102.1 Beam Components

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Beam Pump p Components Show beam system Show system y component p by y component p Show functionality of each component Show nomenclature of each component to assist with following sections on Design, Analysis and Trouble Shooting.

Beam Pump Components S f E i t Surface Equipment – – – – – – – –

Units Wellhead Polished Rods Motors Gearbox Sheaves B lt Belts Transformers

Downhole Equipment – Pumps – Rods – Tubing

Production Optimization – – – – –

Pump cards P d Valve checks Pump Off Controller Power Measurement Downhole sensors ®

2

Pressure Profiles: Tubing / Casing

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3

Surface Units Types of units Designations L di Loading Design considerations Maintenance Conventional Unit

Mark Unit ®

Air Balance Unit 4

Tower, Hydraulic Units Tower

Long Stroke, more efficient ®

Hydraulic

Easy to control speed of up/down stroke 5

Smaller Hydraulically Powered Units: These used for CBM wells and other.

Dynapump

Dynasave

Economizer

VSH2

Economizer has no noticeable motion at surface All are predicted to give more surface. required surface maintenance than regular beam pumps. Details on all in report.

VSH2mini ®

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Unico LRP

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Multiple Zone Beam Completions

Two – in - One

Three – in - One

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Surface Unit Nomenclature

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Surface Unit Nomenclature

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Surface Unit Pumping Unit Designations PK TORQUE RATING IN

MAXIMUM STROKE LENGTH IN INCHES

THOUSANDS OF IN-LBS

C-228D-246-86 A- AIR BALANCE

B – BEAM BALANCE C – CONVENTIONAL M – MARK II

POLISHED ROD RATING IN 100’S OF LBF’S

LP – LOW PROFILE RM – REVERSE MARK ®

See API Specification 11E 11

Surface Unit C-912D-365-168 Conventional Unit

168”

912,000 in-lbs.

36500 lbs.. lb Well on right: Designate CCW or CW rotation rotation. Cranks fall towards Sampson Post is called positive rotation as well. Negative for falling away from Sampson Post ®

12

Motors Oil Field Motor Types ~Efficiency y Full Load

SLIP

NEMA B

~92+

NEMA C

TYPE

APPLICATION

2-3%

STARTING TORQUE 100-175%

~90+

4%

200-250%

POSITIVE DISPLACEMENT INJECTION PUMPS

NEMA D

~88%

8-13%

275%+

BEAM PUMPS

ULTRA HISLIP

Lower

15-30%

275%+

SPECIAL APPLICATION BEAM PUMPS

TRANSFER PUMPS

SLIP=( No-load RPM – RPM under load) / (No-load RPM) J. Lea, Texas Tech University ®

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Motors Torque Curves for Motors

Motor Performance Curve 5 hp, p, 1120 rpm, p , 220/440 V, 66/33 Amps, 3 Phase, 60 Hz NEMA D, Squirrel Cage Induction Motor ®

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Motors Balanced vs. Unbalanced Motor – Torque (in-lbs) or kW (power) signatures of an electrically or mechanically y unbalanced or balanced p pumping p g unit: – Balanced if the peak upstroke torque is equal to the peak down stroke torque.

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Motors Two main methods for determining motor HP – Both based on calculating Polished Rod Horse Power (PRHP)

Computer Sizing

CLF × PRHP Motor HP = U it Efficiency Unit Effi i

Or

Gault Method

Motor HP = 2 × PRHP CLF = RMS Current/ Average Current ~ RMS T Torque// Average A Torque T ~ RMS Power/ Average Power ®

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Sheaves and Gearbox The speed of a motor in RPM can be calculated from Speed (rpm) =

Frequency ×120 No of poles

Typically beam pump motors are running 1200 or 1800 rpm Need a method to reduce speed p to get g down to approx 10 SPM Use ratio of sheaves and gearbox ®

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How Sheaves and GB Reduce Speed

47” dia di 1170 RPM

298.7RPM 30.12 GB Ratio =9.92 SPM

12” dia

1170 x 12”/47” = 298.7 RPM GB Ratio: R ti 30.12 30 12 ®

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SPM Problem

Problem –A bea beam pu pump p has as a motor oto sheave of 10 inches OD (254mm). The gear-box gear box sheave is 34 inches (863.6mm). The gear box is typical. The motor is a gas engine turning at 500 rpm average speed. What is the SPM (strokes per minute) of the pumping unit? ®

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Belts Purposes of belt drive – Adds additional speed reduction – Change pumping speed – Soft link in drive train – Moves motor away from cranks

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Gearbox Most expensive part of unit Reduces rpm and increase torque – out/in by ~30:1

Requires servicing Can last 20-30 + years with care Do not overload by design g or operation p

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Gearbox Factors Affecting GB Torque and Polished Rod Loading Gearbox should be loaded at least 50% % to p prevent low efficiency Factor

Polished Rod Load

Gearbox load

Increase rod string weight

Increases PRL

Increases load

Increase stroke length

Minimal Effect

Increases load

Increase pump diameter

Increases PRL

Increases load

Increase SPM

Increases PRL

Increases load

Out of balance

Increases PRL

Increases peak load

Pump off well

Increases PRL

Increases peak load

Oversized Motor

Increases PRL

Low Efficiency

Pump off well

Increases PRL

Increases peak load

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Wellhead Flowing/pumping well Stuffing box Bl Blow outt preventer t Gas side check valve Gas must be allowed from casing back to flowline through check valve l Flowline pressure

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Wellhead Flowing vs. Pumping Well: Contrast the Two

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Polished Rods The polished rod is the connecting link between the surface pumping unit and the downhole rod string. It’s surface is ground to close tolerances and has an extremely smooth surface to provide a sealing surface for the elastomer seals (packing) that allow vertical movement of the polish rod rod.

Recommended PR sizes: Size of sucker rod

Size of polished rod

5/8 inch

1-1/8 inch

¾ inch

1/1/8 inch

7/8 inch

1-1/4 inch

1 inch

1-1/2 inch ®

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Polished Rods • Polished Rod Liners • Use polish rod or liner to connect rods through stuffing box:

Use sucker rod coupling Use PR coupling ®

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Tubing Ranges from 1.05” to 4.5” Pick appropriate size based upon casing size and production Most common sizes for beam pumping are2-3/8’s and 2-7/8’s The “most expensive” failure for a downhole beam pump system failure. Set pump intake below the perfs or as low as possible Install an internally coated joint above seat nipple Decision TAC,, gas g anchor,, mud anchor, de-sander, etc. ®

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Tubing Seamless Tubing Construction – Advantages: less susceptible to corrosion – Disadvantages: more expensive than ERW ERW, and less available

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Tubing Electro Resistance Welded (ERW) Tubing Treating Choices – – – –

Non-Normalized Seam Annealed Full Body Normalized (FBN) Full Body Normalized after upsetting (Best choice for H2S Service))

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Tubing Tubing Grades – Wide variety from H-40 (40 ksi min yield) to P-105 – More strength means more potential problems with corrosion – Most commonly used for rod pumping: J-55 and H-40 – J-55 is good choice considering both strength and corrosion

H2S Precautions – – – –

Max grade of L-80 Do not use N-80 or P-105/110 Specify full body normalization after upsetting In general high strength rods are not a good choice with H2S presence ®

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Tubing Connections – External upset (EUE) with Beam – Non-Upset (NU) – Integral Joint (IJ) – Special/Premium thread ¾ Sometimes used when CO2 high for instance

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Tubing Use of Used Tubing – – – –

Green Band tubing: 30-50% wall loss Blue Band tubing: 15-30% wall loss Yellow Band tubing: 0-15% wall loss Could use in 1/3’s 1/3 s of length of well well, Green Band at the top, Blue Band in middle, and Yellow Band or new tubing at the bottom. This for a well where wear is a problem. – Even with 50% wall loss, the tensile strength is still good for applications to 5000’ 5000 .

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Tubing Movement with No Anchor Tubing movement and buckling with no anchor Guidelines for Anchor: Set near pump Set above perforations Set within 200’ of seating nipple Set 2 joints above seating nipple if pumps stick A tension anchor preferred Calculate tubing pickup Calculate min hookload for shear pins on each anchor Use proper tubing grade to facilitate possible worst case scenario ®

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Tubing Anchor Determine Tension to Set Anchor: On Disk

Buckling of Tubing in Pumping Wells, Its Effects and Means for Controlling It. Arthur Lubinski, K. A. Blenkarn; AIME Transactions V l 210, Vol 210 1957 1957, Ch Chapter t 3 3, V Volume l 1 Programmed by S. A. Wong

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Tubing Failures Acid Producing Bacteria

Rod Guide Wear

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Tubing Failures

Pump p Joint – Protruding g ERW Seam

T bi - Pump Tubing P J i t - Stagnant Joint St tA Area ((non coated) t d) Preferential Corrosion Along Seam ®

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Sucker Rods Sucker rods nominally consist of 25 foot joints (30 ft in California) with a th threaded d d pin i (male) ( l ) connection on both ends. Manufacturers furnish a th threaded d d coupling li (female (f l on one end of each rod).

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Sucker Rods API Specification 11b: Specification for SR’s Couplings and Subcouplings FRP (Fiberglass) Sucker Rods St l S Steel Sucker k R Rods d – Grade C – Grade K – Grade G d D Carbon, C b Grade G d D Alloy All and d Grade G d D Special S i l Alloy (KD) Polished Rods P li h d Rod Polished R d Clamps Cl Sinker Bars Stuffing Boxes and Pumping Tees

N i Norris ®

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Sucker Rods Connections

Coupling

Wrench Flats

Sucker S k R Rod d Body

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Sucker Rods API 86 Rod String 8/8 1 5” P 1.5” Pump - 26.8%, 26 8% 27% 27%, 46 46.2% 2%

API Grade Rods Equal Stress?

C - 90,000 psi min. tensile 7/8

Not equal stress. Instead equal tendency to fail from g fatigue.. Goodman Diagram

K - 90,000 psi min. tensile D - 115,000 psi min. tensile

6/8

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High strength rods - 140,000 140 000 psi min. min tensile

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Sucker Rods Common Rod Grades – Grade C rods are designed for light to medium loads (less than 25,000 psi fully loaded) in shallow to medium depth wells and non-corrosive or effecti el inhibited well effectively ell flfluids. ids – Grade K rods are designed to work under the same loading conditions as C rods where corrosion is a problem and must be effectively inhibited. – Grade D rods are designed for medium to heavy loads (up to 30,000 psi) or deep wells with non-corrosive or effectively inhibited well fluids. – KD rods are designed to be used where D rods are needed to handle the loads but a higher level of corrosion resistance is required. – High strength rods not covered by API grades but were designed to handle extremely heavy loads (up to a maximum of 50,000 psi without a safety f factor) f ) at any operating depth where corrosive fluids f can be inhibited.

corrosion. ®

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Sucker Rods / Corrosive Conditions Non-corrosive well fluid types are classified as follows: Well fluids that have less than 25% water cut and a pH of 7.0 and above. Well fluids that are effectively, effectively chemically inhibited inhibited, monitored and documented. Consider installing Type 30, Type 54, Type 78, or Type 97 sucker rods where corrosion is not a problem. The specific type sucker rod must be determined by the design loading conditions. Acid Gas Corrosion H d Hydrogen S Sulfide lfid (H2S) (H2S), either ith as a gas or ffrom b bacterial t i l activity ti it iin b brine, i iin any amount. Carbon Dioxide (CO2) as a gas between a partial pressure of 7 psi (.048 Mpa) p ) to 30 p psi ((.207 Mpa), p ), or between 600 pp ppm and 1200 pp ppm in brine. Consider installing Type 40 or Type 90 sucker rods for service in corrosive fluids. The specific type sucker rod must be determined by the design loading conditions. corrosion. ®

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Sucker Rods Rod Stress / Strain Curve – Sucker Rods should operate in the linear portion of the stress vs. stain curve and never receive permanent deformation – However, fatigue will be shown to be the design g consideration for continuous operation.

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Sucker Rods Original Goodman Fatigue Loading Diagram

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Sucker Rods Construction of Modified Goodman Diagram T Sa = (T/4+ .5625(Smin))(SF)

ΔSa= Sa – Smin Sa= max allowable stress, psi ΔSa = allowable range of stress .5625 5625 = slope l off S Sa curve

Sy T/2

T/1.75

Sa

T/4

SF = Service Factor T = Minimum tensile strength, psi ®

Sm

T

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Sucker Rods Service Factors – Use C grade rods to SF of 1.35 before using g D rods – Use D rods to SF of 1.35 before going to high strength g rods – Inhibit! Do not use case hardened rods ¾ For Permian from failure control in rod pump wells, SWPSC

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Service

API-C (default)

API-D (default)

Non Corrosive

1.0

1.0

Salt Water

0 65 0.65

09 0.9

H2S

0.5

0.7

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Sucker Rods Get Surface Rod Loads from Dyno Card

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Sucker Rods Modified Goodman Diagram: Grade D Rods 70000

Rod Loading = 29768 - 15141 37267-15141

60000

50000

= 66% 40000

Sa =(T/4+ =(T/4+.5625(Smin))(SF) 5625(Smin))(SF) = 37267 psi 30000

20000

Smin = 15141 psi 10000

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0

Pk Stress = 29768 psi 48

Sucker Rods Modified Goodman Diagram: Grade D, SF=.8 70000

Rod Loading = 29768 - 15141 29814 -15141

60000

50000

= 99.7% 40000 30000

Sa =(T/4+.5625(Smin))(.8) = 29814 psi 20000

Smin = 15141 psi 10000

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0

Pk Stress = 29768 psi 49

Sucker Rods Rod Loading Problem – Grade D, one inch rods were used to generate the below dyno y card. The service factor is 1.0. The min tensile is 115,000 psi (792810 kPa)

– What is the rod loading according to the percent of the range g of stress of the Modified Goodman Diagram? g

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Sucker Rods Care – Brochures Available from Norris

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Sucker Rods Recommendations for Sour / Corrosive Service –U Use C grade d rods d up tto a service i ffactor t off 1 1.35 35 b before f going to “KD” (alloy “D”) rods – Use “KD” rods up to a service factor of 1.35 before considering High Strength rods. Do you really want HS rods in a sour, corrosive environment? – Have an effective corrosion inhibition program to reduce pitting, especially with HS rods. – Do not use case hardened rods. – Inspected I t d rods d are acceptable t bl since i mostt ffailures il originate from corrosion pits and the inspection process is very good at identifying pits. (Jim Curfew & John Patterson) ®

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Sucker Rods Types of Coupling

Note: Norris now supplies pp a histrength coupling for use with histrength rods

Weatherford example products: ®

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Sucker Rods: See API RP 11 BR Correct Make-Up Lubricate threads before make make-up up

Scribed Vertical Line

Hand Tight Joint

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Measured M d Circumferential p Displacement

Made up Joint Made-up

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Sucker Rods Rods / Tubing / Casing / Pumps “Fit” Table

2 3/8s

2 7/8s

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Sucker Rods Size Limitations – 2 3/8’s ¾ 1 iinch h fiberglass fib l OK ( h has 7/8’s 7/8’ coupling) li ) ¾ (All fiberglass rods have pins 1 size less) ¾ 7/8’s steel OK but can’t run overshot for fishing ¾ 7/8’s slim hole couplings can be run with steel coupled rods ¾ Don’t run ½ inch in 2 3/8’s.. ((1/2 now discontinued)) ¾ Don’t run 1 ½ wt bars in 2 3/8’s with less than 22 API – 2 7/8’s ¾ Can run 1 “ w. w slim hole couplings couplings.. Can fish ¾ Can’t run regular 1 1/8’s couplings ¾ Never run smaller than ¾” rods in 2 7/8’s

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Sucker Rods Rod Guides – Use guides at wear locations at dog-leg g g locations and/or at above pump to reduce wear due to fluid pound – Molded guides tend to slip less than hand installed

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Sucker Rods High Strength Rods

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Sucker Rods Fibreglass Rods –

Positive Features ¾ Rods are light weight, therefore reduce load on surface equipment equipment. ¾ Due to their elasticity characteristic, well designed rod strings can have longer stroke down-hole than surface stroke, over travel equal to increased production ¾ Suitable for corrosive environments

Fibreglass Rods –

Negative Features ¾ Cost is higher then conventional sucker rods ¾ Due to excessive stretch characteristic, when fluid load increases, down-hole pump stroke smaller than su ace surface ¾ Surface of rod damages quicker compared to steel rods ¾ Due to fiber composite, they cannot support compressive loads. Rods must always be in tension. Design is critical and pump-off controllers are highly recommended to eliminate any compression due to unforeseen problem downhole ¾ Extremely difficult to fish when part ®

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Sucker Rods R d Rotators R t t Rod – Rod rotators are used in conjunction with rod guides to remove paraffin deposition. – A rod rotator should not be used when rods can’t rotate freely. If the rods torque up, backlash could cause the rods to unscrew. – A leveling plate should be installed on the carrier bar to prevent misalignment that could cause side id lloads d th thatt could ld result lt iin a polish li h rod failure. – A rotating tubing hanger and anchor system is available that can be installed on wells that have severe wear problems problems. – The entire tubing string can be slowly rotated to distribute wear from rod contact, even if sides loads keep the rod string in contact with one side of the well. well It is relatively expensive but it can be justified if it eliminates one tubing failure in a well. – Use tubing rotator if tubing wears

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Sucker Rods: Co-rod No Couplings!

Courtesy: Weatherford

Advantages – Minimal Pin and Coupling Failures – Minimal rod and tubing Wear – Minimal torque and power requirement – Enhanced pump efficiency – Simple, p , quick q installation and field service

Disadvantages – C Costt could ld be b up tto five fi titimes higher than comparable conventional rod – Service rig and welding unit must b available be il bl iin th the area ffor servicing – Connection to polished rod and pull rod critical

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Sinker Bars Heavier bars at bottom of rod string to help rods fall Sinker bars sized: – – –

– –

–

by experience, use vendor formulas, using the “Z” factor or some fraction of bars found from this formula, (see Norris rod handout) or using the “neutral neutral buoyancy” concept. Example: 1.5" diameter sinker bar lengths are 250250 300 feet, 2.875 tubing 1.52.25” plungers and 5000 feet deep. U Sinker bars have smaller pin sized ~ 7/8’s ®

FLEX BAR INC

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Rod Failures Rod “Corrosion-Fatigue” Failure – Mostly see (99%) corrosion-fatigue failures and not “ l “classic” i ” metal t l ffatigue. ti – Focus on pitting via improved chemical inhibition program p g & use rods with better fatigue g p properties p in sour/corrosive environment Corrosion - Fatigue y Small Pit in Wear Tract Very

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Rod Failures Indication of Compression Flexing Failure – Compression - double lipped failure – Focus on eliminating fluid pound – Pump slower, increase pump clearance, use sinker bars or guide program above pump Double Lip p Failure - Flexing g

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Rod Failures Loss of Circumferential Displacement

Wear

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Rod Failures Inspection – Recommend to inspect new and used rods

Handling – Critical!

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The Downhole Pump

Plunger

Traveling Valve Pump Barrel

Standing Valve Up Stroke

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Down Stroke

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The Downhole Pump:

START OF UP STROKE

START OF DOWN STROKE

PLUNGER FALLS THROUGH FLUID

From Harbison / Fischer ®

FLUID LIFTED TOWARD SURFACE 68

The Pump API Pump Designation XX – XXX – XXXX - X - X –X - X Length of Extensions

TBG SIZE PLGR SIZE

Type of Pump & Location of Seating Assy

Length of Barrel

Length of Plunger

A 1-1/4in bore rod type pump with 10 ft. heavy wall barrel and 1ft lower & upper extensions, a 4ft plunger, l and d a bottom b tt cup type t seating ti assembly bl for operations in 2-3/8” tubing, would be designated as follows: Weatherford 20-125-RHBC-10-4-1-1 ®

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The Pump Rod Pump Top Anchor – Advantages ¾ Eliminates sedimentation around barrel tube ¾ Reduces corrosive attack on exterior of barrel ¾ Pump barrel can act as gas anchor – Disadvantages ¾ Valve rod is weak leak of sucker rod ¾ Not recommend for deep wells ¾ Part time pumping may allow sediments to fall on pump Rod Pump Bottom Anchor – Advantages ¾ Can be used in deep wells ¾ Good valve location ¾ Better design where long pumps necessary – Disadvantages ¾ V-rod weak link in S-rod chain j to sedimentation ¾ Barrel tube subject ¾ Part-time pumping may allow sediments to fall on pump ®

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Bottom / Top Holddown Insert Pumps Bottom holddown has pressure equalized li d across th the barrel of pump – But particulates can accumulate accu u a e be between ee barrel and tubing and stick pump on removal. So need top seal or bottom discharge pump

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Top holdown has no place for particulates to p accumulate but outside of barrel exposed to low well pressure and could split at deep depths. So has shallower depth limitations

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The Pump Ball and Seat – Steel – Stainless steel – Cobalt alloy – Tungsten carbide – Titanium carbide – Nickel carbide – Ceramic – Silicon nitride Cage – Steel – Monel – Stellite hardened – Four piece insert

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Pull Rod/tube – Steel – Stainless steel – Brass

Plunger Metallurgy – Steel – Monel or electroless nickel coated t d pins i – Coatings ¾ Chrome plated Barrel Metallurgy ¾ Spray S Metal – Carbon Steel ¾ Boron impregnation – Stainless steel – Brass – Monel – Treatment/coating ¾ Heat treated ¾ Chrome plated ¾ Nickel carbide

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The Pump Plunger Length – Rule of thumb: ¾ 3 ffeett ffor d depths th less l than th 3000 ft ¾ 3 feet long plus 1 ft/1000 ft to 6000 ft ¾ 6 feet long in deeper wells ¾ Industry recommendations: Slippage should be 2-5% of production to reduce pump galling and provide lubrication.

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The Pump 1.25"

1.5"

1.75"

Pump Type

2"

2.25"

2.5"

2.75"

Steel Barrels

Top p Hold-down,, Thin Wall

RWA

6,394

5,520

-

3,732

-

3,183

-

Bottom Hold-down, Thin Wall

RWB

16,936

14,705

-

9,727

-

6,362

-

Travel Barrel, Thin Wall

RWT

16,936

14,705

-

9,727

-

6,362

-

Top Hold-down, Heavy Wall *

RHA

8,321*

8,818*

6,749*

-

4,876*

-

-

Bottom Hold-down, H Heavy W Wall ll *

RHB

27 148* 27,148*

24 249* 24,249*

21 897* 21,897*

-

18 323* 18,323*

-

-

Travel Barrel, Heavy Wall *

RHT

27,148*

24,249*

21,897*

-

18,323*

-

-

Tubing Pump

TH

-

-

10,019

-

7,763

-

6,262

Oversized Tubing Pump

THOS

-

-

10,019

-

7,763

-

6,262

* If using extensions

RHA

7,568

6,118

4,706

-

3,824

-

-

RHB

25728

28,714

20,708

-

17,294

-

-

Weatherford ®

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The Pump Latest Slippage Equation : Desire at least 2-5% of production rate leaking (slipping) back between plunger/barrel

DPC1.52 Slippage = [(0.14 ⋅ SPM ) + 1]453 Lμ – Based on this work and previous work, the following minimum pump clearances are recommended for a 48” 48 Plunger with a “+1 +1 Barrel”. – These clearances have become widely used in the Permian Basin for well depths up to 8000 feet feet. ¾ 1.25” pump = -3 to -4 plunger (0.004” to 0.005” total clearance) ¾ 1.50” pump = -4 to -5 plunger (0.005” to 0.006” total clearance) ¾ 1.75 1 75” pump = -5 5 to -6 6 plunger (0.006 (0 006” to 0.007 0 007” total clearance) ¾ 2.00” pump = -6 to -7 plunger (0.007” to 0.008” total clearance) ®

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The Pump Pump / Tubing / Casing / Rods Chart

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Anchors Mud Anchors – – – –

Used to protect pump & part of gas anchor Same size restriction as tubing Can be short joint or multiple joints Can cut slots in the top of the joint or use a perforated nipple – Recommend that end be orange g p peeled rather than a bull plug – If severe corrosion, consider coating OD and ID

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Anchors Gas Anchors – Gas interference can drastically reduce the pump efficiency – Gas should be separated downhole and vented up the casing – A natural gas anchor with the seat nipple below the perforations is the best option – If no rat hole hole, then determine the best gas anchor for the well

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Beam Monitoring and Optimization Optimization of a Beam System requires getting most production at lowest power cost. Parameters that effect the system that are checked / monitored are: – – – – – – – – – – – –

Fluid pound G Interference Gas f Valve Leaks Worn Plunger / Barrel Incorrect Spacing Overloads (Rod, Unit, Primemover) Pump Fillage Runtime Prod rate vs Pump Volume = Volumetric Efficiency Motor oversized Efficiency of system Fluid levels or intake pressure ®

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Beam Monitoring and Optimization In order to produce the maximum with a beam pump – The fluid level should be as low as possible – However this can result in fluid pound and gas interference – A typical practise is to switch the pump off and let fluid level build up again and then run pump again. – This can be done using ¾ Pump Off Controllers (POCs) ¾ Timers

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Beam Monitoring and Optimization Pump Card (Cycle with Pump Full of Liquid) on left and partial gas fillage on the right

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Beam Monitoring and Optimization The Pump Card – Pump off occurs when the pump p p begins g fill with increasing amounts of gas instead of liquid. – It is up p to the operator p to decide what degree of pump off is allowed before shutting off the unit. – Common practice is to allow pump-off to the point where pump fill age with liquid is about 85 to 90 percent

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Beam Monitoring and Optimization Pump Off Controllers – A well with a high static pressure and a low PI is a good d wellll ffor POC POC. – This is because during the down-cycle, the well will continue to flow into the well annulus. – The pumping unit should be designed such that the unit will pump about 140% of the maximum that the wellll will ill make. k – This means that the well will pump about 18 to 20 hours a day – Beam system is only AL method where POC used extensively! Unit has to be designed to pump f t th faster than reservoir i produces d to t pump-off. ff ®

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Beam Monitoring and Optimization Pump Off Controllers – Typical cycles are about 1 hour for many wells. This means about a 15 min idle time and 45 minute pumping time. – If the pumping hours decrease when idle time is increased then production is being lost increased, lost. The idle time should then be decreased again. – Pumping hours are an excellent measure of production, d ti sometimes ti even b better tt than th a wellll ttestt iin many fields.

Potential Benefits – 20% reduction in energy costs – 25% reduction in pulling expense – 1 to 10% increase in production ®

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Beam Monitoring and Optimization Automated Well with POC A well can have a little or a lot of control. This well figure shows many y controls.

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Beam Monitoring and Optimization Timers – A timer can be used to determine when the unit operates t / switches it h off ff – Two style of timers are used in the oilfield. ¾ A percentage timer controls the percentage of time that the pumping unit operates. ¾ An interval timer controls the time intervals (usually 15 min)) which c tthe e pu pumping p g unit u t operates. ope ates

– They can cost from $25 to $200 each.

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Beam Monitoring and Optimization Summary: POCs and Timers – Electrical and maintenance costs will be reduced with a properly operating p g timer or POC. – The recommended 15 minute percentage timer technique for reducing electrical costs and maintenance costs is a relatively simple p technique q and inexpensive p p procedure for reducing g operating costs in a well which have a pumping capacity exceeding the wells’ producing capacity. – POC is a more sophisticated p method of control and is very y common.

The main idea is to keep the fluid level low without requiring a lot of service time from field personnel personnel. Other gains such as reduced energy, reduced damage, and more production are also possible.

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Beam Monitoring and Optimization System Efficiency – Single well meters allow some measure of diagnostics for the well including g the calculation of p power efficiency. y ¾ Actually few determine the power efficiency below but if they do it is useful diagnostic. ¾ With high prices for oil, the main concern is “how to maximize production”.

– Master meters for a group of well give the company credit for regeneration of the motors when they act as generators. Single well meters with a rachet do not.

η=

0.00000736(bpd )(lift )γ liq kW / 0.746

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useful power = input power

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Additional Reference Slid Follow Slides F ll that th t are Included for your Information that may y not be Presented in Class

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The Pump The “Sandbar” Top Seal Uses a Brush Seal: Other type rubber expandable seals exist

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The Pump The Bottom Discharge Valve is placed above the bottom seating assembly of a bottom b tt anchor h pump. On the downstroke, a portion of the fluid from the pumping chamber is discharged into the annulus around the pump, providing and upflow to keep sediment from accumulating. This valve is an alternate to use of the top seal assembly for type “B” insert pumps. ®

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The Pump API Documents – API Spec 11AX Specification of Subsurface Sucker R dP Rod Pumps and d Fitti Fittings – API RP 11AR Recommended Practice for Care and Use of Subsurface Pumps p

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Surface Unit Standard API Unit Sizes API Gearbox Ratings

API Structural Ratings

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API Standard Stroke’s, in 48

114

143

54

160

173

64

228

200

74

320

213

86

456

246

100

640

256

120

912

305

144

1280

365

168

1824

427

192

2560

470

216 240

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Gearbox Care 1. 2. 3 3. 4. 5. 6.

Keep the loading within the manufacturer’s rating. Ensure unit balanced (counterbalance) A id flfluid Avoid id pound d (thi (this d down h hole l condition diti causes severe shock h k loading on the entire pumping unit as well as on the reducer) Ensure belts not too tight (results in high shaft stresses) Use correct lubricant (manufacturer recommendations) Periodically change rotation (conventional units can be run in both directions). Allows opposite tooth surfaces exposed to contact loading.

Lubrication: Wiper Comments 1. 2. 3.

Lufkin wipers work equally well in both direction of rotation (+ & -). If you run at < 5 SPM Lufkin recommends you add an extra set of wipers on the high speed gear gear. Never have to adjust the wipers as they use gravity to continually adjust as they wear with time (the wiper is hinged to allow gravity to adjust)

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API Documents Spec 11E Specification for Pumping Units RP 11G Installation and Lubrication of Pumping Units API STD 11E Pumping Units API BUL 11L4 Curves for Selecting Beam Pumping Units API spec 1B for guidelines of V belts

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Tubing Best Practices Perform Wellhead tubing scanning on wells where excessive rod wear is found and on problem wells. wells Scan all the tubing tubing, including that below the TAC. For wells 3500' or less in depth p with historic wear problems, pull and replace entire tubing string when there is a tubing failure. Ch Change outt entire ti tubing t bi string t i (regardless ( dl of the type of failure) once the tubing string has reached the average g age g of tubing g life for that particular field. F ll i 4 slides, Following lid MB Brock k BP) ®

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Tubing Best Practices Lay down tubing on all wells having 2 tubing failures in 12 months or less. – Exception to this would be where all tubing failures have historically been right above the pump in which case you should replace the bottom 10 joints.

IIn wells ll with ith tubing t bi failure f il due d to t external t l pitting, lay down all pitted joints and test tubing back in hole Wellhead scan tubing on the first tubing failure after tubing has been replaced with new or yellow band pipe. – The information is an excellent diagnostic tool for evaluating the current rod design design. ®

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Tubing Best Practices Verify the wellhead scanning tool was calibrated on location before and after the job against a known tubing sample and verify the pipe is pulled at the proper speed. – Some tools have a speed scale on the chart.

Consistent speed is very important in scanning tubing. – When approaching pp g the TAC crews tend to slow down several stands before the TAC to keep from pulling it into the wellhead. – It is recommended that when the pulling unit operator feels he must start slowing g down (g (generally y 7 to 10 stands above the TAC) that he stops scanning and stands back the remaining tubing down to the TAC, remove the TAC, rerun the stands not scanned, and then scan the rest of the string out at the appropriate speed. ®

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Tubing Best Practices When running tubing, always use a new or yellow band joint in the wellhead slips. Always replace the seating nipple plus the blast joints / internal plastic coated joints / etc in pump discharge or dead space with etc. new or yellow band when tubing pulled. Tag bottom for fill where applicable when pulling tubing. See below paper , SWPSC 1998 for tubing practices in detail:

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Sucker Rods API Practice 11BR: Care and Handling of Rods – – – –

Selection Of API Steel Sucker Rods Transportation, Storage and Handling Corrosion Control By Chemical Treatment Allowable Sucker Rod Stress Determination Utilizing g Of Stress Range – Sucker Rod Joint Makeup Utilizing Circumferential Displacement – Methods M h d Of Inspection I i and dR Required i dE Equipment i – Installation Of Polished Rod Clamp On Polished Rod

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Sucker Rods Rod Spacing (wells that are 8000-9000 feet deep typically with very low fluid levels) – – – – – – –

Run pump in hole until tag seating nipple. Space out polish rod/pony rods Load tubing w/ fluid. Stroke pump x check for action. Put gauge in pumping tee and stroke w/ rig. Tag plunger on barrel x PU about 18 inches. PU horsehead x hang off rods. – Put well pumping x let pump fluid level down. – Check for bumping and respace pump as necessary. Check pump spacing with dyno to make certain pump is not bumping also. – 18 inch spacing has been working pretty good for Hackberry Hackberry. This spacing is for steel rods only w/ no fiberglass. Fiberglass spacing will be different.

Note: gas problems PU will be much less… only inch or two and then recheck if bumping and respace.. ®

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Rod Failures Corrosion due to Turbulence Past Rod Guide? – SPM x SL (inches) < 1500Fluid velocity between coupling OD (d) and tubing ID ( D) is: Velocity Velocity, ft/sec = 0 02384 BPD/(D-d) < 4 fps – Newer guides more streamlined. – Guides must be removed in inspection process to look for underlying corrosion!! Corrosion In Turbulent Area - Rod Guide

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Sucker Rod Best Practices (after Brock, BP) When running rods, remove one rod and replace with 13' of rod subs above pump and 12' of rod subs at the top of the well to move the wear pattern. On subsequent pulls reverse procedure. (Assuming the pump length remains the same). All rod strings should be carded when run in the hole. Should card every taper and/or 10 - 12 triples Replace rod taper section following the second failure in 12 months in that taper. Replace p entire rod string g on second failure in 12 months if failures occurred in two different tapers. (another operator 4th in 24 months)

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Sucker Rod Best Practices (after Brock, BP) R l ti steel t l rod d string t i after ft an estimated ti t d Replace entire 20,000,000 cycles. If used inspected rods are utilized, 15,000,000 cycles since i last l t inspected i t d good d rule l off thumb. th b When looking at replacing fiberglass rods, need to consider the loading the rods have been under. Loading on fiberglass f rods is inversely proportional to cycle life. The higher the percent rod loading, the shorter the rod life. P bli h d data Published d t for f fiberglass fib l rods d indicates i di t the th number of cycles to first failure to be: – – – –

30 million cycles at 80% rod loading, 15 million cycles at 85% rod loading loading, 10 million cycles at 92% rod loading 7 million at 100% loading.

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Beam Monitoring and Optimization Travelling Valve Test – Stopping the pump on the upstroke p will have the fluid load plus the weight of rods in fluid on the polished rod. TV, load = Wra ( 1- 0.128 x SG) + + 0.340 0 340 x SG x D2 x H Where: Wra = weight of rods in air SG = specific ifi gravity it off fluids fl id D = pump diameter , inches H = depth, feet

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Beam Monitoring and Optimization Standing Valve Test – Stopping the unit on the downstroke will have only th weight the i ht off rods d iin fl fluid id on the polished rod. SV, load = VOL x 487.5 - VOL x 62.4 x SG = Wra W ( 1 - .128 128 x SG) Where: VOL = volume of rod string 487.5 = density of steel, lbs/cu.ft 62 4 = water density, 62.4 density lbs/cu.ft. lbs/cu ft Wra = weight of rods in air ®

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