead Surface Drives: 

Wellhead Surface Drives Supplies the necessary speed and torque to down hole PC pump by suspending and rotating a drive string. The drive string is typically made up of conventional or Corod® continuous sucker rods. Several models available to accommodate various applications Direct electric motor drives Direct gearbox drives that may be coupled to an electric motor or gas engine Hydraulic drive systems for both gas and electric applications

Slide 121: 

Operating Issues and Concerns Prof. SSP SINGH PROGRESSING CAVITY PUMPING SYSTEM

Operating Concerns Heavy Oil: 

Operating Concerns Heavy Oil Flow Losses Due to high viscous fluid. Increases; horsepower, torque, discharge pressure. Solution Use large diameter tubing (Note: if producing sand, flow velocities must be maintained) Inject diluents to decrease fluid viscosity.

Operating Concerns Heavy Oil: 

Operating Concerns Heavy Oil Sand Production Important part of production Abrasive action accelerates wear of pump, tubing & rod string Increased H.P. & Torque requirements Restricts pump inlet Tubing blockage due to low transport velocities Design system to allow for slugs

Operating Concerns Heavy Oil: 

Operating Concerns Heavy Oil Solution To increase tubing flow velocities – decrease tubing size – inject fluid down annulus & pump @ higher rates To reduce wear to pump – decrease rotor stator interference fit – increase number of pump stages – use softer more resilient elastomer – operate at lower speeds To dissipate sand slugs – extend rotors, run booster pump

Operating Concerns Heavy Oil: 

Operating Concerns Heavy Oil High Viscosity Fluid Pumps operate @ rates which are higher than fluid can flow into the pump cavity Solution To decrease flow velocities through pump – use large displacement pumps – reduce speed @ which cavities open and close (rpm) Reduce fluid viscosity by injecting diluents down the annulus

Operating Concerns Medium Oil: 

Operating Concerns Medium Oil Aromatics (benzene, toluene, xylene) Swelling, softening and decline in mechanical properties of the elastomer. Swelling results in tight rotor/stator interference fit and decrease in volumetric efficiencies Tight interference fit results in high pump friction, torque and horsepower requirements Solution Custom fit, match elastomer to wellbore fluids

Operating Concerns Medium Oil: 

Operating Concerns Medium Oil H 2 S and CO 2 Creates weak acids that accelerate corrosion Extended vulcanization in elastomer causes: – decline in mechanical properties – high pump torque and decrease in volumetric efficiency CO 2 oxidizer, affects mechanical properties Solution Match elastomer to wellbore fluids Use corrosion inhibitor (elastomer compatible)

Operating Concerns Medium Oil : 

Operating Concerns Medium Oil Gas Production Incomplete pump fillage. High operating temperatures Solution Sump pump below perforations Use downhole gas separation equipment

Operating Concerns Light Oil: 

Operating Concerns Light Oil Highest Aromatic, H 2 S and CO 2 Concentrations High G.O.R’s Same operating concerns as medium oil

Operating Concerns Water: 

Operating Concerns Water Abrasive Solids Frac. & coal fines damage stator Fluid velocities must transport solids Large particles can seize pump. Solution Sand screens and slotted tag bars reduce amount and size of solids entering pump

Operating Concerns Water: 

Operating Concerns Water Dissolved Solids Precipitant, forms scale on production equipment Scale build-up creates restrictions in tubing and flow lines – increased horsepower and torque requirements Solution Chemicals to stop precipitation of dissolved solids – Note: Should be compatible with elastomer

Operating Concerns Water: 

Operating Concerns Water Gas Production Same concerns as other applications H 2 S and CO 2 Same concerns as other applications