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1 Production Electrical Submersible Pumps Fundamentals Virtual Session 2 ESP Design Example Manual Design 1

2 Production ESP Design and Equipment Selection: Nine Steps** 1. Basic data 2. Production capacity 3. Gas calculations 4. Total dynamic head 5. Pump type 6. Optimum size of components 7. Electric cable 8. Accessories and optional equipment 9. Variable speed drive ** Centrilift Data Collection 1. Well Data Casing or liner size and weight API CASING 7 IN. O.D. 29 #/FT. (ID in, Drift ID in.) Set at 7100 Ft. Tubing size, type and thread:, API TUBING 2-7/8 IN. O.D. EUE 8 RD THREADS (NEW), 6.5 lb/ft. (ID in., Coupling OD in.) Perforated or open hole interval Ft. ( m) Pump setting depth (measured & vertical) 6500 Ft. ( m) Well Deviation Survey VERTICAL WELL 2. Production Data Wellhead tubing pressure 100 PSIG ( kpa) Wellhead casing pressure NA Present production rate Producing fluid level and/or pump intake pressure Static bottom-hole pressure 3000 PSI ( kpa) EST LIQ PI 1.4 BPD/PSI dp ( m 3 /d/kpa) Datum point 7000 FT ( m) Bottom-hole temperature 200 F (93 C) Desired production rate 2400 STBPD ( m 3 /day) Gas-oil ratio FGOR = 250 SCF/STB (44.5 m 3 /m 3 ) Water cut 80% 4. Well Fluid Conditions Specific gravity of water 1.06 Oil API or specific gravity 35 API Specific gravity of gas 0.75 (Air = 1.0) Bubble-point pressure 1250 psig ( kpa) Viscosity of oil PVT data 5. Power Sources Available primary voltage 12,470 VOLTS THREE PHASE Frequency 60 Hz Power source capabilities 6. Possible Problems Sand Deposition Corrosion Paraffin Emulsion Gas Temperature Other constraints (if any) NONE EXPECTED 2

3 Production Production Capacity Using the PI of 1.4 BPD/psi ( m3/d/kpa) calculate Pwf Pwf = 3000 (2400/1.4) = 1286 psi ( kpa) The Pwf > Pbp, hence use of PI method is good Calculate Pump intake pressure Fluid SG = (0.8*1.06)+(0.2*0.85) = 1.02 Pump intake pressure, PIP = Pwf {(Head, ft * SG)/2.31 ft/psi } PIP = 1286 {(500 * 1.02)/2.31} = 1065 psi ( kpa) As PIP<Pbp, there will be some free gas at intake Gas Calculations (1) ** Solution gas oil ratio (Rs) at pump intake: Substituting PIP (1065 psi) in place of Pb for pump intake conditions, Rs= 208 scf/stb Calculate Bo (FVF) using Rs found above using Standing eqn F = and Bo = 1.17 RB/STB **Note: The Rs and Bo at pump intake can also be estimated from Standing Correlation Charts or from PVT software packages of Nodal analysis. 3

4 Production Standing s Correlation Bubble Point Pressure Finding the Bubble Point pressure starting with Solution GOR Example: Example: GOR = 250 scf/stb GOR SG 250 scf/stb gas = 0.75 Oil SG gas Gravity 0.75 = 35 o API Oil BHT Gravity = 200 o F 35 o API BHT 200 o Standing s Correlation Bubble Point Pressure P bp = 1300 psia** **Pbp value already supplied as 1265 psia Using the Bubble Point correlation to estimate the GOR at pump intake Example: Example: GOR = = scf/stb GOR SG SG 250 scf/stb gas gas = = 0.75 Oil SG Oil gas Gravity 0.75 = = o API o API Oil BHT Gravity = = o F o 35 F o API BHT 200 o PIP = 1080 psia** 4

5 Production Standing s Correlation Oil Formation Volume Factor Gas Calculations (2) Finding Bo for pump inlet conditions Determine gas volume factor (Bg) as follows: Example: GOR = 250 scf/stb SG gas gas = 0.75 Oil Gravity = 35 o API BHT = 200 o F B o = 1.17 reservoir bbl/stb Assuming 0.85 Z Factor and using the reservoir temperature (200 F or 660 R at pump intake), Bg = (5.04*0.85*660)/1080= 2.62 bbl/mscf Volume of free gas at pump intake: TG = (STBOPD * FGOR)/1000 Mscf Tg = (2400*0.2) * 250 / 1000 = 120 Mscf/d Solution gas using Rs at pump intake, Sg = (STBOPD * Rs)/1000 = (480*208)/1000 = 100 Mscf/d Volume of free gas at pump intake Fg = Tg Sg = = 20 Mscf/d 5

6 Production Gas Calculations (3) Volume of oil (Vo) at pump intake Vo = STBOPD * Bo (RB/STB) = 480 * 1.17 = BOPD LS Volume of free gas at pump intake Vg = Fg Mscf * Bg bbl/mscf = 20 * 2.62 = 52.4 BGPD Vw = STBLPD * BSW = 2400*0.8 = 1920 BWPD Total volume of oil gas water at intake SK Vt = Vo + Vg + Vw = 2534 BFPD This is the volume the ESP should be designed for. IL Volume of water at pump intake Percentage of free gas present at pump intake, GVF O = (52.4/2534)*100 = 2%. Gas separator is not required (<10%) T PE TR Note: The reduction of composite fluid gravity due to presence of gas should be accounted for horsepower calculations if the gas fraction is high C O PY R IG H Frictional Head Loss Using Chart 6

7 Production Total Dynamic Head Calculate TDH (feet) as TDH = Hd + Ft + Pd For the Design Example: Assume Surface casing pressure : 0 psig Mid perf depth : 7000 ft. ( m) Pump set depth: 6500 ft. ( m) FLOP = 2410 ft. ( m) Dynamic fluid level, Hd : 4090 ft ( m) For 2534 BFPD and 2-7/8 new tubing, Pipeline frictional loss = 48*6.5 = 312 ft ( m) Ft = 312 ft ( m) Assume Flowing wellhead pressure = 100 psig ( kpa) Pd = 100 * (2.31/1.02) = 226 ft ( m) TDH = = 4628 ft. ( m) Pump Discharge Pressure Example: TDH = 4628 ft = 2048 psi ( kpa) PDP = PIP + Pump P PDP = = 3113 psi ( kpa) Depth, Ft TVD FWHP 100 psig Pressure (PIP) (PDP) 1065 psig 3113 psig 6500 Pump Depth 7000 (Pwf) 1286 psig Mid-perf Depth 7

8 Production Equipment Combination Sizing Options Pump Type Selection Preliminary Equipment Combination Selection Pump Size 538 Series (Pump OD: 5.38 in.) Protector Size 513 Motor Size P23 pump has good efficiency at 2550 BFPD Also take into account of Fluid characteristics, gas, viscosity; Well Conditions, Abrasives, Scale etc. Radial flow Type / Floater construction may be sufficient for this application 8

9 Production Pump Performance Curve Determination of Pump Stages From the Pump Curve Head = 51.5 ft ( m) per stage Number stages = TDH / (Head per stage) Number stages = 4628 / 51.5 = 90 stages Using pump technical data, a pump housing with 90+ stages should be selected From the Pump Curve Horse power = 1.5 HP per stage 9

10 Production Pump Housing Options Pump Housing Selection From the Pump Curve Head = 51.5 ft ( m) per stage HP = 1.5 HP per stage Number stages = TDH / (Head per stage) Number stages = 4628 / 51.5 = 90 stages Using pump technical data, Housing no.7 with 95 stages capacity will be selected Horse power requirement Brake Horse Power = BHP per stage * No. of Stages * Sp. gravity BHP = 1.5* 95 * 1.02 = 145 HP 10

11 Production Selection of Pump intake, Seal Sections Pump Intake: Separator not required for initial conditions Consider life of the well operations; include separator if needed and estimate HP requirements Select suitable pump intake if separator not needed Seal Section: Select 513 Series suitable seal section (housing OD: 5.13 in.) Add the HP required for the seal section and estimate total HP requirement Check Max Pressure / HP Limits Housing Burst Pressure Limit With closed discharge, head developed = 71 ft/stage Max head developed by pump = 71*95 = 6745 ft. ( m) Max pressure developed by pump = 2981 psi ( kpa) The pump housing pressure rating = 5600 psi ( kpa) Housing burst pressure limit not exceeded Shaft HP Pump and Gas separator HP limit = 360 HP (max for Standard shaft, 60 Hz supply) Actual = 145 HP Shaft HP limit not exceeded Check Seal / Protector Design Total thrust generated by pump = S/I Pump PSI x Shaft area = 2981 * sq in. (Shaft dia is 7/8 ) = 1793 pounds (813.3 kg) Make sure the selected seal can withstand beyond this limit 11

12 Production Selection of Motor Selection of Motor Select the high voltage (thus low current) motor that will have lower cable losses, thus requiring smaller conductor size cables For the well temperature (200 F), for the 60 Hz service, a 562 KMHJ Series should be sufficient Referring to the Technical Data on Motors, the next higher power motor is 161 HP Of the three options available for the 161 HP, the motor with 1406 Volts, 72 amps will be used All operating parameters are well within their recommended ranges (e.g. thrust bearing, shaft HP, housing burst pressure and fluid velocity). Single motor is sufficient 12

13 Production Selection of Cable Size Applying Temperature Correction 13

14 Production Electric Cable Size The proper cable size is governed by the motor amperage, voltage drop, and space available between the tubing collar and casing drift Guideline is to select a cable size with a voltage drop of less than 30 volts per 1,000 ft. (304.8 m) For the motor amps (72 A) Cable #2 has a voltage drop of 21 x 1.26 = 26.5 volts/1,000 ft. (304.8 m) and will be selected Selection of Cable Insulation Type Ranking of insulation materials Model Max T Min T Flat Insulation Jacket Application deg. F deg. F Round CTT F Thermoplastic Thermoplastic Shallow wells, Water wells, Low CO 2 Light ends CPN F/R Polypropylene Nitrile General CPL F Polypropylene Lead Gassy Wells, High CO 2 H 2 S CEN F/R EPDM w/tape Nitrile Low to Moderate Gassy Conditions CEE F/R EPDM EPDM Moderate Gassy w/tape, Braid CEB 300 or 400 R EPDM EPDM Gassy Wells w/extruded Fluropolymer CEL F/R EPDM Lead w/bedding Tape Hot Gassy Wells 14

15 Production Electric Cable Cable # 2 has been selected Estimated voltage drop of 26.5 volts/1,000 ft. (304.8 m) Insulation Spec: CENR (Centrilift EPDM, Nitrile, Galvanized Armor, Round): Size AWG KV Rating Nominal Dimension Weight in. (33.3 mm) 1.51 lb/ft (2.25 Kg/m) Surface voltage required = Nameplate voltage + Cable loss = (26.5*6.6) = 1581 V (using 100 ft cable more than the ESP set depth) Also calculate length of flat cable (MLE) required Accessories Accessories: The flat guards cable bands and other downhole accessories will be ordered Downhole gauge equipment Wellhead feedthrough A cable vent box must be installed between the wellhead and the motor controller to prevent gas migration to the controller Motor controller: KVA = (Surf voltage * Amps *1.732)/1000 = (1581*72*1.732)/1000 = The need for VSD should be investigated for current conditions as well as near future conditions and ordered as required Transformer and surface cable should be ordered 15

16 Production Recall - the surface set up options Switchboard Generation System high voltage Input power (11-15kV) Step-down Transformer V input at fixed frequency (50/60 Hz) Variable Speed Drive (VSD) Generation System high voltage input power (11-15kV) Step-down Transformer ESP Sizing Summary 380V or 480 V input at fixed frequency (50/60 Hz) Switchboard Variable Speed Drive 380V / 480 V output at desired frequency Step-up Transformer Junction Box Junction Box output voltage for ESP at desired frequency The basic ESP sizing process is as follows: 1. Assume a design flowrate (STB/day), water-cut, WHP, ESP setting depth and IPR 2. From the IPR, determine Pwf 3. Calculate upwards to find PIP 4. Calculate downwards from WHP to find PDP 5. Calculate pump P = PDP PIP 6. Pump TDH (ft) = Pump P / Fluid gradient (psi/ft) 7. Find average flowrate (Qpump) in pump (RB/day), this includes oil gas and water volumes, all in BBL/day 8. Select pump size from casing I.D. and pump operating range 9. From pump operating curves, read head per stage delivered at Qpump 10. Calculate no. of stages required = TDH / (head per stage) 11.From pump operating curves, read power required per stage at Qpump ESP ESP 16

17 Production ESP Sizing Summary (2) 12.Calculate total motor horsepower required = power per stage x no. of stages x fluid S.G. 13.Select appropriate protector (seal) configuration 14. Evaluate requirement for gas separator 15. Select voltage/amps combination for selected motor size 16.Select cable size from amps required 17. Specify cable protectors or banding for cable 18. Determine KVA rating of switchboard or VSD 19.Review the calculations if VSD is opted for, and make necessary changes 20.Order additional equipment (e.g., Wellhead feedthrough, Vent box, Downhole data package, etc.) as required Note: The completion will become more complex if a production packer / Y-tool or smart elements are included ESP Start up Precautions and Procedures 17

18 Production ESP Commissioning Precautions Unit to be started in a controlled manner and closely observed till it stabilizes Useful tools for monitoring: Downhole pressure sensor Surface pressure gauge and choke Historical settings: Overloads set at about 115% Under-loads at 80% Of the normal running current It may be necessary to adjust this during start up ESP Commissioning Guidelines 1. Set the in-line valves in the correct position 2. If the well is flowing before starting the unit, the flow must be stopped by closing the choke 3. If the well was killed using heavy kill fluid then the amperage will be high while pumping the high density fluid. The current has to be carefully monitored until the kill fluid has been removed from tubing 4. ESP turning in correct direction will be confirmed by surface pressure (pump should not be back-spinning) 5. If current is getting too high or fluctuating in a manner which is causing concern, then the motor should be shut down and the problem investigated 6. Test the well to know the producing rate Ensure pump is operating within the recommended operating range Control production rate using choke if required 7. Observe the parameters vs. time in a chart 18

19 Production Example: ESP Commissioning Chart Take Note of Shut-In Suction Pressure ESP Routine Start ESP Start Discharge Pressure 3000 First Indication Both Pressuresdecrease offlow Controlling Pressure with Choke Intake Pressure Wellhead Pressure Wellhead Temperature Current Current Wellhead Temperature Wellhead Pressure Intake Pressure Discharge Pressure If the unit was stopped, wait for 30 minutes before restarting Observe the ESP performance in the chart All data are important when starting units

20 Production Example: ESP Routine Start-up First Indication of Flow Normal RunningConditions Check Pressure has Equalised Min 30 Minutewait Session Summary ESP Start Controlling Pressure with Choke Current Wellhead Temperature Wellhead Pressure Intake Pressure Discharge Pressure The detailed design for ESP system was demonstrated with a well example Should accommodate the production requirements for a reasonable period (3-4 years). Possible changes production rate, GOR, water cut etc. during this period should be factored in Lot of communication and information-sharing between various teams of the operator and with the ESP supplier will be required The ESP commissioning / start up procedure was reviewed There is significant value in reviewing the ESP and well parameters together to achieve long run life and profitable operations ESP design to accommodate required flexibility Good surveillance required during start up and running of ESP