Care & Handling

8/3/2019 Care & Handling

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Protecting your investments

The care and handling of Norris Sucker Rods

A four part series reprinted from theWell Servicing magazine


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The rod string is a vital link between surfaceequipment and subsurface equipment in arod pumped well. Without this link the well

will not produce liquid. The investment in a rodstring may be significant, but failure to adequatelyprotect this vital link can generate substantialexpenses that far exceed the initial investment(i.e., rig time, equipment replacement cost, lostproduction, and the like). However, a rod string that

is properly designed (based upon experience),physically handled and made-up in accordance withthe recommendations of the manufacturer, operatedwithin acceptable design parameters and maintainedwith an effective downhole corrosion controlprogram should give a long, satisfactory, andeconomical service life. Adhering to theseparameters makes both the initial investment and theoperating expense for a rod pumped well extremelycost-effective as a method for artificial lift.

In order to maximize the value of your investment,Well Servicingwill publish a four-part series identifyingpossible causes of failure and suggested remedies toextend the usable service life of the rod string.

Storage and transportationIn most cases, the rod string is comprised of the

polished rod clamp, polished rod, polished rodcoupling, pony rods, rod guides, sucker rods,stabilizer bars, sinker bars, sucker rod couplings andsubcouplings. Physically storing and transportingthese components in accordance with therecommendations outlined below, and/or thosecontained in API Recommended Practices 11BR, willhelp prevent premature failures that occur due toimproper storage and transportation procedures.

(1) Rod string components should be inspectedupon delivery to verify quantity, size, length, type orgrade, pin size, guide size, style and/or load capacity.

(2) Protectors should not be removed from thecomponents while in storage, except for inspectionpurposes, and then immediately reinstalled after thevisual examination is complete. Whenever a componentis observed to be without such protection, it shouldbe inspected and, if undamaged, thoroughly cleaned,

a suitable protective coating reapplied and theprotectors reinstalled.(3) The components should be routinely inspected

on a quarterly basis for damage and/or protectivecoating deterioration. Damaged components shouldbe removed and/or replaced. Rust should be removedwith a soft wire brush prior to the reapplication of asuitable protective coating.

(4) The components should be routinely rotatedwhile in storage so that older inventory is used first.

Loading or unloading procedures(5) In all handling operations, care should be

exercised to prevent the components from coming in

contact with an object that may cause mechanicaldamage. Caution should be exercised with threadedcomponents to ensure intact thread integrity ismaintained. Care should be taken when applying orremoving the bulkheads and tie-downs used tosecure the load during shipment in order to avoiddamaging the components.

(6) Polished rods, pony rods, sinker bars, stabilizerbars, and sucker rods should never be handled insuch a manner that may produce a permanent bendor kink. Bent or kinked components are permanentlydamaged and should be discarded.

By RUSSELL STEVENS &SCOTT MALONE

Norris

Protecting your investment insucker rods

Part 1:

Storage andtransportation

Figure 1


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Figure 3

(7) Polished rods, sinker bars, and sucker rodsshould always be handled with approved liftingdevices designed to support the sucker rod withoutdamage.

a. Packaged sucker rods should always be lifted and/or laid down using a forklift and an approved spreaderbar and tee hook system that adequately supportsthe full load of the sucker rod package by lifting onepackage, at a time, from beneath (Figure 1).

b. Loose polished rods, sinker bars and sucker rodsshould always be lifted and/or laid down one at a timewith either an approved spreader bar and nylon straps,or by using a minimum of two individuals with eachperson positioned in about 3 to 4 feet from each end.

Transportation procedures(8) Trucks and trailers for handling rod stringcomponents should have non-metallic floors orsupports, be in good condition that provides forproper support to the component shipped. Trailersshould provide blockage directly under the cross-wise supports of the package so that the sucker rodsthemselves do not come in contact with the blockage.Further, packages should be stacked so that thebottom supports of the top package rest squarely onthe top supports of the package underneath.

a. Polished rod clamps should be placed in storageboxes during shipment.

b. Polished rods should remain in factory protec-

tors and set level on non-metallic supports duringshipment. Nylon tie-downs should be placed in sucha position as to pass over non-metallic supports andshould be prevented from coming in contact with thepolished rod by the use of spacers.

c. Pony rods should be carefully packaged orpalletized and nylon tie-down straps should be placedin such a position as to pass over the package supports.The straps should be prevented from coming incontacting with the pony rods on the top layer.

d. Sinker bars should set level on non-metallicsupports and have nylon tie-downs that pass over the

non-metallic supports. Tie-downs should be preventedfrom coming in contact with the polished rod by theuse of spacers.

e. Stabilizer bars should be carefully packaged orpalletized and nylon tie-down straps should pass overthe package supports. Tie-downs should be preventedfrom contacting the stabilizer bars on the top layer.

f. Packaged sucker rods, preferably should behandled as a packaged unit. The packaged unit shouldset level with non-metallic supports under eachpackage support. When stacking packaged suckerrods on top of other packaged sucker rods, thepackage supports in the top package must properlyalign vertically with the package supports in thepackage beneath. Nylon tie-down straps should beplaced in such a position as to pass over the packagesupports and should be prevented from contactingthe sucker rods on the top layer (Figure 2).

g. Loose sucker rods should be carefully placed onfive non-metallic supports. End supports should beplaced approximately 1-foot in from each end and theother three supports should be spaced equally in themiddle. Layered sucker rods should be separated bynon-metallic spacers positioned directly above thenon-metallic supports in order to separate the toplayer from the bottom layer of sucker rods. Nylon tie-down straps should be placed in such a position as topass over the spacers and should be prevented fromcontacting the sucker rods on the top layer.

Storage Procedures(9) Couplings, polished rod clamps, polished rods,

pony rods and stabilizer bars should be storedinside, out of the elements, on shelves, pallets, racksor sills made from non-metallic materials that arenon-abrasive to the stored component.

a. Couplings should be stored separately on palletsin factory boxes by type, inside thread diameter, andoutside diameter (Figure 3).

b. Polished rod clamps should be stored separatelyon shelves by style, size and load capacity.

Figure 2


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c. Polished rods should be stored separately onracks or sills by type, size, length and pin size. Usethree non-metallic supports for polished rods thatare 14 feet or less in length. End supports should beplaced approximately 1-foot in from each end of therod and the other support spaced equal distance inthe middle. Use four non-metallic supports forpolished rods that are 20 feet or less. End supportsshould be placed 1-foot in from each end of the rodand the other two supports spaced equally along the

middle. Use five non-metallic supports for polishedrods that are 26 feet or less in length, with endsupports 1-foot in from each end of the rod and theother three supports spaced equally along themiddle. Use six non-metallic supports for polishedrods that are 32 feet or less in length, with thesupports spaced as described above. Use sevennon-metallic supports for polished rods 32 feet orless, with supports spaced as described above.

d. Pony rods should be stored separately by typeor grade, size and length in bins, pallets, or racksdesigned to minimize metal-to-metal contact.

e. Stabilizer bars should be stored separately bytype or grade, size, pin size and guide size in bins,

pallets or racks designed to minimize metal-to-metalcontact.

(10) Sinker bars, packaged sucker rods and loosesucker rods should be stored on racks or sills madefrom non-metallic materials that are non-abrasive tothe stored components. The storage site containingthe racks or sills should have a level, firm surfacethat is clear of weeds and debris with adequatedrainage to promote water runoff.

a. Sinker bars should be stored separately bygrade, size, length and pin size on racks or sillsdesigned to minimize metal-to-metal contact. Theyshould be stored loosely on a minimum of five non-metallic supports with end supports approximately

1-foot in from each end of the bars and the otherthree supports equally spaced along the middle.Sinker bar layers should be separated by spacersplaced directly above the non-metallic supports. The

spacers should be thick enough to prevent the sinkerbars from coming in contacting with other sinkerbars in adjacent layers. If the spacers are notnotched, the outside sinker bar in each layer must bechocked with blocks to prevent the sinker bars fromrolling off the spacers.

b. Packaged sucker rods should be storedseparately by type or grade and size on racks or sillsdesigned to minimize metal-to-metal contact. Theyshould be stored using non-metallic supports undereach package support and, when stacking packagedrods, the package supports on the top package mustproperly align vertically with the package supportson the package beneath (Figure 4).

c. Loose sucker rods should be stored separatelyby type or grade and size on racks or sills designed tominimize metal-to-metal contact. They should bestored using five non-metallic supports with each end

support placed approximately 1-foot in from eachend of the rods and the other three supports spacedequally along the middle. Rod layers should beseparated by spacers placed directly above the non-metallic supports. The spacers should be thick enoughto prevent the sucker rods from coming in contactwith other sucker rods in adjacent layers. If the spacersare not notched, the outside sucker rod in each layermust be chocked with blocks to prevent the suckerrods from rolling off the spacers (Figure 5).

Adhering to the guidelines outlined above shouldhelp prevent damage to components of the rod stringthat result in premature failure. By proactivelypreventing possible failure causes that result from

poor storage and transportation techniques, you areprotecting the initial investment in the rod string andhelping to lower operating expenses that justmakes good sense.

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Figure 4

Figure 5


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As discussed in Part 1 of this series (Well

Servicing July/August 2005), the rod string isa vital link between surface and subsurface

equipment in a rod pumped well. A significantmonetary investment is necessary along with aconsiderable amount of time. The API document,Recommended Practices 11BR, states usefulsucker rod strength is limited by the fatigue perfor-mance of a metal in a non-corrosive environment.But the fatigue life can be dramatically decreased

by improper installation Many improper activitiescan cause rod damage so severe that failure canresult in just a few days following initial installation.The proper and consistent procedures of runningsucker rods into a producing well takes time andshould not be a race against the clock. Time spentwisely is sure to pay off in terms of longer run timeswithout unnecessary downtime and rod replacement.

General running and re-Running information(1) Rod string components should be inspected

upon delivery to verify quantity, size, length, type orgrade, pin size, guide size, style and/or load capacity.They should also be examined to verify that the

components were not damaged during the deliveryprocess.(2) Protectors should not be removed from the

components until the string is ready to be installed,except for inspection purposes, and then immediatelyreinstalled after the visual examination is complete.These protectors and packaging materials arepreserving your investment from the surroundingenvironment until you can place it into the environ-ment for which it was designed to operate. Whenevera component is observed to be without suchprotection, it should be inspected and, if undamaged,thoroughly cleaned and a suitable protective coatingreapplied and the protectors reinstalled.

(3) Loose rods should be stored at the welllocation in the same manner required at storage yardfacilities. Non-metallic supports should be used toensure that rods are not bent and metal-to-metalcontact is avoided. Metal-to-metal contact is anopportunity to damage the surface of the rod andpotentially lead to premature failure (Figure 1).

(4) Pony rods and couplings should be deliveredand stored on separate pallets until ready for use.The same level of care and attention should be givento these accessories as is given to the sucker rods(Figure 2).

Running the rods(5) It is extremely important that the well servicing

rig be correctly positioned over the wellbore. Therod hook must be positioned directly over the tubing

bore in order for the sucker rods to feed into thetubing without creating friction on the sides of therunning nipple. Any friction, undoubtedly, will rub offany corrosion inhibitor film and may possiblydamage the surface of the rod due to the aggressivemetal-to-metal contact. The lack of corrosion protectionand/or the work hardening of the area will create asmall anodic area and corrosion will be acceleratedin this spot and premature failure may result.

(6) The rod bundles that are ready to be installedshould be broken open in a safe manner that will notcause rod surface damage. This can be accomplished

By RUSSELL STEVENS &

SCOTT MALONENorris

Protecting your investment in sucker rods

Part 2: Running and Re-Running

Figure 1

Figure 2


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using side cutters or tin snips to cut the steelbanding. Axes, crescent wrenches, claw hammers, orany other tool can easily cause damage to the rodsand may also cause injury.

(7) The rod bundles are not designed to be used asa work surface. Do not place tools, pipe or otherequipment on the rod bundles as this will increasethe possibility of rod surface damage.

(8) Dumping the couplings out on the ground forfaster access to them may cause failure for every

coupling that retains contamination in the threads.To properly clean the threads on couplings contami-nated in this manner will take a great deal of time.The threads will gall if not kept free of solid material.

(9) The pony rods are nothing more than shorterrods and are susceptible to the same types of damageas a regular length rod.

(10) Unscrew the rod thread protectors by hand orwith an air impact wrench. Knocking off the threadprotectors will leave plastic remnants on the rodthreads that will damage the threads during makeupor when they are broken out on the next pump pull.Do not remove them until it is time to install the rods.It is best to keep them covered and protected as long

as possible.(11) When removing box protectors DO NOT

engage the coupling threads with the screw driver.This action always results in thread coupling crestdamage and will more than likely fail downhole.

(12) Clean and inspect pins and boxes. New rodpins are coated with corrosion inhibitor from themanufacturer; not thread lubricant. The pins of therods in the derrick often have been contaminated bywellbore fluid, unknown lubrication type and evenblowing sand. These contaminants need to beremoved and the threads re-lubricated.

(13) The API sucker rod coupling is designed as arotary-shouldered, friction-loaded, fluid-free connec-

tion between sucker rods (Figure 3). Apply a smallamount of lubrication to the pin or coupling threadsto help reduce the interference between the threads(Figure 4). The rod shoulder and box face contactrequires friction to maintain proper makeup.Lubrication in the friction contact area will increaselikelihood of pin failure. The faces must remain cleanand dry throughout the makeup procedure.

(14) Sucker rod thread-lubricants need to besmooth, with a grease-like consistency, and containcorrosion inhibitors and anti-oxidants to reduce theinterference-fit between the threads. Topco SRL is

such a lubricant. If no other lubricant is available use

the grease gun off the rig. Ensure that the lubricanthas no fillers.

(15) Inspect the rod elevators regularly and repairor replace them if their use may result in damage tothe rods. Ensure that the seats are smooth and roundin shape, that the latch opens with resistance andsnaps shut, and that the bail moves back and forthfreely. Elevators can inflict mechanical damage to therod upset taper if seats are not smooth or the eleva-tors can corkscrew the entire string if they open atthe wrong time (Figure 5). The individual rods will bebent near the ends if the elevators do not pick up the

Figure 3 Figure 4

Figure 5

Figure 6


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string weight in a level fashion due to their inabilityto swing freely.

(16) As you begin to pick up the rods, rememberthat every rod must be tailed into the derrick(Figure 6). Rods that run down the bundle damageevery rod they hit. Rods that are dragged though thedirt have contaminated threads and may gall. Thesethreads must be thoroughly cleaned and inspectedfor damage.

(17) Be sure to use bell nipple, a stripper or aswage nipple for the running nipple. A piece of cut-offtubing may damage most every rod you run.

(18) Power tongs are the recommended tools formaking up joints on virtually all sucker rod strings.They must be set up properly to provide thecircumferential displacement specified by themanufacturer. The displacement card must match allfour (4) characteristics of the rod (size, grade, condition

and manufacturer) to ensure accurate displacementcalibration of the power tongs (Figure 7).

(19) Make up the rod and coupling connections byhand and scribe a vertical line on the coupling andlower rod shoulder and then unscrew the lowerconnection until roughly two pin-threads are left

engaged by the coupling. Note: When making theseinitial connections, the rod must be hanging free inthe rod elevators squarely over the joint below.When stabbing the rod pin into the coupling the rodshould be hanging straight and without slack to avoidcross threading (Figure 8).

(20) Make sure the engine rpms are at full throttle.Then pull the rod tongs to the connection, engage theconnection with the rod tongs using the lowest speedpossible.

(21) Maintain full engine rpms throughout makeupand stall the rod tongs and do not bump theconnection. Back away the rod tongs and idle downthe engine rpms.

(22) Match the circumferential displacement on therod coupling connection to the proper card.(Figure 9) Adjust the power tongs to create thedisplacement necessary. Do a mechanical integritycheck of the rod tongs by checking the next 4 to 5joints to verify the pressure adjustments are correctand maintained. Check every 12th connection as yougo into the hole with the sucker rods and adjust thepower tong pressure accordingly.

(23) Note: Cross threaded connections are notacceptable. Always start every connection by hand,with at least two full threads engaged before puttingthe power tongs on the joint. The tongs are capableof cross threading the joint and the joint will fail.

(24) Pulling rods can also damage them, particularlyif you are pulling the rods and laying them down. It ispossible to lay down singles without much damage,but it is virtually impossible to lay down doubleswithout damaging the rods.

Consistently prepared joints and damage freestring installation will enhance the likelihood of longproductive sucker rod service life.

Figure 7 Figure 8

Correct Incorrect Wind

Figure 9

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A

s discussed in Part 1 of this series (WellServicing July/August 2005), the rod string isa vital link between surface and subsurface

equipment in a rod pumped well. A rod string that isproperly designed (based upon experience),physically handled and made-up in accordance withthe recommendation of the manufacturer, operatedwithin acceptable design parameters and maintainedwith an effective corrosion control program shouldgive a long, satisfactory and economical service life.Since most failures can typically be categorized aseither man-made or well-induced, Part 1 (Well

Servicing July/August 2005) and Part 2 (Well Servicing September/October 2005) dealt with preventingman-made failures from improper storage, trans-portation, running and re-running procedures. Part 3explores design and operating conditions to optimizethe useable service life of the rod string.

Most failures in the rod string are repeat failures. Inother words, they occur as a result of the same failurecause in a given well. Simply pulling the rod string,replacing the failed component and re-running therod string will not solve the problem and willultimately lead to more failures. Do not replace therod string one component at a time. Instead, analyzethe failure cause and implement proper correctiveaction based upon information gleaned from thefailure history. Failures inevitably drive costs up, soby reducing the failure frequency, or extending thetimeframe between failures, operating expenses

(OPEX) can be kept in check. That said, the elimina-tion of all failures in a rod pumped system isimpractical, if not impossible, and the costs associatedwith the task would be astronomical! Therefore therod-pumped system must be optimized to effectivelymanage failure frequencies, thus allowing the greatestamount of profit to be realized from the well.

The first criterion for effective failure managementis to target problem wells. To target problem wells,you must keep good, accurate records. Effectivefailure management is data intensive and requirescomprehensive knowledge of the data from which

tracking measures can be developed to monitor andmeasure improvements. A simple database orspreadsheet is a good way to record and trackfailures. The database or spreadsheet should recordthe failure depth, failed component (pump, rods ortubing), location of failure on the component (travel-ing valve cage, rod body, collar, etc.), and theroot-cause of each failure (fluid pound, H2Scorrosion, inadequate makeup, etc.). During theinitial stages of an effective failure managementprogram, prevention costs may increase, masking theinitial effects of the improvements. However, overalllong-term cost reductions will become apparent andimprovements to operations realized resulting ingreater operating economics.

Numerous combinations of depths, tubing sizes,fluid volumes, pump sizes and configurations, unitsizes and geometries, stroke lengths, pumpingspeeds and sucker grades and tapers are available tothe system designer. Most designs are optimizedfor conditions existing at the time of the initialinstallation. However as the well matures, gas and/orwater production may increase or decrease, resultingin changes to load requirements and fluidcorrosiveness. A good initial design may become apoor design if well conditions change. The systemmay need periodic re-evaluation to insure all

components are operating effectively. Develop asystematic approach to well optimization bymonitoring actual operating parameters with reliablediagnostic equipment. Always verify that conditionsare optimal for the well after any change in operatingconditions (production volumes, fluid level, pumpsize, stroke length, strokes per minute, chemicaltreatment, etc.) as these changes can severely impactthe total rod-pumped system. This allows bettercontrol of operating conditions such as rod loading,pump fillage, corrosion, solids and the like, thatenhance the useable service life of your equipment.


SCOTT MALONE

Norris

Part 3:Well Optimization

Protecting your investment insucker rods

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Have you ever heard the phrase, If it aintbumping, it aint pumping!? Bumping, a.k.a. pumptagging, allows the reciprocating top valve rodbushing to impact the stationary valve rod guide of

the downhole rod pump at or near the end of thedownstroke. The force of the impact between thetwo pump components rattles the traveling valve balloff its seat and allows a load transfer from the rodstring to the tubing to take place. At the same time, ashock wave is generated throughout the rod-pumpedsystem by the sudden impact of these twocomponents tagging each other. The impactdamages the clutches on the bushing and guide(Figure 1) and the shock wave creates rod buckling,rod-on-tubing contact and excessive wear. Bumpingalso elevates the possibility of damage to the gearreducer of the pumping unit.

Bumping the pump is a band-aid solution that

attempts to correct symptoms created by erraticvalve action in the downhole rod pump. Erratic valveaction is a problem that may be caused from solidsand/or gas interference. Careful review of pump tear-down reports will indicate problems from solids, i.e.sand cut plungers (Figure 2), scored barrels, andsuch. Solids can significantly increase pump friction,reducing rod loads on the downstroke and pushingrod buckling further up the well. Solids trappedbetween the barrel and the plunger will also increaseloads on the upstroke. Using alternate pattern ballsand seats (Figure 3), with increased flow areas, mayhelp alleviate some of the symptoms commonlyassociated with this phenomenon.

Designing pumps with high compression ratios isanother way to effectively deal with gas interference.The compression ratio of the pump is equal to theswept volume of the plunger stroke plus the unsweptvolume of the plunger stroke divided by the unsweptvolume of the plunger stroke. The pump dischargepressure is equal to the pump intake pressure timesthe compression ratio. If the pump discharge pressureis not equal to or greater than the hydrostatic fluidload on the traveling valve, gas interference or gaslocking will occur. Heavy wall, stroke-thru barrels(RHBC & RHAC) are examples of pumps that develop

relatively low compression ratios due to the area ofthe unswept volume in the lower extension and areprone to more problems with gas interference andgas pound (Figure 4) if not properly designed.

Many wells produce gas along with the well fluids.The presence of free or break-out gas at the pumpcan interfere with the efficiency of the pump action,thereby reducing the amount of fluid produced. Thisinterference can result in a gas pound and, whenextreme, it can result in a completely gas-lockedpump. During the pumping unit upstroke, the pumpbarrel is filled with fluid and free gas, usually in afrothy condition. On the downstroke, the rod andfluid loads above the plunger must compress this gasuntil the pressure above and below the travelingvalve are equalized to allow the traveling valve toopen and discharge the gas and fluid into the tubing.At this time, a pound or shock wave similar to that

produced by fluid pound, only cushioned more,travels through the entire system. Some control canbe maintained if gas separation is possible before thegas enters the pump, but where gas breaks out ofsolution during the pressure drop within the pump,only partial control can be achieved. In a situation wheregas completely fills the pump barrel the pump gaslocks, which means that not enough discharge pressurecan be built within the pump to open either thetraveling or standing valve and production will cease.

A great many pumping wells pound fluid, eitherintentionally or unintentionally, and any well issubject to pounding depending on many pumpingconditions. A fluid pound (Figure 5), as experienced

in rod-pumped wells, is caused by the pump notcompletely filling with fluid on the upstroke. As thedownstroke begins, the entire fluid and sucker rodload move down through a void until the plunger hitsthe fluid level in the pump barrel. The traveling valveopens, suddenly transferring the load to the tubing,causing a sharp decrease in load which transmits ashock wave through the entire rod-pumped system.It is this shock wave that damages the components ofthe pumping system. A fluid pound is alwaysundesirable and rod-pumped system controls shouldbe used to monitor and detect this condition. If fluid

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Figure 2 Figure 3


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pound is suspected, changes need to be made to therod pumped system to eliminate or reduce thepound. The worst fluid pound condition is when thepound occurs at or near maximum polished rodvelocity and the resulting shock wave is greatest.

Properly designed and operated rod-pumpedsystems will not allow the rod string to come incontact with the inside of the tubing. Poorlydesigned rod strings, excessive strokes per minuteand solids in the pump can retard the plunger fallcausing the rod string to stack out and buckle. It isdifficult to predict where rod-on-tubing contact andwear will occur so it is advantageous to eliminate orreduce factors that retard plunger fall. Rod-on-tubing

contact and wear will typically accelerate any otherprocesses that are acting to reduce the usable servicelife of the rod string. The rod string needs to operatein tension and the tubing should be properlyanchored at the lowest possible depth in the well.Properly anchoring the tubing is always recommended justify any decision made that doesnt include atubing anchor!

Wear is defined as the progressive removal ofsurface metal by contact with the tubing. Wearcauses failures by reducing the cross-sectional areaof the metal component, exposing new surface metalto corrosion, and causes connection failures in therod string from impact and shoulder damage. Angled

wear patterns indicate rod strings that areaggressively contacting the tubing at an angle,usually as a result of fluid pound, gas interference,pump tagging, and/or unanchored (or improperlyanchored) tubing. Tubing-slap wear (Figure 6) is theresult of the rod string stacking out during thedownstroke. This extremely aggressive coupling orrod-on-tubing contact is the direct result of severefluid pound, unanchored (or improperly anchored)

tubing, sticking (or stuck) pump plungers, or anycombination of the preceding.

Wear that is equal in length, width and depthusually suggests a deviated or crooked well bore(Figure 7). For a deviated or crooked well bore, it

may be necessary to use injection molded rod guidesto manage the sideloads that occur due to the doglegseverity. For deviated or crooked well bores, aproperly designed injection molded rod guide systemwill allow the rod guide to become the sacrificialcomponent in the rod string and prevent rod-on-tub-ing contact and wear. A wellbore deviation survey isrecommended for proper placement of the rodguides in areas suspected of having high sideloads.When using rod guides, rod rotators are alwaysrecommended to extend the service life of the rodguide by distributing wear around the entire outercircumference of the component.

This article is by no means all inclusive of every

design and operating condition encountered in everytype of rod-pumped system available. It is intendedas a reference guide to help optimize wells. Wheredesign and operating conditions are concerned, thereare no absolutes. But, by recognizing unfavorableoperating conditions through proper failure manage-ment and well monitoring techniques, optimizationpractices can be implemented that will make morewells economically advantages to produce.

11

Figure 4 and Figure 5

Figure 6

Figure 7


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Protecting your investment

in sucker rods

12

Keeping with the theme presented in theprevious three parts of this series, the rodstring is a vital link between the surface

equipment and the subsurface equipment in a rodpumped well. To optimize the service life of the rodstring, it must be properly designed (based uponexperience), physically handled and made-up inaccordance with the recommendations of the manu-facturer, and operated within acceptable designparameters with an effective corrosion controlprogram. An effective corrosion control program thatis properly designed, implemented and optimized

using accepted monitoring techniques, is a criticalconstituent that helps extend the economical servicelife of the rod string. Since most failures can usuallybe categorized as either man-made or well induced,Part 1 (Well Servicing July/August 2005), Part 2 (Well

Servicing September/October 2005), and Part 3 (Well Servicing November/December 2005)of this seriesdealt with preventing man-made failures andrecognizing acceptable design parameters. Now inPart 4, we will attempt to explore some of the morecommonly recognized design, implementation andmonitoring techniques for an effective downholecorrosion control program.

Corrosion definedCorrosion is defined by NACE International as the deterioration of a substance (usually a metal)or its properties because of a reaction with itsenvironment. For the steel components in the rodstring, corrosion is the electrochemical reactionbetween the steel and the corrosiveness of theproduced fluids. This electrochemical reaction willturn your investment, in the rod string, into a worth-less solution of corrosion byproducts (i.e., iron oxide,iron sulfide, iron carbonate, etc.). Some form andconcentration of water (H2O) is present in all wells

considered corrosive and most contain considerablequantities of dissolved impurities and gases. Forinstance, carbon dioxide (CO2) and hydrogen sulfide(H2S) acid gases, commonly found in most wells, arehigh soluble and readily dissolve in H2O whichlowers its potential of hydrogen (pH). The corrosivityof the produced fluid is then a function of the amountof these two acid gases that remain in solution, thepH of the fluid, wellbore temperature and pressure.

Regardless of the steel grade or type, effectivecorrosion inhibition is necessary in any wellconsidered corrosive. Some steel grades or types

may offer enhanced performance in certain aqueousenvironments, but effective inhibitor programs mustbe maintained to adequately protect the steel fromcorrosion. In order to be effective and provide aprotective barrier against corrosion, the inhibitormust be allowed to contact the surface of the steel itis to protect. The preceding statement acknowledgesthat, for effective corrosion inhibition, it is best tostart out with clean equipment. Another aspect ofcorrosion is the steel and its potential to corrode.New steel introduced into an corrosive environmenttypically has a higher potential to corrode thussteel components in the rod string must beadequately protected from corrosion. NACE Task

Group T-1D-3 has prepared recommendations for thecorrosion control of steel sucker rods and theserecommendations are published in the APIRecommended Practice 11BR. These recommenda-tions set forth standard guidelines for applicationmethods, inhibitor selection and treatment programevaluation.

Type and method of treatmentFluid compatibility, fluid volumes, completion

methods and reservoir compatibility determine thetype and method of treatment that is available for


SCOTT MALONE

Norris

Protecting your investment

in sucker rods

Part 4: Corrosion-fatigue induced failuresPart 4: Corrosion-fatigue induced failures


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each well. Fluid analysis is critical to the evaluation oftreating chemicals for compatibility with the fluidproduced by the well. Selection criterion includesusing chemicals that do not create stable emulsions.Selection criterion also includes using treatingchemicals that are not so tenacious as to developundesirable precipitates or gunk when injecteddownhole. Prior to their application, chemicalcompanies should test their chemicals withproduced well fluid in order to prevent operationalproblems related to the chemical treatment program.An effective corrosion inhibitor will create aprotective barrier between the steel rod string andthe corrosive well fluids, but will not create additionalproblems with operating the well. Improper selectionof a corrosion inhibitor may result in increasedsubsurface pump failures, rod failures and problemswith surface production facilities.

Batch treatingBatch treating down the casing/tubing annulus is a

common method of applying corrosion inhibitors.Batch treating involves pre-flush water to wet thecasing/tubing, a high concentration of corrosioninhibitor, and flush water, of a determined volume,that helps disperse the chemical treatment down-hole. A calculated quantity of corrosion inhibitor isadded to the casing/tubing annulus at regularintervals to help promote the continued repair of theprotective inhibitor film until the next treatmentcycle. A basic rule-of-thumb for corrosion inhibitorconcentration is to start at 25 ppm (parts per million),based on the total fluid production volume betweentreatments, and to increase the concentration asdeemed necessary by results obtained from accept-able monitoring techniques. (Use a minimum volumeof 2 quarts corrosion inhibitor per 1,000' of well

depth). Flush volumes will be determined by the welldepth and the dynamic fluid level in the casing/tubing annulus.

Batch treatments are sometimes re-circulated forseveral hours. A relatively large volume of corrosioninhibitor is deliberately re-circulated from thecasing/tubing annulus to the production stream andback again. Batch and circulate treatments helpensure all downhole production equipment surfacesin the well make contact with the corrosion inhibitormore than once.

Continuous treatmentContinuous treatment is another method commonly

used to apply corrosion inhibitors. Continuous treat-ment involves a chemical-feed pump used to injectcorrosion inhibitor at the surface or below the sub-surface pump via a capillary string. A small volume ofproduced fluid is continuously circulated to helpflush the inhibitor down the casing/tubing annulus.Prior to putting the well on continuous injection, apre-treatment application, typically consisting of fiveto 10 gallons of concentrated corrosion inhibitor, isinjected into the casing/tubing annulus. The basicrule-of-thumb for corrosion inhibitor concentration isto start at 25 ppm (parts per million), based on totalfluid production, and to increase the level ofconcentration as deemed necessary by resultsobtained from acceptable monitoring techniques.

Squeeze treatmentsAlthough not a common practice, corrosion

inhibitor squeeze treatments can be effective andlong-lasting. Squeeze treatments involve pumpinglarge volumes of corrosion inhibitor, diluted withsolvent, into the producing formations under highpressure. The inhibitor in the formation desorbs overtime to help maintain the inhibitor film on the down-hole production equipment. A basic rule-of-thumb forcorrosion inhibitor concentration is to start with 50to 75 ppm (parts per million), based on the total fluidproduction for the expected treatment life. Becauseinhibitor compatibility with the formation fluids andthe formation rock is a concern, squeeze treatmentsare generally not used when other treatmentmethods are possible.

Program performanceOnce a corrosion inhibition program is designed

and effectively applied, it is important to monitor theperformance of the program and optimize theinhibitor type or concentration level before failuresoccur. An effective chemical inhibition program isfairly expensive and may be subject to cutbacks ifjustification for this huge expense cannot be made.Non-effective corrosion inhibition programs allow thesystem to become contaminated and may requireextensive cleaning in order to re-establish aneffective maintenance film. By reducing an effectiveinhibition program, it will become difficult tocontinue operating the well economically due to the

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Figure 1 Figure 2


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potential damage incurred by the downholeproduction equipment. In the long run, most wellswill be more economical to operate with effectivecorrosion inhibition programs versus those without.

Monitoring techniquesNACE International recommends using several

monitoring techniques simultaneously, if possible and recommends never relying on any single methodfor monitoring corrosion! Some of the tools typicallyused to measure the effectiveness of chemical

inhibition programs include: (1) water and gas analysis;(2) weight loss coupons; (3) pH measurements;(4) H2S content; (5) C02 content; (6) O2 content;(7) chloride content; (8) iron count measurements;(9) copper ion displacement (CID); (10) corrosioninhibitor residuals; (11) linear polarization; (12)bacterium cultures; (13) bottomhole temperaturemeasurements; (14) bottomhole pressure measure-ments; (15) fluid level measurements; and (16) visualwater quality.

Designing and implementing an effective corrosioninhibition program is a complex subject that isdifficult to cover due to the numerous combinationsof corrodent concentration levels, temperatures,

pressures, compatibility issues, production volumes,and completion methods to name a few. Properselection of the corrosion inhibitor type andconcentration level, application method andmonitoring techniques should help prevent mostcorrosion related failures. However, this article is byno means all inclusive on the subject of corrosioninduced failures. Chemical companies that specializein the design and treatment of corrosion inhibitionprograms are the best source for up-to-date informa-tion about programs recommended for yourparticular application.

Types of corrosion Acid corrosion is a uniform thinning of the metal

surface, leaving the component with the appearanceof sharp, feathery, or web-like residual metal nodules.Corrosion deposits will not be formed in the pits oron the surface of the component (Figure 1).

Acid producing bacteria (APB) has the same basicpit shape characteristics of CO2 acid gas corrosionexcept for the cavernous appearing pit-wall and thestriated or grainy appearing pit-base. The pit will notcontain scale deposits (Figure 2).

Carbon dioxide (CO2 ) acid gas corrosion formsround-based pits with steep walls and sharp pit-edges.These pits are usually interconnected in long linesbut can occasionally be singular and isolated. The pitbase will be filled with iron carbonate scale a corro-sion byproduct of CO2 acid gas corrosion (Figure 3).

Chlorides contribute to the likelihood of anincrease in corrosion related failures in wells withsmall amounts of CO2 and/or H2S acid gas corrosion.Plain carbon steel tends to pit in produced waterscontaining high chlorides. The pitting is usuallyspread over the entire surface of the component withflat-bottomed, shallow, irregular shaped pits thatexhibit steep walls and sharp pit-edges.

Dissimilar metals corrosion may be apparentwhen the less noble metal has a tapered or leechedappearance toward the more noble metal.

Hydrogen blistering is the formation of blisters onor near the metal surface from the absorption ofhydrogen into the metal lattice creating excessiveinternal pressure in the steel (Figure 4).

Hydrogen embrittlement usually leaves the fracturesurface halves with a brittle, granular appearancedue to the immediate shear tear that occurs as aresult of the absorption of hydrogen into the metallattice and the loss of ductility in the steel (Figure 5).

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Figure 3 Figure 4

Figure 5 Figure 6


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Hydrogen sulfide (H2S) acid gas corrosion pits areround-based with beveled walls and pit-edges. Pitsare usually random and scattered over the entiresurface of the component. Both the surface of themetal and the pit-base will be covered with ironsulfide scale a corrosion byproduct of H2S acid gascorrosion (Figure 6).

Oxygen (O2 ) enhanced corrosion pits are broad-based, smooth-bottomed with the tendency for one

pit to combine with another. Pit shape characteristicsmay include steep pit-walls and sharp pit-edges withCO2 acid gas corrosion or beveled pit-walls andpit-edges with H2S acid gas corrosion (Figure 7).

Stray current corrosion generally leaves deep,irregular shaped pits with smooth sides and sharppit-edges.

Sulfate Reducing Bacteria (SRB) has the same basicpit shape characteristics of H2S acid gas corrosion,often with multiple transverse cracks in the pit-base,tunneling around the pit-edges (aka pits-within-pits),pit clustering, and/or unusual anomalies (i.e. shinysplotches) on the surface of the component(Figure 8).

Figure 7

Figure 8

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