IADC Drilling Manual Part 7 ppt

When the seat is firmly in place, most manufacturers recommend you place an old valve on the seat and strikeseveral blows on the upper stem with an old pump rod or similar object to driv

Figure J4-37 Protection of Studs while using Wedge-type Pullers

Figure J4-37 When wedge-type pullers are used on pumps with stud-type valve pet covers, a rag inserted in thecrotch of the wedge will protect the studs

Figure J4-38 Pulling the Valve Seat

Figure J4-38 The valve seat is then pulled by striking the wedge with a sledge hammer

Figure J4-39 Valve Seat Puller Assembly

Figure J4-39 This photograph shows the entire valve seat puller assembly immediately after it has been removedfrom the valve pot

Hydraulic jack pullers employ the same type puller head as the wedge type only the stem is longer for the jack.Place the jack over the stem on the two piece block and install the nut Insert the "C" washer between the top ofthe jack and the nut Release the fluid return valve to compress puller and bring the nut up as tight as possible

To prevent injury when the seat releases and pulls out of the deck, secure a safety chain around the pulling bly, Figure J4-35

assem-On duplex and single acting "L" head pumps all the valves are accessible from the top and may be changed easily.However, on single acting cylinder head pumps the intake valve is directly below the discharge valve and requires

a special pulling tool, Figure J4-40

Figure J4-41 Washing Out the Valve Pot after Removing Valve Seat

Figure J4-41 The entire valve pot should be washed immediately after removal of the valve seat

The deck should be carefully inspected for damage of any sign of fluid cutting

Any damage to pump deck should be repaired before installing new valve seats

Clean the pump deck thoroughly, removing any accumulation of rust or dried mud at the bottom of the machinedtapered surface If there is a shoulder at the bottom of the deck it must be thoroughly cleansed A build-up of rust

or mud in these areas will prevent the seat from seating properly in the taper, Figure J4-42 and Figure J4-43

The new valve seat is coated with a rust inhibitor, which must be thoroughly removed before installation in thepump Remove the inhibitor with diesel oil or some other suitable solvent, and wipe dry with a clean cloth The seatshould be installed immediately after cleaning If heat was used to remove the old seat, be sure the pump deck iscool to touch before attempting to install the new seat Place the seat in the taper and press down firmly with yourhand.

This pressure should be sufficient to cause the seat to stick to the taper There should be good contact all the wayalong the taper of the seat and the deck If the seat will not stick in the taper and make good contact all the wayaround, remove the seat and inspect the mating surfaces again to be sure you have sufficiently removed the

accumulation of rust and mud from the pump deck and that there are no nicks, burrs or pieces of weld spatter onthe taper Also check the part number to be sure it is the correct part for the pump

When the seat is firmly in place, most manufacturers recommend you place an old valve on the seat and strikeseveral blows on the upper stem with an old pump rod or similar object to drive the seat into the deck You canusually tell from the sound when it is properly seated This step is very important Do not rely on pump pressure tomake this initial seal within the pump, since this may allow drilling fluids to seep between the seat and the decktaper causing leaks and wash outs

Before installing the valve in the pump, check the fit of the valve stem in the valve cover guide If the valve coverguide is found to be egg-shaped, or if the clearance around the valve stem is greater than 1/16", the pot coverguide should be replaced

Now install the valve in the pump NOTE: Never install old valves in new seat or new valves in worn seat, FigureJ4-44

Figure J4-44 Never Install Worn Valves in New Seat (and vice versa)

Remember when installing new valves in the pump, always use new springs to insure long trouble-free servicefrom valves and seats; otherwise, check springs for signs of corrosion, loss of tension, physical abuse or wear.Before installing the pot covers, thoroughly clean the sealing surface Lubricate both the sealing surface and thegasket with a general purpose grease Remember: always use new gaskets

Prime the pump through all pots and install the pot covers Make up to the proper torque recommended by thepump manufacturer

J-5 Pump Problems, Failures and Analysis

I Priming and Starting Instructions

Once the pump rod, cylinder heads and valve seats are installed, the pump is ready to be primed through all valvepots Before installing the pot covers, be sure that the sealing surface and gaskets are cleaned and lubricated withgeneral purpose grease Make up the studs to the torque that is recommended by the manufacturer

If prechargers are available, they should be used so that the pump will be sure of getting complete prime and thatentrained air in the mud pump will be easily worked out

The mud pump should be brought up to operating pressure gradually On a duplex pump a crewman should cheek

to make sure that the rod packing is getting sufficient lubrication

Rod packing leakage can be checked by momentarily pulling the rod lubricator line out of the gland nut and ing if any mud is coming through the packing while the piston is moving toward the power end of the pump

observ-Reinstall the lubrication line On triplex pumps check the liner coolant system to assure adequate volume of coolant

in the liner

Pot covers and tattle tale holes should be checked to be sure that there is no oozing of mud or excessive breathing.During the break-in period, the liner packing is also seating and expanding into all the voids and crevices At theend of approximately a two hour period, the pump should be shut down and the liner packing retightened Anymovement of the liner will allow abrasive mud to get into the packing housing causing undue wear to the pumpsurfaces

Never tighten liner packing while the pump is under pressure

II Pistons and Liners

A Excessive Wear of Liner and/or Piston Body

In low pressure (less than 850 psi) service, when a total clearance of 3/32 or more occurs between piston flangeand liner wall, the piston and/or liner should be replaced depending on wear of each At medium (850 psi to 1600psi) to high pressure, 1/16 clearance should be the limit At extreme pressures (1600 psi to 3200 psi) and othersevere operating conditions 0.040 clearance and the piston and/or liner can be considered "worn out" The contin-ued use of worn liners or pistons will result in short service life of piston rubbers Do not use worn pistons in newliners or new pistons in worn-out liners

B Streaking of Liner Bore and Piston Rubbers

This condition is generally caused by excessive sand or other abrasive or foreign materials in the drilling fluid.Keep drill fluids as clean as possible and inspect the liners frequently when the pump is shut down

C Pitted Liner

This indicates corrosive conditions, pH of mull should be checked and increased if too low (below 7.2 pH) sion inhibitors may be considered If corrosion is severe, the use of corrosion-resistant liners may be indicated

Corro-D Concentration of Wear on One Side of Piston or Liner

Normally a piston body will wear more on the lower side than the upper If eccentric wear is excessive, or if itoccurs at points other than the lower side, misalignment may be indicated Check for worn crosshead slides, wornpump bores, worn stuffing boxes and junk rings, and unequal tightening of liner rod packing

E Swollen and Torn Piston Rubbers

The use of regular (natural rubber) piston rubbers in oil emulsion or oil contaminated mud will result in swelling anddeterioration of the rubber The use of oil resisting piston rubbers in oil emulsion muds with low aniline point oilscan also result in similar swelling and deterioration In the latter case, failure of other parts such as pipe protectors,blowout preventer rubbers, etc will probably occur also, Figure J5-1

Figure J5-1 Buna N Rubber in Low Aniline Diesel Oil

Figure J5-1 This "Buna-N" rubber has been run in an oil emulsion mud with a low aniline point diesel oil

Note the evidence of swelling of the face and chunks of rubber broken out of the body of the piston rubber caused

by the deteriorating effect of the low aniline point diesel oil The aniline point of the diesel oil being added to themud must be above 150°F to prevent deterioration of all rubber goods which come in contact with the mud

F "Burned" Piston Rubbers

A starved suction or starting the pump without priming results in "burning" the piston rubbers in dry lines Rapidfailure will result after burning has occurred and it is sometimes difficult to trace or identify the failure A "squeal-ing" in the cylinders when starting the pump or trying to pick up a prime indicates probable damage, Figure J5-2

Figure J5-3 Liner Damaged by Excessive Tighening of Liner Packing

Figure J5-3 This liner was ruined by excessive tightening of the liner packing

The most common cause for this damage is failing to loosen the liner packing adjusting screws before tighteningthe cylinder head nuts

III Fluid End Piston Rod and Packing

A Rod Broken Through Taper (Duplex Pumps)

This type break can be caused by pump misalignment Check for unequal wear on piston rod, piston body or linerfor evidence of misalignment Break can be caused by a notch or a stress concentration point or improper torque

on the HP taper make-up so that the joint is not prestressed

B Rod Broken in Cross-Head or Pony Threads

Cross-head thread breakage is frequently due to out-of-square jam nuts, but pump misalignment can also causesuch breakage

The use of an out-of-square jam nut can produce a stress concentration of up to ten times that of one having theproper fit, Figure J4-12

C Rod Breakage in Body of Rod

Failure of this type can be due to cracks started by hammer blows or other external rod damage Don't hammer onthe body of the rod to remove the piston, Figure J4-18

D Rod Pulled Apart in Taper End Threads (Duplex Pumps)

These breaks are found exclusively in the smaller tapers and are generally the result of overtightening the pistonand nut when making the piston up on a rod, Figure J4-24

E Single Acting Piston Rod Problems

Overtorquing of piston rod nut can cause rod breakage, thread galling and other installation and removal problems.Reference Figure J4-24 Torque for API Rod Connections for torque values

Inspect rod at clamp or thread end for cracks in flange and/or threads, as well as wear Also inspect clamps forwear With a clamp in good condition and tightened properly there must be no movement between clamp and rod

F Rapid Wear or Streaking (Duplex Pumps)

Overtightened or wornout gland packing, inadequate lubrication, or high sand content are chief causes High pumppressures aggravate any streaking tendencies that may be present If wear or streaking is concentrated on oneside of rod, check pump alignment or check for uneven tightening of the packing gland Recirculation of sand in thecoolant system can also cause streaking Too viscous a fluid so that fluid does not flow around entire rod also cancontribute to streaking

G Pitted or Streaked Rod Due to Pitting (Duplex Pumps)

Corrosive drilling fluids or corrosive water lubrication are responsible Use chrome-plated or hard coated pistonred

H Chrome Worn Off Rod (Duplex Pumps)

Chrome plated piston rods have a hardened surface beneath the chrome plate and should not be replaced justbecause the chrome has worn off if chrome has worn in smooth Replace when worn 1/16" to 3/32" total wear,depending upon operating conditions At pressures above 2000 psi, 0.045 wear is generally all the wear that can beaccommodated without excessive packing replacement

I Washed Out Taper or Piston Pushed Up on Rod Taper (Duplex Pumps)

Improper installation is responsible for the majority of these failures Both piston and rod tapers should be cleanand dry and proper torque used when piston is made up on rod, Figure J4-23

J Short Packing Life (Duplex Pumps)

Over tightening of packing, insufficient lubrication, high sand content, or use of worn-out rods with new packingare generally responsible Worn junk rings, misalignment, or unequal tightening of the gland are other possiblecauses, as well as wash outs on worn stuffing boxes

IV Valves and Seats

A Fluid Cut Sealing Members or Parts

These failures are generally due to foreign material or lost circulation materials in the mud, or continued use ofnew sealing members on worn metal parts Check all parts for wear, including upper valve guides, and replace ifworn out

B Fluid Cut Taper of Seat and Pump Deck

Most cutting between the seat and deck is due to failure to realize the importance of proper installation and

replacement of valve seats, Figure J4-43

Careless use of cutting torch in removing valve seats can result in damaging the deck so that the new seat will notseal properly If a deck needs reworking, it should be done before a new scat is installed and qualified personnelshould do it

C Abnormal Wear or Breakage

The use of new parts combined with worn-out mating parts frequently results in very rapid failure of either or boththe new and worn part, Figure J4-44

Improper application sometimes results in similar failures of new parts Proper selection of parts for the operatingconditions will eliminate these troubles Rapid wear results from high sand content in the drilling mud and if thesand content cannot be controlled or reduced, more frequent replacements will be necessary

Proper lift, with adequate guiding and correct springs are necessary for optimum valve life and performance

V Reducing Pump Volume

Pump manufacturers agree that reducing pump volume should be done be reducing pump speed and/or reducingliner size If neither of these can be done, and under short emergency conditions, the following methods have beenused

A Duplex Pumps

The discharge volume in any constant speed duplex pump may be reduced by removing valves as illustrated inFigure J5-4

Figure J5-4 Volume Reduction by Removing Valves

FIGURE J5-4: Reduce volume by removing valves as shown

B Triplex Pumps

There are at least two methods that have been used:

1 Remove the center suction valve only, or

2 Blank off center cylinder by welding a plate in the liner bore

Before any method is used, manufacturer should be consulted for his recommended procedure

REDUCING DUPLEX PUMP VOLUME BY REMOVING VALVES

At any constant pump speed the volume discharge may be reduced by removing valves in the following manner:For 25 % volume reduction, remove discharge valve No 8

For 50% volume reduction, remove discharge valves No 2 and No 8

For 75 % volume reduction, remove discharge valve No 2 and suction valves No 5 and No 7

VI Centrifugal Pump Care and Maintenance

A carefully planned and carried out maintenance program extends pump life, maintains high pump dependabilityand rated performance, and reduces overall operating costs The three primary areas of pump care are generaleffects of erosion and specific problems of packing and bearings

Erosion is wear caused from the impingement effect of the fluid The wear from erosion is increased when

abrasive solids are suspended in the fluid Discontinuities in the flow passage, such as exposed gaskets, abruptchange of pipe size, and sharp corners, are particularly susceptible to erosion They cause a change in the direction

of flow that creates eddy currents and instantaneous velocity increases

A centrifugal pump which has been carefully selected for its application will show less wear and that wear will beuniform thus affecting performance less A pump that is the wrong size or the wrong design for its service canvery likely fail prematurely

As a pump wears, impeller clearances are increased, and the pump's performance is reduced Pumps that depend

on close clearances for effective performance show the most rapid reduction in performance For this reason only

a pump designed for slurries should be used in that service These pumps do not depend on such close impellerclearance, internal discontinuities are eliminated, fluid passages are large to minimize high velocities, and impellerdiameters and shafts are larger so the pump can be run at reduced speeds

Packing problems most usually are caused by difficulty in maintaining proper lubrication between the shaft andpacking The shaft and packing must be lubricated to prevent shaft scoring and wear as well as packing wear.The most common method for lubricating packing is to allow leakage The most common cause of packing difficul-ties comes from preventing this kind of lubrication by overtightening Tight packing causes excessive heat thatwears the shaft and packing As a result, the shaft is scored and packing must be replaced frequently And it isvirtually impossible to maintain reasonable packing life or to seal against a rough shaft

Usually the line fluid is used as a lubricant However, if it contains abrasives, it is not suitable and another lubricantmust be introduced into the stuffing box at the lantern ring Around a drilling rig the best such external lubricant iswater free from abrasives But it's pressure must be sufficient to force it into the stuffing box and to keep theabrasive line product from entering the stuffing box

Packing life is also reduced at higher shaft speeds So one more important point in pump selection is to pick thepump that will do the job required at the lowest speed

When repacking the stuffing box, first make sure the box is clean and all old packing is removed Place packing inthe bottom of the box that, when compressed, the lantern ring will be in the proper location beneath the sealing tap.(Figure J5-5)

Figure J5-5 Installing King Type Packing

The ring joints should be staggered Draw up snug only by means of the gland Pack the remainder of the box,draw up snug and back off the gland until the nuts are finger-tight Packing expands with heat, and a box which ismore than finger-tight when cold, will generally smoke when started up

Tighten nuts half a turn at a time and wait to see if leakage has been controlled to desired rate Do no run droptight Some drippage is required to cool packing

Water to the packing lantern ring is recommended when the stuffing box pressure is below atmospheric pressure.Where water cannot be used, grease as often as required to maintain an air seal Water flushing also prolongspacking life in abrasive service

NOTE: Do not add extra packing rings when excessive leakage occurs

The third important factor in pump performance is proper care of the bearings Several factors can affect their lifeand performance Mechanical unbalance produces excessive loads, as does misalignment of the pump because ofimproper or poor piping foundation Excessive cavitation also causes unusual vibration loads on the beatings,resulting in premature failure Solids that ball up and plug the impeller cause a mechanical unbalance and corre-sponding vibration loads that are damaging Overtightening the beatings cause the lubricant to break down whileexcessive lubrication causes beatings to overheat

But the most important bearing problems come from contamination Dirt and grit in the bearing race cause rapidfailure Moisture within a beating enclosure (usually entering from contaminated lubricant) causes rust and corro-sion with subsequent bearing failure Cleanliness cannot be overemphasized You should not need to regrease thepump unless the original grease becomes contaminated Disassemble the pump and remove old grease Hand packthe bearing and fill the bearing cap approximately 1/3 full with clean grease

An increase in bearing temperatures (above 200°F) or noise indicates possible bearing failure Complete bearingfailure usually damages other pump parts Try to prevent complete bearing failure by changing when the aboveconditions are detected

VII Checklists

A Checklist for Start Up

1 Coupling Aligned

2 Pump Full of Fluid

3 Suction Valve Open

4 Water on Stuffing Box (In case of double seal)

5 Oil Full (If Oil Lubricated)

6 Pump Rotates Freely by Hand

B Checklist for Trouble-Free Suction

1 Keep suction flooded This will eliminate priming problems

2 Make suction pipe as short and straight as possible

3 Make suction pipe one size larger than pump suction flange and one pipe; size larger than the dischargepipe

4 If a reducer is used, use an eccentric reducer with all eccentricity at the bottom

5 Suction line must be leak-free to keep air out of the fine

C Checklist for Increased Packing Life

1 Use proper pump for application

2 Keep packing box and shaft clean

3 Do not overtighten packing Allow leakage if line product is not abrasive

4 If abrasives are present, lubricate externally with clean liquid under pressure

D Checklist for Maximum Bearing Life

1 Choose proper pump for application

2 Do not let bearings overheat

3 Keep bearings and enclosure free of dirt and contamination

4 Check Bearing alignment

5 Check drivers, piping, and foundations to prevent excessive loads cause by misalignment

6 Do no press or hammer on bearings when installing

7 Lubricate properly neither too much nor too little, with clean lubricant

8 Clean impeller and casing after using if it will be more than a week before pump is to be used again

9 Do not apply excessive external loads to pump, such as pipe strain, which cause a load on the bearings

E Table J5-P6 Centrifugal Pump Trouble Shooting Guide

J6 Power End Maintenance

The power end of a slush pump is essentially a "speed reducer slider crank mechanism" used to translate therotating motion of the power source to the reciprocating piston action required for the pumping fluids Gears,bearings, crossheads and crosshead liners are all utilized in most conventional mud pump power end designs.Reliable long life service from these items is primarily dependent upon proper lubrication Therefore, routine powerend maintenance must focus upon the pump's lubrication system and the care and periodic inspection of compo-nents associated with it

A Lubrication

Proper functioning of the power end lubrication system requires that: the correct type and quantity of lubricant bemaintained in the power end sump, contaminants and excess heat be continuously removed from the lubricant, thelubricant be properly distributed to all moving components, and the power end lubricant be completely segregatedfrom the drilling mud and water in the fluid end rod chamber

To accomplish these requirements, slush pumps are equipped with: various filter and/or magnet assemblies tocapture contaminations, dipsticks or sight glasses to check oil levels, a pressurized flow or splash-gravity flowlubrication system for distributing the lubricant to various components, and various sealing wiper arrangements onthe crosshead extension rod to prevent drilling mud from entering the power end Each of these items will besubsequently reviewed in more detail, but first let us pause to examine the importance of the proper lubricant in thepower end

All slush pumps are equipped with bearings, crossheads, and gears (chains and sprockets in some instances) whichmust be continually supplied with the correct type and quantity of lubricant Usually a high grade, extreme pressure(EP) gear oil is recommended by most manufacturers These gear oils must be capable of maintaining a lubricantfile on all bearing surfaces and gear teeth under varying operating speeds and loading conditions Failure to do socan lead to rapid wear and ultimate destruction of bearings, gears and crossheads

Pump manufacturers have thoroughly analyzed the operational speeds, loads, and temperatures of their pumps andhave specified lubricant viscosity grades and additive recommendations which should adequately protect againstcomponent wear and corrosion Lubricant recommendations are usually based upon temperature of the lubricantitself within the pump Rather than recommend particular brands of lubricant for the pump, many pump manufac-turers prefer to simply state the viscosity grade requirements for various temperature ranges (Refer to pumpmanufacturer's specific lubricant recommendations) The drilling contractor is then at liberty to contact his local orpreferred bulk lubricant distributor, and arrange for them to furnish a lubricant which complies with the pumpmanufacturer's recommendations

In the past several years confusion has been observed between pump manufacturer's, drilling contractors, andlubricant suppliers as to whether or not lubricants with the correct viscosity characteristics are being furnished andutilized in the pumps If the pump manufacturer's classification system is not the same as the lubricant supplier'snomenclature and if efforts are not taken to cross reference the information, errors can and do occur These errorshave resulted in the gears, bearings, and crossheads being overheated, pitted, scored, and effectively deteriorated

to an unacceptable condition

To eliminate confusion between various classification systems, Figure J6-1 compares AGMA lubricant numbers,SAE gear oil numbers, and ISO viscosity grades

Figure J6-1 Viscosity Classification Systems

Kinematic viscosity in centistokes (cSt) at 40°C, and viscosity in Saybolt Universal Seconds (SUS) at 100°F arealso presented for the different classification systems

B Lubricant Contamination

Contamination of the gear oil in the power end is an inevitable by-product of slush pump operation Metallic

particles may be worn off the working surfaces of the gears, bearings, and crossheads Dust and other debris mayenter the power end through the air breather or through worn crosshead extension rod wipers Water may alsoenter the power end through damaged or worn crosshead extension rod wipers, or it may condense as a result oftemperature changes within the power end Oil may be oxidized due to high operating temperatures and chemicalreactions of the oil with oxygen in the air

Dust, dirt and metallic particles in the gear oil can attach moving components with an abrasive, lapping actionwhich can quickly lead to excessive clearance in bearings and scoring of the gears and crossheads Water in thepower end quickly mixes with the gear oil as the pump operates, and imparts a cloudy or milky appearance to theoil This condition will frequently cause rusting and corrosion of bearing surfaces, and accelerated wear on loadcarrying members due to thinning and breakdown of the lubricant's film thickness Oxidation causes darkening ofthe gear oil color and leads to sludge formation in the sump and oil troughs

To protect against the detrimental effects of gear oil contamination, most pump manufacturer's recommend thegear oil be changed every six months, or as frequently as required to maintain a relatively clean, sludge free oil.Maintaining a clean, quality lubricant in the power end of the mud pump is the best insurance available for reliable,long life service from slush pump power ends

C Lubrication Systems

Several systems are used in slush pump power ends for collecting and distributing gear oil to the various nents requiring lubrication The pressure flow system, the splash-gravity flow system, and a combination of thepressurized flow and splash-gravity flow systems are used by different pump manufacturers to fulfill the lubricationrequirements of their particular pump design

compo-The pressurized flow system is the most commonly used lubrication system This system relies upon a small gearpump to circulate lubricant from the sump and to force it under pressure to various lubrication points Pressurizedflow systems are frequently equipped with heat exchangers, pressure and temperature gages, filters, and a lowpressure alarm the pressure and temperature gages should be checked once every tour for correct lubricationsystem operation

The splash-gravity flow system, used either singularly or in conjunction the pressurized flow system, relies upon therotation of the main gear of the pump to pick up lubricant from the sump Wiper arms or troughs are mountedadjacent to the gear to catch oil from the gear and distribute it to the bearings and crossheads Proper operation ofthis arrangement requires that the pump speed be maintained above a certain minimum and that the wiper armsare adjusted properly with respect to the main gear At every routine oil change, the adjustment of troughs andwiper arms should be checked and the fasteners which retain these members in position should be checked for thecorrect tightness

D Lubrication System Magnets and Filters

To assist in the removal of contaminants from the power end gear oil, pump manufacturers have incorporatedfilters and/or magnet assemblies at strategic points in the power end lubrication system Pump designs whichrequire a pressurized flow of lubricant to the bearings and crossheads, generally have a filter or strainer screeninstalled in the lube pump's plumbing to remove debris from the lubricant Filters equipped with gages or "conditionindicators" should be routinely checked to be sure that the filter is not clogged and in a by-passing condition.Magnet assemblies are also installed at various locations in the power end to collect ferrous (iron) particles whichare gradually worn from the load carrying surfaces of gears, bearings and crossheads Pump designs which use anoil splash-gravity flow type lubrication system usually have multiple magnet assemblies in the upper lubricationtroughs, crosshead oil reservoirs, and in the sump Pumps equipped with pressurized flow type lubrication usuallyonly have a sump magnet and possibly a magnetic rod canister installed in a lubrication plumbing linc

Filter cartridges, strainers, and magnets should be cleaned or changed at every routine power end oil change.Anytime insufficient lubrication pressure is monitored on a power end equipped with a pressurized flow lubricationsystem the filter and strainer should be checked for plugging

E Crosshead Extension (Pony) Rod Wipers

Crosshead extension rod wipers (Figure J6-2) are the vital barrier between the power end and piston rod bers, confining gear oil to the power end and the splashing or spraying water and drilling mud to the rod chamber

cham-Figure J6-3 Drilling Mud Contamination of Triplex Slush Pump Power End

Figure J6-4 Faulty Wipers Cause Mud Contamination

FIGURE J6-4: Faulty wipers shown on the crosshead extension rod caused the power end contamination shown inFigure J6-3

Crosshead extension rod wipers should be inspected daily for sign of fluid leakage and lip wear If a grease fitting

is installed in the wiper housing, the seals should be greased daily with one or two strokes of a hand grease gun Tomaximize protection of the power end, an annual change out of these wipers should be performed

F Settling Chamber

Many triplex slush pumps are equipped with a power end lubricant settling chamber (Figure J6-5) or sludge traplocated beneath the crossheads and forward of the gear oil sump

Figure J6-5 Settling Chamber

The purpose of this settling chamber is to provide a means for collecting and segregating water and other nants from the gear oil

contami-Water can condense in the power ends of the mud pumps or enter the power end, together with drilling mud andsand, through worn crosshead extension rod wipers If these contaminants were permitted to settle abundantly inthe main gear oil sump, they would be continually mixed with the gear oil and recirculated through the pump.Excessive contamination of the gear oil would then lead to rapid wear of moving components

To help minimize power end lubricant contamination, lubricant flow from the crosshead area is directed into thesettling chamber Solid material and water will settle to the bottom of the chamber, while the lighter gear oil rises tothe upper part of the chamber and flows back into the gear oil sump

The settling chamber is usually equipped with cleanout plates and drain plugs on each side of the pump Once aday the drain plugs should be pulled to permit any water accumulation in the chamber to be drained off Duringroutine oil changes the cover plates should be removed and the chamber cleaned of all mud, sludge, and debris

G Gear Oil Reservoir

The gear oil sump must be thoroughly cleaned during every regular oil change Accumulations of drilling mud andsludge must be removed to avoid contaminating the new gear oil The gear oil reservoir and power end framewalls must also be routinely cleaned to facilitate the proper dissipation of heat from the lubricant to the air sur-rounding the sump Small cover-plates are usually provided on the sump to permit access for cleaning

H Lubricant Dipstick and Sight-glasses

The gear oil dipstick or sight-glass is a very simple instrument attached to the power end reservoir, yet it is ably the most important maintenance tool provided to the slush pump mechanic The dipstick or sight-glass not onlypermits checking of the lubricant level in the pump, but frequently assists the mechanic in monitoring contaminationbuildup in the gear oil Failure to maintain the proper oil level within the power end can result in: marginal lubrica-tion of moving components, pump overheating, and rapid wear of components

prob-The lubricant level in the power end reservoir should be checked at least once a day with the pump shut down It

is usually best to wait several minutes at, er shutting a pump down before checking the lubricant level This willallow the lubricant level to stabilize in the reservoir and permit accurate readings

I Pump Storage

When slush pumps are to be put into storage certain precautions must be taken to prevent corrosive deterioration

of pump components The cost of the precautionary measures is usually small compared to the loss of drilling timeand expenses involved in reconditioning and replacing corrosion damaged bearings, seals, piston rods, and fluidcylinder components

The power end sump and settling chamber should first be drained and thoroughly cleaned A rust inhibiting oilshould be sprayed on all bearings, finished surfaced, and the entire inside surface of the power end To provide aircirculation and prevent condensation build up, the drain plug may be removed and a wire mesh screen (for rodentexclusion) secured over the opening

On pump equipped with pressurized, forced flow lubrication systems, clean gear oil should be induced into the oilcirculating pump, filter housing, heat exchanger, etc

If the exterior paint on the pump has begun to deteriorate or is extensively chipped, a quality machinery paintshould be applied For maximum frame protection against rusting, all painting operations should be preceded by thenecessary sanding and surface preparations

To provide corrosion protection for the fluid end of the pump, the valves, valve seats, piston rods, and liners should

be removed from the fluid cylinders, and all components thoroughly cleaned and dried Coat the cylinder bores, allvalve cover and cylinder head components, and the reusable expendable parts with a rust preventative or grease.The triplex pump's liner spray system must also be protected against corrosion while in storage All water, sand,and debris should be flushed from the liner spray pump, coolant reservoir and associated hoses, spray nozzles andtubes Spray all components with a rust inhibiting oil and fill the liner spray pump housing with oil

While in storage the pump should be thoroughly inspected at least once each month and recoated, where sary, with a rust inhibiting oil Always rotate the pump gears during each inspection This procedure will permitredistribution of the rust inhibiting oil over the surfaces of the bearings

neces-J7 Preventive Maintenance

I Planned Preventative Maintenance

The primary goal of a Preventative Maintenance Program is to help the contractor realize and control fluid lating equipment costs It is possible to control mud pump costs, if the life of fluid end parts can be reasonablypredicted so that they can be pulled before failure This will save money because when a part is run to failure, thepump goes down likely when it is needed most, and the odds are that another part is damaged or is due to failsoon At this time, money is being lost; money is coming out of the contractor's pocket Some of this lost money is:Lost Footage that all-important portion of the hole before the driller reaches contract depth, each hour of notdrilling represents lost revenue new to be recovered

circu-Damage to Other Parts A piston run to complete failure will almost invariably take the liner with it

A liner costs four (4) to eight (8) times more than a piston

Man Hours on the Pump In addition to the cost of the liner, how often does the crew complain about alwaysgoing into the pump?

How many times has someone been hurt working on the pump?

How does a Preventative Maintenance Program operate? If a part is replaced before it fails, the changeout can bemade at a time most convenient to the contractor not when it is unexpected or costly to be down Parts that areleft in will not be damaged and can be expected to run their full life

Those few cents per hour wasted, Figure J7-1, by the item pulling apart with few hours life left on it, are more thansaved

Figure J7-1 If a Part is Replaced Before it Fails

The "Cost per Hour" is out on the flat portion of the curve and the savings are very small compared to the riskinvolved How much do you save by running the risk of shutdown attempting to get another 50-100 hours use out

of a part Schedule pump downtime, reduce pump downtime, and rig downtime, by changing parts in groups If apart is worn out, its companion is very nearly so By changing parts of the pump in a group, you eliminate the

continual going into the pump Since you can program a part and know when it is time to be replaced, you can thenplan all your events or activities so that the pump is never down while drilling is in progress.

Compare Figure J7-2 to Figure J7-3 where pump is shut down 12 times in 3600 hours compared to 28 times in

3600 hours

Figure J7-2 Maintenance Schedule Chart

Figure J7-3 Maintenance Schedule Chart

II Establishing a Preventative Maintenance Program

FIRST, run sufficient parts in the pump as to establish what can be expected for parts life

For example, what is the average liner life?

How long does a piston last?

How long does a rod last?

What is the 'life of the rod packing and liner packing?

How long do valves and seats last?

SECOND, once you have determined "the average life of these components", can the products with similar life beoperated as a unit?

For example, can a piston and a rod called Unit "A" be operated for say 300 hours, or 500 hours, or 600 hours?Can a liner and liner packing called Unit "B" be operated for 600 or 1000 or 1200 hours?

What is the life of valves and seats called Unit "C", 1200 hours, 2000 hours, or 2400 hours?

THIRD, can these units be arranged in some multiple of each other?

For example, two Unit "A's" for one Unit "B"?

That would require changing two pistons and two rods for each liner, or can two Unit "B's" be changed for oneUnit "C"; in other words, every second liner change the valve and seats

If these products have similar life and can be operated as a unit, then we are ready to start programming, Table J7-1

Table J7-1 Parts Life Program

FIRST: Run Sufficient Parts to Establish What Can Be Expected for Parts Life

Liner Life

Piston Life

Rod Life

Rod Packing Life

Liner Packing Life

Valve and Seat Life

SECOND: Can The Products With Similar Life Be Operated As a Unit?

Possible Combinations Pistons and Rods Unit A 300 500 600

Liners and Liner Packing Unit B 600 1000 1200

Valves and Seats Unit C 1200 2000 2400

THIRD: Can These Units Be Arranged in Some Multiple of Each Other?

2 Unit A's for 1 Unit B (Change 2 Pistons and Rods for Each Liner)

2 Unit B's for 1 Unit C (Change 2 Liners for 1 Valve and Seat Change)

When to replace parts is "just before failure!"

This gives the longest life and the lowest replacement cost When the pump pressure falls, it is too late!

There is a wash out somewhere, between:

piston and rod,

piston and liner,

liner and pump,

valve and seat,

seat and deck,

line pipe and drill pipe, etc.,

usually somewhere in a joint Two pieces are damaged or destroyed

This is what programming does; pull the part just before failure.

III Advantages of programming:

1 If you know when an event is to occur, then plan your operation or activity around it

2 It is the most economical way to operate

a No lost footage

b No rig downtime

c No damage to other parts because of failure

d Reduce man-hours working on pumps

3 Able to plan material flow so that sufficient parts are at rigs, warehouse, or supply stores

4 Material requirements for overseas or isolated locations can be determined beforehand

5 Fluid end costs known beforehand and can be used in bidding

6 Crew can be instructed beforehand as to what to change and when to change

This Page Left Intentionally Blank

Chapter K Well Control Equipment and

Procedures

Table of Contents - Chapter K

Well Control Equipment and Procedures

Disclaimer and Credits K-3 K-1 Blowout Preventer Stack Equipment K-5

I Annular Type Blowout Preventer K-5

II Ram Type Blowout Preventer K-6 III Typical Bop Stack Arrangement And Testing Procedures For A Surface Stack K-11

IV Inside Blowout Preventers K-36

V Choke Manifold K-43

VI Diverter Systems K-46 K2 Blowout Preventer Control Systems K-54

A Surface Bop Stacks, (Land Rigs, Offshore Jackups, And Platforms) K-54

B Subsea Bop Stacks K-61

C Remote Operated Choke Controls K-71

D Diverter Control Systems K-73

E Control Systems Typical Capacity And Performance Data / Calculations K-77 K3 Well Control Procedures K-92 Basic Principles K-92

II Pre-kill Procedures K-93 III Formation Pressure Integrity Information K-96

IV Kill Techniques K-99 K-4 Glossary of Well Control Terms K-108

The following industry representatives have contributed to the development and updating of this chapter:Bill Bingham, Chairman MH Koomey, Inc.

John Altermann Reading & Bates Drilling Company

Ralph Linenberger Global Marine Drilling Company

Fred Mueller Reading & Bates Drilling Company

Larry Odelius Cooper Oil Tools

Robert Taylor Zapata Offshore

Richard Grayson Reading & Bates Drilling Company

Figure K1-2B Subsea BOP

There are typically 3 or 4 ram preventers in a BOP stack

Flanged or hubbed side outlets are located on one or both sides of the ram BOPs These outlets are sometimesused to attach the valved choke and kill lines to The outlets enter the wellbore of the ram preventer immediatelyunder the ram cavity

Other than sealing off the well bore, rams can be used to hang-off the drill string A pipe ram, closed around thedrill pipe with the tool-joint resting on the top of the ram, can hold up to 600,000 lbs of drill string

Several different types of rams are installed in the ram type BOP body The four main types of rams are PipeRams, Blind Rams, Shearing Blind Rams, and Variable Bore Rams Following is a brief description of each type:

Blind Rams

Blind Rams - the rubber sealing element is flat and can seal the wellbore when there is nothing in it, i.e "openhole" (See Figure K1-3B)

Figure K1-5B Variable Bore Rams

Shearing Blind Rams

Shearing Blind Rams - the blade portion of the rams shears or cuts the drill pipe, and then a seal is obtained muchlike the blind ram (See Figure K1-6B)

Figure K1-6B Upper and Lower Shearing Blind Rams

NOTE - Special shear rams can be made capable of shearing multiple tubing strings and large diameter tubularswhile maintaining a reliable wellbore pressure seal

B Operation And Use Of Pipe Rams

As described earlier, pipe rams are designed to fit around certain diameter tubulars to seal off the wellbore lus) in a blowout situation Most pipe rams are designed with replaceable elastomer packers and top seals Besidessealing off the wellbore in an emergency situation, the pipe rams can be used for stripping Use of two ram-typepreventers would only be resorted to if the annular preventer was badly worn However, stripping drill pipe throughrams can be done with less string weight than if the annular preventer is used, since there is no closure around thelarger diameter of the tool joints One additional ram-type BOP must always remain available below any used for

(annu-stripping, to allow the well to be closed in safely.

C Stripping With Ram-type Bops

Stripping through ram-type BOPs requires at least three preventer ram cavities fitted with the proper size rams forthe pipe to be stripped If the pipe string is a tapered string, i.e., having more than one size pipe in the string, twopreventer ram cavities will be required for each size of pipe in the string A tapered pipe string can be strippedusing only two preventer ram cavities provided variable (multiple) bore rams are used Variable bore rams have aspecified pipe size range and will seal off on any size pipe within the size range The two preventer ram cavitiesused for stripping should be spaced sufficiently far apart so that closed rams in each preventer cavity will clear thelength of a pipe connecting joint This also includes any upset (increased pipe diameter) portions adjacent to theconnection The distance between the two preventer ram cavities should provide enough additional space so thatpositioning 'the pipe joint between the cavities does not require an excessive amount of precise positioning

When operations indicate that a considerable amount of stripping may be required, it is advisable to include a thirdpreventer ram cavity fitted with pipe rams for added safety and to permit replacement of the ram packers in thestripping preventers The pipe rams in the upper two preventer cavities would be considered the "stripping" ramswhile the pipe rams in the third preventer cavity would be "safety" rams Stripping pipe through ram packerscauses wear on the packers and packer replacement is sometimes required The safety rams in the third preventercavity will permit well pressure to be shut in below the stripping preventers when required The preventer withsafety rams is only closed on a stationary pipe string and therefore the rams do not receive much wear, thusalways providing a reliable backup closure

Stripping requires no special equipment beyond what is normally available on a drilling rig; however, as the pipestring becomes insufficient to overcome the upward force of the well pressure acting on the pipe, provisions must

be made for restraining the pipe string against upward movement At this point, the stripping operation becomes a

"snubbing" operation Capability for pipe snubbing is also required when starting a pipe down into the wellboreagainst well pressure

D Ram Locking Device

A ram locking device is necessary to be fitted to all ram blowout preventers This device is used whenever it isnecessary to remove hydraulic operating pressure from the "close" side of the ram operating system, but maintainthe ram preventer in the close position On BOP stacks that are used in a surface application, the ram lockingdevice is a threaded rod, referred to as a "lock screw" This lock screw reacts between the operating piston in theram operating system, and the housing of the lock screw The locking device on a ram preventer that is used in asubsea application must be designed to be remotely actuated by either the BOP hydraulic control unit, or by theactual movement of the operating piston in the ram operating system

E Operation And Use Of Shearing Blind Rams

Under normal operating conditions, shearing blind rams are used as blind rams The large front packer in the uppershear ram seals against the front face of the lower shear ram, resulting in prolonged packer life similar to that ofstandard blind packers

If emergency conditions make it necessary to shear the drill pipe, the closing shearing blind rams will shear thepipe and seal the wellbore whether the fish (the lower section of sheared pipe) is suspended on the lower piperams or dropped If the fish is not dropped, the lower shear ram will bend the sheared pipe over a shoulder andaway from the front face of the lower shear ram which then seals against the packer in the upper shear ram

If different grades, weights, or large diameter pipe has to sheared, each oil tool manufacturer has a variety ofshear rams available to perform the shearing operation

For control of any well, blowout preventer stacks and associated kill/choke lines and valving must be arranged toprovide a high degree of backup and flexibility.

API RP53 illustrates typical arrangements for BOP (Figure K1-1C) and choke/kill manifolds

Figure K1-1C BOPs for 10M and 15M WP, Surface Installations

Notes on Figure K1-1C:

ARRANGEMENT RSRRA * Double Ram Type Preventers, Rd, Optional

ARRANGEMENT SRRRA * Double Ram Type Preventers, Rd, Optional

ARRANGEMENT RSRRA *G* Double Ram Type Preventers, Rd, Optional

*Annular preventer, A, and rotating head, G, can be of a lower pressure rating

However, this API RP deals with the subject only in a general way The rest of this section will be devoted toanalyzing several specific BOP stack arrangements Before doing this, first consider certain general facts con-cerning BOP design and arrangements

B BOP Design Considerations For Surface Stack

The principle BOP design considerations are to:

1 Confine Well Bore Pressure; and

2 Provide for Passage of Tools

Controlling bottom hole pressure while killing a well is the primary purpose of a BOP In most cases, the BOPworking pressure exceeds the limit of all other well control system elements A BOP stack should be able tocontain the maximum anticipated surface pressure which is essentially the full bottom hole formation pore pres-sure

Obviously, the BOP bore must be large enough for passage of anticipated tool sizes On occasion, under reamersmust be used to open the hole because of BOP bore restrictions Pilot holes are sometimes drilled to investigateformation pressure and the BOP is removed to open the hole and run casing This practice could be disastrous.The BOP bore should be sufficient to provide protection during any drilling process

C Bop Arrangement Considerations

Specific BOP arrangements are based on the following considerations:

1 Governmental Regulations;

2 Company Policy;

3 Physical size and cost; and

4 Flexibility and safety

1 Governmental Regulations or Company Policy

Rules and regulations governing the operation of a BOP in the USA outer continental shelf areas are contained inthe Mineral Management Service (MMS) 30 code of Federal Regulations Part 250 These rules and regulationsmust be complied with Likewise in other areas of the world, governments will usually have local regulationsgoverning the use and testing of BOP stacks

2 Company Policy

Both the Operator and the Contractor will usually have their own policies concerning BOP stack configuration andtesting The operator should be made aware of the Contractors "policies" prior to the "occurrence" of any kick

3 Physical Size and Cost

If physical size and cost is no consideration, the ideal situation would be to have only one BOP stack of sufficientbore, working pressure and back-up components to drill the complete well Such stacks are actually being built fordeepwater subsea operations where such designs can be justified Most non-floating rig BOPs are surface

mounted Two independent stack arrangements are normally used A large bore relatively low-pressure stackconsisting of an annular only, or an annular plus one or two rams, is used for well control until surface casing is set.This large bore stack sometimes is used as part of a diverter system After setting surface casing, a small borestack of higher working pressure is normally used to TD

4 Flexibility and Safety

The rest of this section will analyze two BOP stack arrangements used for maintaining control below surfacecasing on non-floating type rigs

Both arrangements consist of a singular annular and three (3) rams The advantages and disadvantages of thesearrangements in terms of flexibility and safety will be discussed

Also, included are recommendations for developing a safe, efficient BOP test procedure and the description of aspecific test sequence for one of the subject stack arrangements.

There can be no "best" standard stack arrangements since each drilling environment and rig influences, to somedegree, BOP equipment configuration But a closer look at several good hookups highlights principles that will behelpful to anyone responsible for arranging or inspecting BOP stacks

D Bop Arrangements Surface Stacks

The following discussion is an excerpt from a paper by John A Altermann, III Used with permission

<Reference> "Practical Considerations for Arranging, Testing BOP Stacks," World Oil, May 1980

The drilling business is often a series of compromises, both in equipment and practices This is certainly true withBOP stack arrangements

1 Location of the Blind Ram

Consider placement of blind rams in a 3-ram surface BOP stack If blind (or shear) rams are placed at the bottom

of the stack, with no flowlines below, then the BOP stack has the advantage of a "master valve" for open holesituations, or a last resort valve if all else fails during a kick But this placement also imposes limitations on stackuse

For example, drill pipe cannot be hung off on pipe rams below the blind ram and the well killed by circulatingthrough the drill stem This arrangement may also force placement of pipe rams so close together that adequatespace is not available for ram-to-ram stripping

On the other hand, if blind rams are placed at the top of the ram BOP stack, they can be replaced with pipe ramsfor ram-to-ram stripping operations to either protect the lower pipe ram or in the event of a tapered string, tofurnish the pipe ram size that will fit the size of drill pipe being stripped But this arrangement also presents aproblem because it prevents the utilization of the blind ram as a master valve in open hole situations, for repair ofitems above it, or changing to casing rams It also may force spacing of pipe rams so close that the ram-to-ramstripping is impossible

The question arises as to how to best maximize advantages of both of these placements and minimize tages The two compromise arrangements illustrated in this section (Figures K1-2C and K1-3C) place blind rams

disadvan-on top for tapered string drilling and in the middle when disadvan-one size drill pipe is being used

This allows hanging off pipe in the pipe rams and circulation through the drill stem when kill and choke lines areplaced properly; adequate clearance for ram-to-ram stripping; and partial utilization of the blind ram as a mastervalve for equipment out of hole repairs (top ram change to casing size obviously being safer with the blind ram inthe middle)

Notes 2b and 3a for Figure K1-3C

(arrangement for tapered strings) indicates that space between the blind rams and small pipe rams limits certainactivities

For tapered string application, this space problem could be eased by stacking the single ram unit on top of thedouble ram unit

Figure K1-3C shows the double on top, another compromise In field use it is not practical to rearrange the BOPstack just before picking up a smaller drill pipe string

2 Arrangement of a Double and a Single Ram Unit

A standard size 13-5/8 inch, 5,000 psi flanged double ram should be mounted on top of a single ram unit Thisprovides sufficient space for shearing above a standard 5 inch API NC50 connection hung in the bottom pipe ram

as illustrated in Figure K1-4C

Figure K1-5C

Figure K1-6C

Figure K1-7C

Activities Possible

1 Normal kill down drill pipe using either pipe ram

a Choke flowlines 2 and 4 below each pipe ram

2 Kill with blind or shear ram closed

a Double ram unit must be on top of single ram to provide sufficient space for hang off and shear

b Kill flowline 1 and choke flowline 4 must be arranged as shown

3 Ram to ram stripping

a Blind ram must be in middle to provide sufficient space

b Kill flowline 1 to equalize pressure before opening bottom ram

c Choke flowlines 2 and 4 to bleed fluid and monitor pressures below each ram during stripping

d Kill flowline 3 to lubricate in fluid (volumetric method when bleeding gas) or kill below bottom ram

e Could also strip between annular and either ram and do items 2, 3, or 4 above

4 Location of blind ram in the middle

a More room for ram to ram stripping as previously mentioned

b Safe "out of hole" top ram change, annular element change or repairs to the single ram unit or annular.NOTE: Location of primary choke flowline 2 at alternate location 2a will allow all previously mentioned activitiesbut is somewhat more exposed to mechanical damage