BOP Equipments Use and Testing

8/4/2019 BOP Equipments Use and Testing

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Circular 17 Page 1 of 17

GEOLOGICAL SURVEY DIVISION

Circular 17BLOWOUT PREVENTION

Equipment, Use and Testing

byDaniel T. Bertalan

Lansing, Michigan 1979

Contents

INTRODUCTION............................................................... 1BLOWOUTS ..................................................................... 1BLOWOUT PREVENTERS - FUNCTION ........................ 3RAM PREVENTERS......................................................... 3ANNULAR PREVENTERS............................................... 5BLOWOUT PREVENTER STACK ARRANGEMENTS ... 7TESTING........................................................................... 8GENERAL INFORMATION ON TESTING..................... 11CLOSING UNITS ............................................................ 11SPECIAL EQUIPMENT .................................................. 11IN PARTING.................................................................... 13SPECIAL ORDER NO. 2-73, AMENDED....................... 13GLOSSARY .................................................................... 15Figures

Figure 1. Shaffer dual body ram preventer - cutaway view, top

ram closed. (Courtesy of NL Shaffer) ..............................3Figure 2. Cutaway view of shear ram cutting drill pipe.

(Courtesy of NL Shaffer)...................................................4Figure 3. Partial cutaway view, pipe ram in closed position.

(Courtesy of NL Shaffer)...................................................4Figure 4. Pipe ram blocks, white portion is rubber sealing

element. (Courtesy of NL Shaffer)...................................4Figure 5. Cutaway view of locking shaft on ram preventer

(note arrow). (Courtesy of NL Shaffer) ............................5Figure 6. Cutaway view of Hydril annular preventers.

(Courtesy of NL Shaffer)...................................................5Figure 7. Cutaway view of annular element closing movement(Hydril). (Courtesy of NL Shaffer) ....................................5Figure 8. Partial cutaway of Shaffer spherical annular

preventer. (Courtesy of NL Shaffer).................................6Figure 9. Cutaway view of Shaffer spherical closed on drill

pipe. (Courtesy of NL Shaffer).........................................6Figure 10. Partial cutaway of Shaffer annular preventer

sealing element, white portion is steel skeleton.(Courtesy of NL Shaffer)...................................................6

Figure 11. Common BOP stack arrangement for Michigan

operations, (Courtesy of NL Shaffer)................................7

Figure 12. Time/pressure chart of BOP system test. (Courtesyof Double Check) .............................................................9

Figure 13. Pressure test of blind rams and outer valves onspool. (Courtesy of NL Shaffer).......................................9

Figure 14. Pressure test of blind rams and inner valves onspool. (Courtesy of NL Shaffer).....................................10

Figure 15. Test plug set on drill pipe and pipe rams closed.(Courtesy of NL Shaffer) ................................................10

Figure 16. Pressure test of annular preventer closed on drillpipe. (Courtesy NL Shaffer)...........................................10

Figure 17. Example of BOP Test Report. (Courtesy of DoubleCheck)............................................................................11

Figure 18. Trip Tank Work Sheet. .........................................12

Figure 19. Tables for use with Trip Tank Work Sheet. ..........12

Figure 20. 24-hour chart from Pit Volume Totalizer...............13

Figure 21. 24-hour chart from Flow Sensor...........................13

INTRODUCTION

This circular has been prepared as a basic guide for theinstallation, testing and use of blowout preventionequipment in Michigan. 'Kick detection, causes ofblowouts, and the use of special monitoring equipmentare also discussed.

Contents of this circular have been designed tofamiliarize the field geologist with the blowout preventersystems, with particular emphasis on the methods ofinstallation, inspection, and testing.

BLOWOUTS

DEFINITION

A well blowout is the uncontrolled flow of oil, gas, saltwater, or any combination of these three substancesfrom a wellbore. This uncontrolled flow can occur at thesurface from the wellbore or, if the well is shut in, canfracture underground formations, causing a subsurfaceblowout. Whether it is a dramatic well fire roaringthrough the twisted steel of a half-melted rig or gascratering the ground miles from the well, a blowout is agreat waste of resources. Human life, surface values,ground and surface waters, drilling rigs and equipment,

and nonrenewable hydrocarbons are all threatenedwhen a well indicates the possibility of a blowout.

CAUSES

Oil, gas, and salt water exist in sedimentary rocksthrough the process of deposition. Several geologicprocesses cause these substances to exist underpressure in porous and permeable formations. Thispressure varies with depth and location but usuallyincreases in increments that average 0.465 pounds per


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square inch (psi) for each foot of depth. Although 0.465psi/ft depth is the average formation pressure gradient,many geographical areas have substantially higherpressure gradients. Any substance that is capable offlowing will move from a higher-pressure to a lower-pressure environment whenever possible. With this inmind it is easy to understand how a blowout can occurwhen the pressure in the penetrated permeableformation is greater than the hydrostatic pressure of thewellbore. There are five major causes of blowouts in

which wellbore pressures are allowed to become lessthan formation pressures. These five causes are: 1) notkeeping the hole full; 2) swabbing; 3) insufficient mudweight; 4) lost circulation; and 5) abnormal formationpressure. Of these five causes, two account for a majorportion of all kicks. They are: 1) not keeping the holefull, and 2) swabbing. Swabbing and not keeping thehole full happen during trips, making this a potentiallyhazardous part of operations especially after penetratingpay sections. A kick is a bubble of gas (or slug ofoil/gas/salt water) that enters the wellbore. As thisbubble rises or is circulated upward in the wellbore, itexpands at an increasing rate, eventually blowing a slugof fluid from the hole. A kick which blows fluid from thehole is usually the LAST indicator that a blowout isimminent.

It is interesting to note that although abnormal formationpressure is mentioned as one of the major causes ofwell-control problems, most blowouts occur when normalformation pressures are involved. Abnormally highformation pressures are usually recognized in advanceand extra care and special equipment are used whendrilling. Many hydrocarbon-bearing formations inMichigan exhibit abnormally high formation pressures.Niagaran reefs have an average formation pressure of0.540 to 0.580 psi/ft of depth, and the A-1 Carbonate

has been found to have 1.0 psi/ft depth in some areas.As mentioned earlier, most kicks occur when the drillpipe is being tripped from the hole. There are severalreasons why tripping is an extremely delicate operationwhen done in high pressure formations or pay sections.These will be discussed in greater detail under SPECIALEQUIPMENT-TRIP TANKS.

INDICATIONS

Blowouts do not usually happen instantly or withoutwarning. Often, one or more circumstances indicate thata problem is developing long before the first kick is seen

at the surface. Briefly, these indications and their relatedcauses are discussed in the following paragraphs.

PIT GAIN. A gain in the fluid level of the circulating pitsduring drilling operations may mean an invasion offormation fluid or gas into the wellbore and circulatingsystem. The invading gas or fluid, by displacement,reduces the volume of hole that can be occupied bydrilling mud; this shows up directly as an increasedvolume of mud in the pit. During tripping operations,formation fluid invasion is not measured by a gain in the

pit but by the unequal amount of fluid needed for hole fill-up during drill pipe withdrawal. Put more simply, thevolume of fluid needed to keep the hole full should equalthe volume of drill pipe pulled out. If fill-up fluid volumeis less than the volume of withdrawn pipe, the chancesare that formation fluid or gas has entered the wellbore.Special equipment such as pit volume totalizers, flowsensors, and trip tanks are designed to detect thesepotential problems and will be discussed underSPECIAL EQUIPMENT.

WATER CUT MUD. Water cut mud during drillingoperations is an indication that formation water mayhave entered the wellbore (providing some weevil isn'tfooling around with watering the mud system).Formation water entering the wellbore may lighten thedrilling fluid, thus reducing the hydrostatic pressure andallowing more formation fluid to invade the hole at anincreasing rate.

DRILLING BREAK. When porosity and/or formationpressure greater than the hydrostatic pressure of thewellbore are encountered, a noticeable increase inpenetration rate will usually show up on the geolograph.

This increase in penetration rate is called a "drillingbreak. Penetration rate through porous zones will oftenincrease as formation pressure causes a reduction of thehydrostatic overbalance, allowing cuttings and liberatedformation gas or fluids to surge upward away from thebit. A drilling break may be an advance warning of apotential kick, thus providing time to implementprecautionary action.

DECREASE IN CIRCULATING PRESSURE.Invading formation fluid and/or gas will lighten the weightof the mud being circulated back up the hole, resulting ina decrease in circulating pressure. Decreasedcirculating pressure is another indicator that a kick may

be expected. Although other conditions such as partiallost circulation zones or a hole in the drill pipe can causea reduction in circulating pressure, any pressuredecrease should be monitored and accounted for.

GAS-CUT MUD. Gas-cut mud indicates that formationpressure is greater than hydrostatic pressure. Formationgas entering the wellbore expands as it rises uphole,lightening the mud column. This reduction in mudweight allows more gas to enter the hole, often at anincreasing rate. Gas-cut mud can show up as frog eyesin the pits, foaming mud, or simply a minor loss of mudweight. Gas-cut mud can be a late indicator that a kickis pending, or it can represent gas liberated with thecuttings during drilling, which by itself presents littleproblem. Like any of the other kick indicators, gas-cutmud must be carefully watched and defensive actionshould be taken.

If any of the above-mentioned kick indicators show upduring drilling, the operator should be prepared tomonitor and assess the situation accurately, and beginany necessary corrective action to bring the well undercontrol. No one particular indicator can be used todetermine definitely that a kick is occurring. Generally, a


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combination of indicators is used to detect potential wellcontrol problems. The significance of these indicatorswill vary depending upon local conditions.

General practice for drilling operations where kickindicators are experienced is to:

1. Pull off bottom- This should be done so the piperams can be closed on the drill pipe if necessary.Pulling off bottom also provides an opportunity toinstall additional equipment (stabbing or control

valves) on the drill string and allows for movement ofthe drill pipe if necessary.

2. Shut down the pump- Circulation must bestopped in order to monitor the well accurately understatic conditions.

3. Check for flow- A visual check for flow in theannulus will reveal if formation fluid and/or gas iscontinuing to invade the wellbore or if a kick isbeginning to unload the hole.

4. If no flow, circulate bottoms up- Even if the welldoes not flow from the annulus after shutting downthe pumps, a serious problem may be 'waiting

downhole in the annulus. It is safe practice tocirculate bottoms up if any of the kick indicators showup. This will allow the operator to check for invadingfluids or a gas bubble in the well.

5. Shut in the well and check for pressures- A flowof fluids from the annulus after shutting down thepumps indicates real trouble. If this is the case, theblowout preventers should be shut in and pressurereadings taken on the drill pipe and casing.

This general practice must be tempered with judgmentand flexibility to adapt to changing situations. At thispoint there are 101 things that can and should be done

to resolve the well control problem. This text cannot andwill not attempt to explain well control or kill proceduresas too many variables and combinations of problemsmay exist in a well.

Although many things should be done, one thing whichis often done should be avoided. After receiving a kickand shutting in the blowout preventers, many operatorssettle back to study the problem, thinking they haveeternity to come up with lacking needed equipment or aplan of action. A well should not be shut in any longerthan is necessary to begin kill operations. When a wellis shut in after receiving a gas kick, the gas will rise inthe wellbore. Without being able to expand, the rising

gas maintains the bottom hole pressure it had whenentering the wellbore. If given enough time this gasbubble can rise all the way uphole, exerting extreme orexcessive pressure on the BOPS, casing, and exposedformations. If this happens, a number of things can, andoften do, go wrong. Well control techniques can beimplemented whereby the well can be kept shut in andthe pressure caused by the rising gas bled off. Time isof the essence when initiating kill operations.

BLOWOUT PREVENTERS -FUNCTION

Up to this point we have discussed what a blowout is,how it can occur, and what some of its indicators are.Lastly, we outlined a general practice to be followedwhen a well indicates it is taking a kick. Closing of theblowout preventers is a must in most serious well controlsituations, and when closed, the BOP's must containanticipated wellbore pressures.

Blowout preventers are devices installed on the wellhead which can close and maintain an effective seal ondrill pipe, line, kelly, or open hole when the drill string isout of the hole. For practical purposes we will limit ourtext to modern preventers, specifically annularpreventers and ram-type preventers. Explanation ofpreventer operation and function is based on theassumption that the preventer is in proper workingcondition.

RAM PREVENTERS

Ram preventers are blowout preventers that obtain shut-off by sealing assemblies, generally called rams, movinghorizontally inward across the wellbore from two sides.Ram preventers commonly used in Michigan arehydraulically operated and also have manual operatingcontrols. There are two common types of ramassemblies used in ram blowout preventers: pipe ramsand blind rams (Figure 1). Another type is theblind/shear ram. This ram performs the same functionas a blind ram but it can cut the drillpipe and effect aseal across the wellbore if required. Shear rams aremost commonly used in offshore drilling operations. In anumber of cases, blowouts through drillpipe have been

shut in with the use of shear rams.

Figure 1. Shaffer dual body ram preventer - cutaway view, topram closed. (Courtesy of NL Shaffer)

BLIND RAMS

Blind rams are designed to close when drill pipe is out ofthe hole. When activated by hydraulic pressure, twopistons move horizontally toward each other across thewellbore forcing the two ram blocks together. These ramblocks each contain a rubber sealing element on the



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shaft incorporated in the hydraulic closing cylinder. Thisshaft can be used to lock the rams in a closed position orto manually screw the rams closed without the aid ofhydraulic pressure. These shafts are an important partof the ram preventers and should be regarded as such.When ram preventers are installed and tested, thelocking shafts should also have proper connections toallow testing. Universal joints attached to the shaftshould be rigged up with extensions and large handwheels to allow manual closing of the rams. Without

proper extensions and closing wheels, there is no waythe rams could be closed quickly or locked in anemergency situation, such as closing unit or line failurewhen the well is kicking. True, this emergency situationshould never happen; but it is the exception that usuallyresults in a serious problem.

Figure 5. Cutaway view of locking shaft on ram preventer(note arrow). (Courtesy of NL Shaffer)

ANNULAR PREVENTERS

Annular blowout preventers are the most versatile typeof preventer in that they can seal and even strip on pipeof any size or shape which may be in the hole. Anannular preventer can be shut in and seal on variousshaped kellys, different size drill pipe, collars, casing, oreven seal without pipe in the hole. Many peoplecommonly refer to the annular preventer as the "Hydril",as this company had a virtual monopoly on the annularBOP market from the mid 40's to the 70fs. AlthoughHydril is understood to mean annular preventer, theproper term "annular preventer will be used in this text,

as preventers made by other companies will bediscussed.

HYDRIL

Hydril annular preventers are closed by hydraulicpressure pushing upward a large single piston whichencircles the wellbore. The top of this piston is beveledinward; and in the bevelled top rests the doughnut-likesealing element which surrounds the open wellbore(Figure 6). When hydraulic pressure pushes the beveled

piston upward, the rubber element is stopped by thepreventer top and is forced inward in all directions,effecting a seal on whatever may (or may not) be in thehole (Figure 7). Excessive pressure, or pressure greaterthan necessary to effect a seal, may cause undue stressand fatigue on the rubber sealing element. It isrecommended that closing pressure be regulated toaccomodate pipe sizes and wellbore pressures toincrease element life. Wellbore pressures containedunder the element force it further upward, giving a tighter

seal than necessary which, if excessive, may reduceelement life. When the piston moves down, the elementopens because of the natural, stored energy in therubber sealing element.

Figure 6. Cutaway view of Hydril annular preventers.(Courtesy of NL Shaffer)

Figure 7. Cutaway view of annular element closing movement(Hydril). (Courtesy of NL Shaffer)

SHAFFER

Shaffer spherical annular preventers also seal by a largehydraulic piston pushing upward on the circular sealingelement (Figure 8). Unlike the Hydril, the Shafferpreventer piston pushes the element upward into aspherical-shaped head. The spherical contour of thepreventer top causes the rubber element to be forcedinward in all directions as it is pushed upward (Figure 9).



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To open the preventer the piston is hydraulically pusheddown and stored energy in the rubber element causes itto expand back to its original shape. Full closingpressure can be used on this preventer without affectingthe normal element life.

Annular preventers do not have mechanical closing orlocking devices. The only way to close this type ofpreventer is by hydraulic pressure under the piston. Thepreventer can be locked in the closed position by sealingin the hydraulic closing fluid under pressure, using a

valve on the closing fluid line. Canadian requirementscall for a valve on the closing line which can be used tolock the annular preventer in the closed position ifnecessary.

Figure 8. Partial cutaway of Shaffer spherical annularpreventer. (Courtesy of NL Shaffer)

SEALING ELEMENTS

Failure of blowout preventers to hold an effective sealcan usually be attributed directly or indirectly to therubber sealing element. The most commonly usedmaterial in blowout preventer sealing elements isNITRILE. This special rubber is resistant to deteriorationfrom hydrocarbons and is almost as resilient as naturalrubber. Natural rubber elements are most resilient buthave the disadvantage of being susceptible todeterioration from hydrocarbons. All types of preventersealing elements are susceptible to hardening fromhydrogen sulfide (H2S). The sulfur in H2S 'cures therubber in a sealing element, making it harder. If anelement has been cured by H2S, it will be less resilientand may develop cracks on the sealing surface. Suchhardening will greatly reduce the effective life of thesealing element.

Another factor that affects the life of a sealing element isrepeated testing. Ram preventer elements can obtain aseal without excessive deformation of the rubberbecause of the small amount of element exposed. Thisallows for extensive pressure testing to rated preventerworking pressure without damage to the sealingelement. Annular preventer elements on the other handdo not enjoy such testing freedom. Shaped steel

segments make up the 'skeleton of the doughnut-likeannular preventer element (Figure 10). Incorporatedinside the rubber, these segments help maintain theelements shape and keep the rubber from beingextruded during high pressure use. Although the steelskeleton keeps the element from being squeezed out ofthe preventer during use, the rubber portion mustundergo great deformation to obtain a seal. Elementdeformation can be moderate when closed on drillcollars, or it can be extreme when closed without pipe in

the hole. Extreme deformation of the element combinedwith high testing pressures can greatly reduce theeffective life of the annular element in certain types ofcommonly used preventers. Manufacturers of somebrand name annular preventers recommend use andtesting to rated working pressures.

Figure 9. Cutaway view of Shaffer spherical closed on drillpipe. (Courtesy of NL Shaffer)

Figure 10. Partial cutaway of Shaffer annular preventersealing element, white portion is steel skeleton. (Courtesy ofNL Shaffer)

Testing of blowout preventers should be done to insuretheir reliability, but without damaging the preventerelement. To insure testing without element damage, it isrecommended that annular preventers be tested to only50% of their rated working pressure, and never pressure



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placement on the bottom of the stack arrangement asensible alternative. If a well control problem developsthat cannot be handled by the existing stack, mostannular preventers are made to accept additional BOPstacking on the top. This can be extremely important inspecial high-pressure stripping operations or where H2Sgas is involved.

TESTING

Installation of blowout prevention equipment is only thefirst major step in achieving a workable pressure-controlsystem. The second step is making sure the equipmentwill work. After blowout preventers are installed theymust be pressure tested to insure complete performancein a well control situation. Without prescribed, periodicpressure testing, one can only assume that the systemwill function properly. Assumptions are dangerousthings on which to risk life and resources. The functionin many phases of a regulatory field geologist's work isto 'assume nothing', and this should be emphasizedwhere blowout prevention is involved.

Act 61, P. A. 1939, as amended, specifically requirestesting of blowout prevention equipment. Rule 302,section e) states:

Blowout prevention equipment shall be tested to apressure commensurate with the objective formationbefore drilling the plug on the surface pipe, beforeencountering the objective formation, and at otherintervals in accordance with good oil field practice. Arecord of each pressure test and each mechanicaltest of the casings, blowout preventers, surfaceconnections and fittings, and auxiliary well headequipment shall be entered in the log book, signed bythe driller, and kept available for inspection by the

supervisor or his authorized representative.

. . . pressure commensurate with the objective formation. . . simply means equal to the known or anticipatedformation pressure. Note that this rule calls for testingblowout prevention equipment "before drilling the plugon the surface pipe, before encountering the objectiveformation, and at other intervals. . .. There is a dualadvantage in having the blowout preventers tested justprior to drilling the objective formation. First, it enablesthe crew that will likely be drilling the pay section tobecome more aware and confident of the preventersystem and its operation. Secondly, this test usuallyfinds leaks or problems that have developed since the

first pressure test several days or weeks previously.Some of the problems that can develop betweenpreventer tests are such things as: 1) flanges or sealsdeveloping leaks from vibration; 2) salt, mud, and/orcuttings accumulating on preventer seals; or 3) systemalterations.

Additional blowout preventer testing procedures arerequired for wells drilled below the base of the DetroitRiver Group. These requirements, set forth in SPECIALORDER No. 2-73, AMENDED, (Pages 32-34) most

commonly involve wells drilled to the Niagaran formationin the northern and southern reef trends. SPECIALORDER 2-73, AMENDED, defines casing, cementing,blowout preventer equipment, and testing requirements.This order requires three complete pressure tests of theblowout prevention equipment: 1) before drilling the plugon surface casing; 2) before drilling the plug onintermediate casing; and 3) prior to drilling potentialproducing zones. A record of each test and notation inthe log book of any failures and/or repairs is also

required. The following discussion will deal withstandard procedures for testing in accordance withSPECIAL ORDER 2-73, AMENDED.

Before blowout prevention equipment can be installed, asuitable string of surface casing must be set andcemented. SPECIAL ORDER 2-73, AMENDED,requires surface casing to be set at least 100f below allfresh water aquifers and cemented to the surface. Insome areas this is deeper than 100 below the glacialdrift, as fresh water aquifers are found in some bedrockformations. A blowout preventer stack comprised of anannular preventer over two ram preventers is theninstalled on the surface casing. Before drilling the

surface casing plug, the blowout preventers and surfacecasing are pressure tested in accordance with good oilfield practice. Testing is usually accomplished by usingthe rig mud pumps. Blind rams are first tested by closingthem on the open hole and pressuring up from the killline. This provides a pressure test upward against theclosed rams and pressure tests the surface casing.After testing the blind rams, drill pipe (with bit & collars)is run in the hole to the cement plug depth. The piperams and annular preventer are individually tested byclosing them on the drill pipe and pressuring up throughthe kill line or drill string. Pressures involved for testingthe surface casing and preventers are between 1000

and 1500 psi.The second test of the blowout preventers is donebefore drilling the plug on the intermediate casing.Unless an exception has been granted prior to permitissuance, intermediate casing is set below all porous orlost circulation zones between the AmherstburgFormation and within the top 50 feet of the Salina A-2Carbonate. Intermediate casing is cemented with aminimum of 500 feet fill-up above the casing shoe, andthis must be confirmed by a verified temperature survey.Prior to drilling the cement plug, the blowout preventers,kill line, choke line and assembly, and intermediatecasing are each tested to 1500 psi for at least 20

minutes. This testing can be done with the rig pumps, aservice company pump truck, or by a blowout preventertesting company. Procedure for testing blowoutpreventers at this point is basically the same as thatused in the first test on the surface casing.

The final pressure test required by SPECIAL ORDER 2-73, AMENDED, is prior to drilling potential producingzones. "Prior to" is understood to be anytime afterdrilling a well into the B salt but prior to penetrating theA-1 Carbonate on Niagaran wells. After drilling to this


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point, the drill string is tripped out to allow testing.Because of today's rig time costs and special needs forcomplete blowout preventer system testing, manyoperators have found it advantageous to use theservices of specialized blowout preventer testingcompanies. This testing service will be discussed inexplaining the final test procedure prior to drillingpotential pay.

Most service company testing of blowout preventers isaccomplished by use of a truck-mounted testing unit.

The truck is equipped with a triplex pump which is usedfor pressuring up the blowout preventer system througha high pressure rubber hose to well head connections.Time/pressure recording clocks are used on the testingunit to provide an impartial and accurate recorded chartof test times and pressures. Figure 12 is an example ofa chart recording of a blowout preventer system andcasing pressure test. A water tank which holds greencolored test water used in pressuring up the preventersis also mounted on the testing unit.

Figure 12. Time/pressure chart of BOP system test. One hourchart time is actually 20 minutes. (Courtesy of Double Check)

Before any pressure testing is done, the blowoutpreventers, kill line, and choke assembly are flushed freeof drilling muds. Mud is a poor test fluid because solidand colloidal particles in the mud will aid in sealing a

leak which may not hold water or gas under pressure. Aspecial test water which aids in leak detection is used inpressuring up the blowout preventers. A greenfluorescent dye (developed by the Navy in World War II)is added to test water in the holding tank. Even slightweeping-type leaks in flange connections are easilydetected by this green-dyed water. Water also has verylow compressibility, a characteristic which makes it adesirable medium for pressure testing.

A sensible principle employed in testing blowout

preventer systems is to restrict the portion tested to thesmallest possible area of the system. Testing small orisolated parts reduces the possible places where leaksmight occur, aids in leak detection, and saves time intesting which, of course, is money.

Many operators, and all prudent operators, test theentire blowout preventer system and all relatedequipment which may be subject to well pressure. Awell control system is only as good or bad as its weakestpoint. The following paragraphs describe parts of the

system which are tested, and these are presented in thegeneral testing sequence.

KILL LINE. The entire length of the kill line from themud pump connection to the valves on the drilling spoolis tested to the rated working pressure but not less than1500 psi for 20 minutes. Pressure is applied (test waterpumped) into the auxiliary kill line which is tied to themain kill line. This auxiliary 2-valved kill line should beavailable for service company hook-up in the event themud pumps fail or cannot handle the well controloperation. Testing the kill line in this manner does notallow for a pressure test on the kill line check valve,

which must be tested later from the well-bore toward thecheck valve. The two recommended valves between thecheck valve and drilling spool are each individuallytested with 3000 psi pressure, applied from the spooltoward the valves.

STAND PIPE & KELLY COCKS. The entire systemfrom mud pump discharge to the kelly is pressure testedby pumping back up the kelly. A special fitting whichscrews onto the kelly sub allows pressure testing of thekelly cocks, swivel, drilling hose, stand pipe, and line tothe mud pumps.

Figure 13. Pressure test of blind rams and outer valves onspool. Darkened portion under pressure. (Courtesy of NLShaffer)

CHOKE LINE & MANIFOLD. The choke line andmanifold (including all valves) are pressure tested to3000 psi. This can be accomplished by pumping testwater through the choke pressure-gauge fitting on thechoke manifold without the loss of rig time. Test



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pressure can also be applied from the wellbore. Like thekill line valves, both choke line valves which are flangedto the spool should be tested (3000 psi), with pressureapplied from the wellbore toward the valves. This isaccomplished when testing the preventers (Figure 13).It must be noted when referring to Figures 12, 13, 14and 15 that the spool with kill and choke line connectionsis located between the blind and pipe rams. This type ofsystem is not commonly used in Michigan operations.

BLIND RAMS. Blind Rams are the first preventers tobe tested. This is accomplished by setting a boll weevil-type test plug down in the casing spool which will seal offthe casing and wellbore. After closing the blind rams,pressure is applied from the kill or choke line and held at3000 psi for 20 minutes (Figure 14). Caution must beexercised when testing the blind rams because a leakingtest plug could result in exertion of excessive pressureon casing and formations in the open hole section. Thisproblem can be eliminated by opening the valve on thecasing spool below the rams.

Figure 14. Pressure test of blind rams and inner valves onspool. Darkened portion under pressure. (Courtesy of NLShaffer)

PIPE RAMS. In testing the pipe rams, a test plug orcup packer is again set in the casing spool or top fewfeet of casing. This plug, or cup packer, is screwed ontoa joint of drill pipe and lowered into the casing spool.The drill pipe is securely set in the slips to preventpumping it and the test packer down the hole whenpressure is applied. After closing the pipe rams,pressure is applied from the kill or choke line and held at

3000 psi for 20 minutes (Figure 15). A leaking cuppacker on this test cannot damage casing or open holeformations as leaking fluid would simply flow out theopen ended joint of drill pipe.

ANNULAR PREVENTER. Pressure testing theannular preventer is done in a manner similar to theprocedure used for testing pipe rams. With the joint ofdrill pipe and cup packer still set, the annular preventeris closed on the drill pipe. An annular preventer shouldnever be pressure tested without pipe in the hole as thiscould result in stress which could damage the preventer

element. Test pressure applied through the kill or chokelines should be limited to 50% of the working pressure ofthe annular preventer. This is commonly 1500 psi andshould be held for 20 minutes (Figure 16).

Figure 15. Test plug set on drill pipe and pipe rams closed.(Courtesy of NL Shaffer)

Figure 16. Pressure test of annular preventer closed on drillpipe. Darkened portion under pressure. (Courtesy NL Shaffer

INTERMEDIATE CASING. Pressure testing theintermediate casing prior to drilling the potential pay isrequired by SPECIAL ORDER 2-73, AMENDED. Thistest is performed by running a hook-wall packer on drillpipe into the casing and setting it at some point betweenthe cement top (indicated by temperature survey) andcasing shoe. Most operators set the hook-wall packer100 above the casing shoe. This provides a margin for

error in counting stands of pipe. The hook-wall packer,which has slips and three sealing elements, is set byturning the drill pipe and exerting drill pipe weight.Setting the packer seals off the open hole below fromthe casing/drill pipe annulus. Pipe rams are closed onthe drill pipe and the casing is pressure tested bypumping into the kill or choke line. Surface test pressureis usually held between 1000 and 1500 psi for 20minutes, depending on mud weight and casing quality.Caution must be used in selecting a test pressure as it ispossible to damage (split) casing by testing with



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excessive surface pressure. After all pressure testing iscompleted a copy of the test results or entry in the logbook must be available for inspection at the rig. Figure17 is an example of a blowout preventer test reportprovided to the operator by the testing service company.

Figure 17. Example of BOP Test Report. (Courtesy of DoubleCheck)

GENERAL INFORMATION ONTESTING

We have discussed blowout preventer testing withoutventuring into the realms of possible failures, problems,and testing variables. These lessons are learnedthrough practical experience and increased knowledgeof blowout prevention. It may be helpful to note that onmost preventer or system tests, a pressure loss of a fewhundred psi occurs within the first five minutes (refer to

Figure 12). This pressure loss is due to compression ofthe sealing elements and valve packing. However, ifminor pressure fall-off continues, a leak should besuspected. A pressure loss during a test is criticalproportionately to the volume of space being tested. Forexample, a kelly cock test which loses 50 psi every fiveminutes would probably have a leak so small it would beundetectable. But a 50 psi loss in five minutes on anintermediate casing test should merit consideration offactors involved, such as length and size of casing string

or whether testing with a packer or against a cementplug. Most common leaks found during blowoutpreventer testing are small in nature and occur aroundflanges, connections, preventer seals, and packings.

There are two types of pressure tests not currently usedin Michigan which merit mention.

A formation integrity test is required by the USGS onmany off-shore drilling operations. This test is designedto find the integrity limit of exposed formations below thecasing shoe so that maximum allowable mud weightscan be calculated. The test is performed by drillingbelow the casing shoe and pressuring up on theexposed formation until it begins to take fluid. Thismeasured formation leak-off pressure is used todetermine maximum mud weights that can be usedwithout risk of formation breakdown.

Although not required in Michigan, low pressure blowoutpreventer testing warrants mention. Low pressuretesting of preventers will often reveal leaks that hold aseal at high pressure. As previously discussed, ramsand annular preventers seal more effectively at highertest pressures, since wellbore pressures assist inobtaining a seal. In most well control situations it iscommon to have relatively low (200 to 500 psi) initialshut-in pressures. With this in mind it is reasonable to

expect that blowout preventers should be capable ofholding lower wellbore pressures.

CLOSING UNITS

The most complete blowout preventer system everdesigned would be of little value if the closing unit did notfunction when it was needed. Our current Stateregulations do not require any specific closing unit testsother than the obvious ability to close the preventersunder test conditions. Although we have norequirements concerning closing units, we recommendreferring to Section 5-A in API RP 53, API

RECOMMENDED PRACTICES FOR BLOWOUTPREVENTION EQUIPMENT SYSTEMS.

SPECIAL EQUIPMENT

Blowout prevention begins with maintaining primarycontrol of a well through hydrostatic overbalance. Ifproper mud weight and hydrostatic column height aremaintained, there should be little or no need for blowoutpreventers. Primary blowout prevention is kick



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prevention and kick prevention is avoiding the mistakesthat result in kicks. As discussed in the beginningportions of this circular, there are five major causes ofblowouts, two of which are identified as maintroublemakers. These two major causes are: 1) notkeeping the hole full, and 2) swabbing. Both occurduring trips. Swabbing is a form of not keeping the holefull. Avoiding these troublemakers and preventing kicksis a much easier task than attempting to regain control ofa kicking well. Potential problems can be avoided

through careful monitoring of the operations with the aidof special equipment.

Figure 18. Trip Tank Work Sheet.

TRIP TANK

A trip tank is potentially one of the most valuable piecesof equipment in kick detection. "Potentially" is used as amodifier because if the trip tank is not used properly (ornot used at all) it does no good. A trip tank is an opentank which is marked for gauging volume (barrels) ofmud pumped from the tank during tripping operations.The value of a trip tank is that it allows exact monitoringof mud volume needed to keep the hole full related to

pipe volume withdrawn from the hole. The volume ofmud needed to fill the hole must equal the volume ofpipe pulled out. If the volume of mud needed to keepthe hole full is less than the volume of pipe pulled, it canbe expected that something else has occupied thatvolume, such as swabbed gas. Figures 18 and 19 aretrip tank work sheets and tables used for mud/pipevolume calculations.

Figure 19. Tables for use with Trip Tank Work Sheet.

Keeping the hole "full" during trips by continuously fillingor filling after every five stands of pipe are pulled withoutusing a trip tank can cause problems. These methodsallow for swabbing-in of gas, oil, or brine withoutdetection until the hole starts unloading fluid at thesurface. The word "full" must be used as it relates tomud volume and pipe volume involved in tripping.



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PIT VOLUME TOTALIZER AND FLOWSENSOR

Two other pieces of equipment which can aid in kickdetection are the pit volume totalizer (PVT), and the flowsensor. These instruments gauge and record on a timechart pit volume and flow from the wellbore.

PVT. Changes in pit volume during the drilling of a wellcan indicate possible well control or related problems. APVT with high/low alarm can detect an increase in fluid

volume in the pit caused by formation fluid or gasinvading the wellbore. These invading fluids displacemud from the wellbore which shows up proportionatelyas a mud volume increase in the drilling pit. Gradualformation fluid invasion into the wellbore which may notbe noticeable during drilling can also be detected by aPVT. This is valuable information, considering that anychange in the mud properties can affect primary wellcontrol. Gradual fluid loss into porous or weak zones isalso important information that may be detectable onlyon a PVT. Figure 20 is a PVT chart recording of pit mudvolume changes.

Figure 20. 24-hour chart from Pit Volume Totalizer showing pitvolume in barrels. (Note: 3 days continuous record of pitvolume).

FLOW SENSOR. A flow sensor is very much like aPVT, showing increases or decreases in amount of mudcoming from the wellbore. Unlike a PVT, which indicatestotal volume in barrels, a flow sensor records percent ofmud flow coming from the well. The flow sensor alsorecords on a time chart and can be installed withhigh/low alarms. Changes in flow occur normally duringdrilling operations when making connections, increasingcirculating pressure, and during other operations.Although these flow changes are normal, a suddenincrease or decrease during drilling, tripping, or

circulating can alert crews to an unpredicted change inflow which may relate to primary well control. Figure 21is a flow sensor chart recording of flow variations duringdrilling operations. The use of trip tanks, PVTs, and flowsensors is not generally required in Michigan operations,although many prudent operators use some or all ofthem. Special requirements for drilling in particularareas call for their use.

IN PARTINGIt is hoped that the material presented has provided thebasic information for a better understanding of blowoutpreventers. Further, it must be understood that all of theequipment presented not only has specific advantagesand applications, but also has certain limitations. Thekey to blowout prevention is the knowledge andunderstanding of primary well control combined with theproper use of detection and prevention equipment.

Figure 21. 24-hour chart from Flow Sensor showing percent(%) of flow. 40% flow during normal drilling, 0% when makingconnections.

STATE OF MICHIGANDEPARTMENT OF NATURAL RESOURCES

SUPERVISOR OF WELLS

SPECIAL ORDER NO. 2-73,AMENDED

CASING AND SEALING REQUIREMENTS FORWELLS DRILLED BELOW THE BASE OF THEDETROIT RIVER GROUP WITH ROTARY TOOLS

Pursuant to a public hearing held in Lansing, Michigan,



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on February 21, 1974, and review of the evidence andtestimony presented and in consideration of therecommendation of the Oil Advisory Board, theSupervisor of Wells has determined the followingprocedure and minimum casing and sealingrequirements are necessary to insure the health,welfare, and safety of the public. These requirementsare hereby issued in conjunction with and in addition tothe provisions of Rule 301, 302, and 306 of the GeneralRules promulgated June 21, 1971, under the authority of

Act No. 61, Public Acts, 1939, as amended.1) Casing shall be run from the surface to a depth noless than 100 feet into the bedrock and in allinstances shall be run at least 100 feet below all freshwater aquifers; shall be cemented to the surface bythe pump and plug method; shall be equipped withblowout preventer equipment in accordance with theprovisions of the General Rules; and pressure testedin accordance with good oil field practice.

2) An intermediate string of casing of sufficientweight and quality to withstand the maximumanticipated pressure is to be run from the surface to apoint below all porous or lost circulation zonesbetween the Amherstburg Formation of the DetroitRiver Group and a point within the top fifty (50) feet ofthe Salina A2 Carbonate or equivalent. The minimumsize hole for any given size casing is to be one andthree-quarters inches (1 3/4") larger in diameter thanthe outside diameter of the casing run. The casing isto be equipped with centralizers and scratchers inaccord with good oil field practice and be cementedwith a minimum of 150 sacks of cement of the properclass and such additives as may be necessary toprovide a positive seal in the annulus for a minimumdistance of 500 feet above the casing shoe.Additional cement shall be used if unusual drilling or

well bore conditions are encountered or upon thedirection of the Supervisor or his agent. Atemperature survey shall be run in order to determinethe top of the cement if the cement is not circulated tothe surface. Verification of the survey, signed by theservice company representative, designating thedepth at which he found the top of the cement, shallbe left at the rig and be available for inspection by theSupervisor's agent. A copy of the temperaturesurvey and copy of the cementing service ticket shallbe filed promptly at the office of the Supervisor.

3) Blowout prevention equipment shall be installed toprovide positive SINGLE shut-off protection when thedrill pipe is out of the hole; to provide positiveDOUBLE shut-off protection when drill pipe is in thehole; to provide connections separate of those of thecasinghead for choke and kill line assemblies; and toprovide protection against casing wear.

4) All outlets, fittings, and connections on the casing,blowout preventers, and auxiliary well headequipment which may be subject to well headpressure shall be of such material constructiondesigned to withstand the maximum anticipated

pressure at the well head. All lines from outlets on orbelow the blowout preventers shall be securelyanchored. All outlets below the blowout preventersshall be the flange type.

5) Before drilling the plug, the blowout preventers,surface connections and fittings, auxiliary well headequipment, and the intermediate casing is to besatisfactorily pressure tested for a period of at least20 minutes at a stabilized pressure of not less than1,500 psig. A representative of the Supervisor shall

be notified a minimum of 12 hours prior tocommencement of the test.

6) Prior to drilling potential producing zones theblowout preventers, surface connections and fittings,auxiliary well head equipment, and intermediatecasing are to be satisfactorily pressure tested for aperiod of at least 20 minutes at a pressurecommensurate to the maximum rated workingpressure. A representative of the Supervisor shall benotified a minimum of 12 hours prior tocommencement of the test.

7) Mechanical tests shall be made by each crew on

every tour to insure that the blowout preventers are inworking order and will close properly.

8) A record of each pressure test and eachmechanical test of the casings, blowout preventers,surface connections and fittings, and auxiliary wellhead equipment shall be entered in the log book andkept available for inspection by the Supervisor ofWells or his authorized representative.

9) Any failure of the casings, blowout preventers,surface connections and fittings, or auxiliary wellhead equipment during the required pressure ormechanical tests shall be corrected or repaired and

retested. The nature of the failure, its repair, andretesting shall be recorded in the log book beforedrilling is resumed.

10) The development of any hazardous conditionduring drilling operations such as lost circulation,threatened blowouts, casing or cement failure orfailure of any secondary control equipment must bereported promptly to the Supervisor of Wells.

The requirements and procedures set forth areapplicable to all wells drilled below the base of theDetroit River Group with rotary tools except wherespecial rules are adopted pursuant to public hearingsscheduled for such purpose; or in instances wheresubsequent to receipt of written supportive data andupon review and evaluation and where deemedappropriate exceptions may be granted by theSupervisor or his authorized representative; or ininstances where the Supervisor finds them inadequateor inappropriate and adopts such requirements as hemay deem appropriate and necessary; or in the eventunusual geological conditions or mechanical problemsare encountered during drilling operations.

This order amends and supersedes Special Order No. 2-


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match the drill pipe in use. This valve is used to close offthe drill pipe to prevent flow.

DRILL STRING FLOAT. A check valve in the drill stringthat will allow fluid to be pumped into the well but willprevent flow from the well through the drill pipe.

DRIVE PIPE. A relatively short string of large diameterpipe driven or forced into the ground to function as"conductor pipe" (refer to Par. 12.18).

FILL-UP LINE. A line usually connected into the bell

nipple above the blowout preventers to allow addingdrilling fluid to the hole while pulling out of the hole tocompensate for the metal volume displacement of thedrill string being pulled.

GATE VALVE. A valve which employs a sliding gate toopen or close the flow passage. The valve may or maynot be full-opening.

HYDROSTATIC HEAD. The pressure which exists atany point in the wellbore due to the weight of the columnof fluid above that point.

INSIDE BLOWOUT PREVENTER. A device that can be

installed in the drill string that acts as a check valveallowing drilling fluid to be circulated down the string butprevents back flow.

KELLY COCK. A valve immediately above the kelly thatcan be closed to confine pressures inside the drill string.

KELLY VALVE, LOWER. An essentially full-openingvalve installed immediately below the kelly, with outsidediameter equal to the tool joint outside diameter. Valvecan be closed to remove the kelly under pressure andcan be stripped in the hole for snubbing operations.

KICK. Intrusion of formation liquids or gas that results inan increase in pit volume. Without corrective measures,

this condition can result in a blowout.KILL LINE. A high pressure line between the pumps andsome point below a blowout preventer. This line allowsfluids to be pumped into the well or annulus with theblowout preventer closed.

LOST RETURNS. Loss of drilling fluids into theformation resulting in a decrease in pit volume.

MINIMUM INTERNAL YIELD PRESSURE. The lowestpressure at which permanent deformation will occur.

DRILLING FLUID WEIGHT RECORDER. An instrumentin the drilling fluid system which continuously measures

drilling fluid density.OPENING RATIO. The ratio of the well pressure to thepressure required to open the blowout preventer.

OVERBURDEN. The pressure on a formation due to theweight of the earth material above that formation. Forpractical purposes this pressure can be estimated at 1psi/ft of depth.

PACKOFF OR STRIPPER. A device with an elastomerpacking element that depends on pressure below thepacking to effect a seal in the annulus. Used primarily to

run or pull pipe under low or moderate pressures. Thisdevice is not dependable for service under highdifferential pressures.

PIPE RAMS. Rams whose ends are contoured to sealaround pipe to close the annular space. Separate ramsare necessary for each size (outside diameter) pipe inuse.

PIT VOLUME INDICATOR. A device installed in thedrilling fluid tank to register the fluid level in the tank.

PIT VOLUME TOTALIZER. A device that combines allof the individual pit volume indicators (refer to Par.12.42) and registers the total drilling fluid volume in thevarious tanks.

PLUG VALVE. A valve whose mechanism consists of aplug with a hole through it on the same axis as thedirection of fluid flow. Turning the plug 90 opens orcloses the valve. The valve may or may not be full-opening.

PRESSURE GRADIENT, NORMAL. The subsurfacepressure proportional to depth, which is roughly equal tothe hydrostatic pressure of a column of salt water (0.465

psi/ft).

RELIEF WELL. An offset well drilled to intersect thesubsurface formation to combat a blowout.

ROTATING HEAD. A rotating, pressure-sealing deviceused in drilling operations utilizing air, gas, foam, or anyother drilling fluid whose hydrostatic pressure is lessthan the formation pressure.

SALT WATER FLOW. An influx of formation salt waterinto the wellbore.

SHEAR RAMS. Refer to Par. 12.5.

SWABBING. The lowering of the hydrostatic pressure inthe hole due to upward movement of pipe and/or tools.

TARGET. A bull plug or blind flange at the end of a teeto prevent erosion at a point where change in flowdirection occurs.

TRIP GAS. An accumulation of gas which enters thehole while a trip is made.

WIRELINE PREVENTERS. Preventers installed on topof the well or drill string as a precautionary measurewhile running wirelines. The preventer packing will closearound the wireline.

Glossary is from American Petroleum Institute (API)

Recommended Practices for Blowout PreventionEquipment Systems, RP 53 first edition 1978, reprintedwith permission.


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STATE OF MICHIGANWilliam G. Milliken, Governor

DEPARTMENT OF NATURAL RESOURCESHoward A. Tanner, Director

GEOLOGICAL SURVEY DIVISIONArthur E. Slaughter, Chiefand State Geologist

NATURAL RESOURCES COMMISSIONHilary F. Snell, Chairman, Grand Rapids

Jacob A. Hoefer, East LansingCarl T. Johnson, Cadillac

E. M. Laitala, HancockHarry H. Whiteley, Rogers City(Mrs.) Joan L. Wolfe, Belmont

Charles G. Younglove, Allen ParkJohn M. Robertson, Executive Assistant

Published by authority of State of Michigan CL 70 s.321.6Printed by Reproduction Services Section, Office Services Division, Department of Management and Budget

Available from the Information Services Center, Michigan Department of Natural Resources, Box 30028, Lansing,Michigan 48909

On deposit in public libraries, state libraries, and university libraries in Michigan and other selected localities.

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BOP Equipments Use and Testing

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