familiarize the field geologist with the blowout preventer systems, with particular emphasis on the assemblies used in ram blowout preventers: pipe rams.
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Circular 17 Œ Page 1 of 17 GEOLOGICAL SURVEY DIVISION Circular 17 BLOWOUT PREVENTION Equipment, Use and Testing by Daniel T. Bertalan Lansing, Michigan 1979 Contents INTRODUCTION 1 BLOWOUTS 1 BLOWOUT PREVENTERS – FUNCTION 3 RAM PREVENTERS 3 ANNULAR PREVENTERS ..5 BLOWOUT PREVENTER STACK ARRANGEMENTS 7 TESTING8 GENERAL INFORMATION ON TESTING 11 CLOSING UNITS11 SPECIAL EQUIPMENT..11 IN PARTING ..13 SPECIAL ORDER NO. 2-73, AMENDED..13 GLOSSARY..15 Figures Figure 1. Shaffer dual body ram preventer – cutaway view, top ram closed. (Courtesy of NL Shaffer) 3 Figure 2. Cutaway view of shear ram cutting drill pipe. (Courtesy of NL Shaffer) 4 Figure 3. Partial cutaway view, pipe ram in closed position. (Courtesy of NL Shaffer) 4 Figure 4. Pipe ram blocks, white portion is rubber sealing element. (Courtesy of NL Shaffer) ..4 Figure 5. Cutaway view of locking shaft on ram preventer (note arrow). (Courtesy of NL Shaffer) .5 Figure 6. Cutaway view of Hydril annular preventers. (Courtesy of NL Shaffer) 5 Figure 7. Cutaway view of annular element closing movement (Hydril). (Courtesy of NL Shaffer)5 Figure 8. Partial cutaway of Shaffer spherical annular preventer. (Courtesy of NL Shaffer) 6 Figure 9. Cutaway view of Shaffer spherical closed on drill pipe. (Courtesy of NL Shaffer)..6 Figure 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. (Courtesy of Double Check) .9 Figure 13. Pressure test of blind rams and outer valves on spool. (Courtesy of NL Shaffer) 9 Figure 14. Pressure test of blind rams and inner valves on spool. (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 drill pipe. (Courtesy NL Shaffer).10 Figure 17. Example of BOP Test Report. (Courtesy of Double Check).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 the installation, testing and use of blowout prevention equipment in Michigan. ‘Kick™ detection, causes of blowouts, and the use of special monitoring equipment are also discussed. Contents of this circular have been designed to familiarize the field geologist with the blowout preventer systems, with particular emphasis on the methods of installation, inspection, and testing. BLOWOUTS DEFINITION A well blowout is the uncontrolled flow of oil, gas, salt water, or any combination of these three substances from a wellbore. This uncontrolled flow can occur at the surface from the wellbore or, if the well is shut in, can fracture underground formations, causing a subsurface blowout. Whether it is a dramatic well fire roaring through the twisted steel of a half-melted rig or gas cratering the ground miles from the well, a blowout is a great waste of resources. Human life, surface values, ground and surface waters, drilling rigs and equipment, and nonrenewable hydrocarbons are all threatened when a well ‚indicates™ the possibility of a blowout. CAUSES Oil, gas, and salt water exist in sedimentary rocks through the process of deposition. Several geologic processes cause these substances to exist under pressure in porous and permeable formations. This pressure varies with depth and location but usually increases in increments that average 0.465 pounds per
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Circular 17 Œ Page 2 of 17 square inch (psi) for each foot of depth. Although 0.465 psi/ft depth is the average fo rmation pressure gradient, many geographical areas have substantially higher pressure gradients. Any substance that is capable of flowing will move from a higher-pressure to a lower- pressure environment whenever possible. With this in mind it is easy to understand how a blowout can occur when the pressure in the penetrated permeable formation is greater than the hydrostatic pressure of the wellbore. There are five major causes of blowouts in which wellbore pressures are allowed to become less than formation pressures. These five causes are: 1) not keeping the hole full; 2) swabbing; 3) insufficient mud weight; 4) lost circulation; and 5) abnormal formation pressure. Of these five causes, two account for a major portion of all kicks. They are: 1) not keeping the hole full, and 2) swabbing. Swabbing and not keeping the hole full happen during trips, making this a potentially hazardous part of operations especially after penetrating pay sections. A ‚kick™ is a bubble of gas (or slug of oil/gas/salt water) that enters the wellbore. As this bubble rises or is circulated upward in the wellbore, it expands at an increasing rate, eventually blowing a slug of fluid from the hole. A kick which blows fluid from the hole is usually the LAST indicator that a blowout is imminent. It is interesting to note that although abnormal formation pressure is mentioned as one of the major causes of well-control problems, most blowouts occur when normal formation pressures are involved. Abnormally high formation pressures are usually recognized in advance and extra care and special equipment are used when drilling. Many hydrocarbon-bearing formations in Michigan exhibit abnormally high formation pressures. Niagaran reefs have an average formation pressure of 0.540 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 drill pipe is being tripped from the hole. There are several reasons why tripping is an extremely delicate operation when done in high pressure formations or pay sections. These will be discussed in greater detail under SPECIAL EQUIPMENT-TRIP TANKS. INDICATIONS Blowouts do not usually happen instantly or without warning. Often, one or more circumstances indicate that a problem is developing long before the first kick is seen at the surface. Briefly, these indications and their related causes are discussed in the following paragraphs. PIT GAIN. A gain in the fluid level of the circulating pits during drilling operations may mean an invasion of formation fluid or gas into the wellbore and circulating system. The invading gas or fluid, by displacement, reduces the volume of hole that can be occupied by drilling mud; this shows up directly as an increased volume 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, the volume of fluid needed to keep the hole full should equal the volume of drill pipe pulled out. If fill-up fluid volume is less than the volume of withdrawn pipe, the chances are that formation fluid or gas has entered the wellbore. Special equipment such as pit volume totalizers, flow sensors, and trip tanks are designed to detect these potential problems and will be discussed under SPECIAL EQUIPMENT. WATER CUT MUD . Water cut mud during drilling operations is an indication that formation water may have entered the wellbore (pro viding some ‚weevil™ isn’t fooling around with watering the mud system). Formation water entering the wellbore may lighten the drilling fluid, thus reducing the hydrostatic pressure and allowing more formation fluid to invade the hole at an increasing rate. DRILLING BREAK . When porosity and/or formation pressure greater than the hydrostatic pressure of the wellbore are encountered, a noticeable increase in penetration rate will usually show up on the geolograph. This increase in penetration rate is called a “drilling breakfl. Penetration rate through porous zones will often increase as formation pressure causes a reduction of the hydrostatic overbalance, allowing cuttings and liberated formation gas or fluids to surge upward away from the bit. A drilling break may be an advance warning of a potential kick, thus providing time to implement precautionary action. DECREASE IN CIRCULATING PRESSURE. Invading formation fluid and/or gas will lighten the weight of the mud being circulated back up the hole, resulting in a decrease in circulating pressure. Decreased circulating pressure is another indicator that a kick may be expected. Although other conditions such as partial lost circulation zones or a hole in the drill pipe can cause a reduction in circulating pressure, any pressure decrease should be monitored and accounted for. GAS-CUT MUD . Gas-cut mud indicates that formation pressure is greater than hydrostatic pressure. Formation gas entering the wellbore expands as it rises uphole, lightening the mud column. This reduction in mud weight allows more gas to enter the hole, often at an increasing rate. Gas-cut mud can show up as ‚frog eyes™ in the pits, foaming mud, or simply a minor loss of mud weight. Gas-cut mud can be a late indicator that a kick is pending, or it can represent gas liberated with the cuttings during drilling, which by itself presents little problem. Like any of the other kick indicators, gas-cut mud must be carefully watched and defensive action should be taken. If any of the above-mentioned kick indicators show up during drilling, the operator should be prepared to monitor and assess the situation accurately, and begin any necessary corrective action to bring the well under control. No one particular indicator can be used to determine definitely that a kick is occurring. Generally, a
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combination of indicators is used to detect potential well control problems. The significance of these indicators will vary depending upon local conditions. General practice for drilling operations where kick indicators are experienced is to: 1. Pull off bottom – This should be done so the pipe rams can be closed on the drill pipe if necessary. Pulling off bottom also provides an opportunity to install additional equipment (stabbing or control valves) on the drill string and allows for movement of the drill pipe if necessary. 2. Shut down the pump – Circulation must be stopped in order to monitor the well accurately under static conditions. 3. Check for flow – A visual check for flow in the annulus will reveal if formation fluid and/or gas is continuing to invade the wellbore or if a kick is beginning to unload the hole. 4. If no flow, circulate bottoms up – Even if the well does not flow from the annulus after shutting down the pumps, a serious problem may be ‘waiting™ downhole in the annulus. It is safe practice to circulate bottoms up if any of the kick indicators show up. This will allow the operator to check for invading fluids or a gas bubble in the well. 5. Shut in the well and check for pressures – A flow of fluids from the annulus after shutting down the pumps indicates real trouble. If this is the case, the blowout preventers should be shut in and pressure readings taken on the drill pipe and casing. This general practice must be tempered with judgment and flexibility to adapt to changing situations. At this point there are 101 things that can and should be done to resolve the well control problem. This text cannot and will not attempt to explain well control or kill procedures as too many variables and combinations of problems may exist in a well. Although many things should be done, one thing which is often done should be avoided. After receiving a kick and shutting in the blowout preventers, many operators settle back to study the problem, thinking they have eternity to come up with lacking needed equipment or a plan of action. A well should not be shut in any longer than is necessary to begin kill operations. When a well is shut in after receiving a gas kick, the gas will rise in the wellbore. Without being able to expand, the rising gas maintains the bottom hole pressure it had when entering the wellbore. If given enough time this gas bubble can rise all the way uphole, exerting extreme or excessive pressure on the BOPS, casing, and exposed formations. If this happens, a number of things can, and often do, go wrong. Well control techniques can be implemented whereby the well can be kept shut in and the pressure caused by the rising gas bled off. Time is of 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 followed when a well indicates it is taking a kick. Closing of the blowout preventers is a must in most serious well control situations, and when closed, the BOP’s must contain anticipated wellbore pressures. Blowout preventers are devices installed on the well head which can close and maintain an effective seal on drill pipe, line, kelly, or open hole when the drill string is out of the hole. For practical purposes we will limit our text to modern preventers, specifically annular preventers and ram-type preventers. Explanation of preventer operation and function is based on the assumption that the preventer is in proper working condition. RAM PREVENTERS Ram preventers are blowout preventers that obtain shut-off by sealing assemblies, generally called rams, moving horizontally inward across the wellbore from two sides. Ram preventers commonly used in Michigan are hydraulically operated and also have manual operating controls. There are two common types of ram assemblies used in ram blowout preventers: pipe rams and blind rams (Figure 1). Another type is the blind/shear ram. This ram performs the same function as a blind ram but it can cut the drillpipe and effect a seal across the wellbore if required. Shear rams are most commonly used in offshore drilling operations. In a number of cases, blowouts through drillpipe have been shut in with the use of shear rams. Figure 1. Shaffer dual body ram preventer – cutaway view, top ram closed. (Courtesy of NL Shaffer) BLIND RAMS Blind rams are designed to close when drill pipe is out of the hole. When activated by hydraulic pressure, two pistons move horizontally toward each other across the wellbore forcing the two ram blocks together. These ram blocks each contain a rubber sealing element on the Circular 17 Œ Page 3 of 17
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face of the block. An effective seal is obtained when the two ram seals are forced firmly together. Blind rams are designed to close without drill pipe in the hole, but in some instances are capable of crimping casing which may be in the hole. The disadvantage of blind rams is that they can be shut effectively only when drill pipe, casing, or lines are out of the hole. Most kicks occur when pipe is in the hole, making blind rams an added safety feature most of the time. Although blind rams cannot be used in many situations, the ram body will accept pipe ram blocks of different sizes and can be converted easily to pipe rams if the need arises. Another type of rams, BLIND/SHEAR RAMS, are specifically designed for crimping and shearing off drill pipe or casing in the hole. Closely resembling blind rams, shear rams have a shear blade which crushes pipe in the hole as the seal is made (Figure 2). The operation of blind shear rams requires greater-than-normal hydraulic pressure and a special ram body capable of holding the longer-than-normal blind shear ram blocks. Except for special situations, blind shear rams are not used in Michigan oil-field operations. Figure 2. Cutaway view of shear ram cutting drill pipe. (Courtesy of NL Shaffer) PIPE RAMS Operation of pipe rams is very similar to that of blind rams, but the ram blocks and seals are different. Pipe rams can close around drill pipe in the hole (Figure 3). Each block is formed to fit snugly around half of the drill pipe and against the other ram block (Figure 4). Pipe rams effect a seal on drill pipe with only 1/8-inch tolerance between the steel of ram blocks and the pipe. The rubber sealing element occupies this 1/8-inch tolerance space and, when closed, seals the annular space around the pipe. This precise fit requires that RAM BLOCKS FIT THE SIZE OF THE PIPE IN THE HOLE. Pipe rams of 4½fl size will not seal on 6″ drill collars or 5½” casing which may be in the hole when a well starts kicking. Proper size pipe rams should be installed in the ram body before using a different size pipe. Pipe rams cannot effect a seal on anything other than the proper size drill pipe or casing. Figure 3. Partial cutaway view, pipe ram in closed position. (Courtesy of NL Shaffer) Figure 4. Pipe ram blocks, white portion is rubber sealing element. (Courtesy of NL Shaffer) Ram preventers are restricted in their single use but used in conjunction offer a good system for containing a kicking well under varying conditions. The blind and pipe ram blocks in a ram preventer are interchangeable, offering a variety of possible system changes or alterations if needed. Ram preventers can be used and tested extensively to rated working pressure without putting damaging stress on the sealing elements. BOP manufacturers contend that rams closed in on a well under pressure can maintain an effective seal even if the closing line pressure is relieved by mechanical or human failure. Although rams can hold a seal under these conditions, intentional relieving of closing line pressure in a wellbore pressure situation is NOT recommended. Wellbore pressure under the rams aids in sealing, and will hold a seal by forcing the rams upward and in toward each other. Although wellbore pressure will maintain the ram preventer in the closed position, operators should not rely on this in their daily operations. Although wellbore pressures assist rams in holding a seal, locking shafts are designed to hold the rams in a closed position (Figure 5). A locking shaft is a threaded Circular 17 Œ Page 4 of 17
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shaft incorporated in the hydraulic closing cylinder. This shaft can be used to lock the rams in a closed position or to manually screw the rams closed without the aid of hydraulic pressure. These shafts are an important part of the ram preventers and should be regarded as such. When ram preventers are installed and tested, the locking shafts should also have proper connections to allow testing. Universal joints attached to the shaft should be rigged up with extensions and large hand wheels to allow manual closing of the rams. Without proper extensions and closing wheels, there is no way the rams could be closed quickly or locked in an emergency situation, such as closing unit or line failure when the well is kicking. True, this emergency situation should never happen; but it is the exception that usually results 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 type of preventer in that they can seal and even strip on pipe of any size or shape which may be in the hole. An annular preventer can be shut in and seal on various shaped kellys, different size drill pipe, collars, casing, or even seal without pipe in the hole. Many people commonly refer to the annular preventer as the “Hydril”, as this company had a virtual monopoly on the annular BOP market from the mid 40’s to the 70fs. Although Hydril is understood to mean annular preventer, the proper term “annular preventerfl will be used in this text, as preventers made by other companies will be discussed. HYDRIL Hydril annular preventers are closed by hydraulic pressure pushing upward a large single piston which encircles the wellbore. The top of this piston is beveled inward; and in the bevelled top rests the doughnut-like sealing element which surrounds the open wellbore (Figure 6). When hydraulic pressure pushes the beveled piston upward, the rubber element is stopped by the preventer top and is forced inward in all directions, effecting a seal on whatever may (or may not) be in the hole (Figure 7). Excessive pressure, or pressure greater than necessary to effect a seal, may cause undue stress and fatigue on the rubber sealing element. It is recommended that closing pressure be regulated to accomodate pipe sizes and wellbore pressures to increase element life. Wellbore pressures contained under the element force it further upward, giving a tighter seal than necessary which, if excessive, may reduce element life. When the piston moves down, the element opens because of the natural, stored energy in the rubber 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 large hydraulic piston pushing upward on the circular sealing element (Figure 8). Unlike the Hydril, the Shaffer preventer piston pushes the element upward into a spherical-shaped head. The spherical contour of the preventer top causes the rubber element to be forced inward in all directions as it is pushed upward (Figure 9). Circular 17 Œ Page 5 of 17
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To open the preventer the piston is hydraulically pushed down and stored energy in the rubber element causes it to expand back to its original shape. Full closing pressure can be used on this preventer without affecting the normal element life. Annular preventers do not have mechanical closing or locking devices. The only way to close this type of preventer is by hydraulic pressure under the piston. The preventer can be locked in the closed position by sealing in the hydraulic closing fluid under pressure, using a valve on the closing fluid line. Canadian requirements call for a valve on the closing line which can be used to lock the annular preventer in the closed position if necessary. Figure 8. Partial cutaway of Shaffer spherical annular preventer. (Courtesy of NL Shaffer) SEALING ELEMENTS Failure of blowout preventers to hold an effective seal can usually be attributed directly or indirectly to the rubber sealing element. The most commonly used material in blowout preventer sealing elements is NITRILE. This special rubber is resistant to deterioration from hydrocarbons and is almost as resilient as natural rubber. Natural rubber elements are most resilient but have the disadvantage of being susceptible to deterioration from hydrocarbons. All types of preventer sealing elements are susceptible to hardening from hydrogen sulfide (H2S). The sulfur in H2S ‘cures™ the rubber in a sealing element, making it harder. If an element has been cured by H2S, it will be less resilient and may develop cracks on the sealing surface. Such hardening will greatly reduce the effective life of the sealing element. Another factor that affects the life of a sealing element is repeated testing. Ram preventer elements can obtain a seal without excessive deformation of the rubber because of the small amount of element exposed. This allows for extensive pressure testing to rated preventer working pressure without damage to the sealing element. Annular preventer elements on the other hand do not enjoy such testing freedom. Shaped steel segments make up the ‘skeleton™ of the doughnut-like annular preventer element (Figure 10). Incorporated inside the rubber, these segments help maintain the element™s shape and keep the rubber from being extruded during high pressure use. Although the steel skeleton keeps the element from being squeezed out of the preventer during use, the rubber portion must undergo great deformation to obtain a seal. Element deformation can be moderate when closed on drill collars, or it can be extreme when closed without pipe in the hole. Extreme deformation of the element combined with high testing pressures can greatly reduce the effective life of the annular element in certain types of commonly used preventers. Manufacturers of some brand name annular preventers recommend use and testing to rated working pressures. Figure 9. Cutaway view of Shaffer spherical closed on drill pipe. (Courtesy of NL Shaffer) Figure 10. Partial cutaway of Shaffer annular preventer sealing element, white portion is steel skeleton. (Courtesy of NL Shaffer) Testing of blowout preventers should be done to insure their reliability, but without damaging the preventer element. To insure testing without element damage, it is recommended that annular preventers be tested to only 50% of their rated working pressure, and never pressure Circular 17 Œ Page 6 of 17
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Circular 17 Œ Page 8 of 17 placement on the bottom of the stack arrangement a sensible alternative. If a well control problem develops that cannot be handled by t he existing stack, most annular preventers are made to accept additional BOP stacking on the top. This can be extremely important in special high-pressure stripping operations or where H 2S gas is involved. TESTING Installation of blowout prevention equipment is only the first major step in achieving a workable pressure-control system. The second step is making sure the equipment will work. After blowout preventers are installed they must be pressure tested to insure complete performance in a well control situation. Without prescribed, periodic pressure testing, one can only assume that the system will function properly. Assumptions are dangerous things on which to risk life and resources. The function in many phases of a regulatory field geologist’s work is to ‘assume nothing’, and this should be emphasized where blowout prevention is involved. Act 61, P. A. 1939, as amended, specifically requires testing of blowout prevention equipment. Rule 302, section e) states: Blowout prevention equipment shall be tested to a pressure commensurate with the objective formation before drilling the plug on the surface pipe, before encountering the objective formation, and at other intervals in accordance with good oil field practice. A record of each pressure test and each mechanical test of the casings, bl owout preventers, surface connections and fittings, and auxiliary well head equipment shall be entered in the log book, signed by the driller, and kept available for inspection by the supervisor or his authorized representative. fi. . . pressure commensurate with the objective formation . . .fl simply means equal to the known or anticipated formation pressure. Note that this rule calls for testing blowout prevention equipment “before drilling the plug on the surface pipe, before encountering the objective formation, and at other intervals. . .fl. There is a dual advantage in having the blowout preventers tested just prior to drilling the objective formation. First, it enables the crew that will likely be drilling the pay section to become more aware and conf ident of the preventer system and its operation. Secondly, this test usually finds leaks or problems that have developed since the first pressure test several days or weeks previously. Some of the problems that can develop between preventer tests are such things as: 1) flanges or seals developing leaks from vibration; 2) salt, mud, and/or cuttings accumulating on preventer seals; or 3) system alterations. Additional blowout preventer testing procedures are required for wells drilled below the base of the Detroit River Group. These requirements, set forth in SPECIAL ORDER No. 2-73, AMENDED, (Pages 32-34) most commonly involve wells drilled to the Niagaran formation in the northern and southern reef trends. SPECIAL ORDER 2-73, AMENDED, defines casing, cementing, blowout preventer equipment, and testing requirements. This order requires three complete pressure tests of the blowout prevention equipment: 1) before drilling the plug on surface casing; 2) before drilling the plug on intermediate casing; and 3) prior to drilling potential producing zones. A record of each test and notation in the log book of any failures and/or repairs is also required. The following discussion will deal with standard procedures for testing in accordance with SPECIAL ORDER 2-73, AMENDED. Before blowout prevention equipment can be installed, a suitable string of surface casing must be set and cemented. SPECIAL ORDER 2-73, AMENDED, requires surface casing to be set at least 100f below all fresh water aquifers and cemented to the surface. In some areas this is deeper than 100™ below the glacial drift, as fresh water aquifers are found in some bedrock formations. A blowout preventer stack comprised of an annular preventer over tw o ram preventers is then installed on the surface casing. Before drilling the surface casing plug, the blowout preventers and surface casing are pressure tested in accordance with good oil field practice. Testing is usually accomplished by using the rig mud pumps. Blind rams are first tested by closing them on the open hole and pressuring up from the kill line. This provides a pressure test upward against the closed 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 pipe rams and annular preventer are individually tested by closing them on the drill pipe and pressuring up through the kill line or drill string. Pressures involved for testing the surface casing and preventers are between 1000 and 1500 psi. The second test of the blowout preventers is done before drilling the plug on the intermediate casing. Unless an exception has been granted prior to permit issuance, intermediate casing is set below all porous or lost circulation zones between the Amherstburg Formation and within the top 50 feet of the Salina A-2 Carbonate. Intermediate casing is cemented with a minimum of 500 feet fill-up above the casing shoe, and this must be confirmed by a verified temperature survey. Prior to drilling the cement plug, the blowout preventers, kill line, choke line and assembly, and intermediate casing are each tested to 1500 psi for at least 20 minutes. This testing can be done with the rig pumps, a service company pump truck, or by a blowout preventer testing company. Procedure for testing blowout preventers at this point is basically the same as that used in the first test on the surface casing. The final pressure test required by SPECIAL ORDER 2- 73, AMENDED, is prior to drilling potential producing zones. “Prior to” is understood to be anytime after drilling a well into the B salt but prior to penetrating the A-1 Carbonate on Niagaran well s. 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 for complete blowout preventer system testing, many operators have found it advantageous to use the services of specialized blowout preventer testing companies. This testing service will be discussed in explaining the final test procedure prior to drilling potential pay. Most service company testing of blowout preventers is accomplished by use of a truck-mounted testing unit. The truck is equipped with a triplex pump which is used for pressuring up the blowout preventer system through a high pressure rubber hose to well head connections. Time/pressure recording clocks are used on the testing unit to provide an impartial and accurate recorded chart of test times and pressures. Figure 12 is an example of a chart recording of a blowout preventer system and casing pressure test. A water tank which holds green colored test water used in pressuring up the preventers is also mounted on the testing unit. Figure 12. Time/pressure chart of BOP system test. One hour chart time is actually 20 minutes. (Courtesy of Double Check) Before any pressure testing is done, the blowout preventers, kill line, and choke assembly are flushed free of drilling muds. Mud is a poor test fluid because solid and colloidal particles in the mud will aid in sealing a leak which may not hold water or gas under pressure. A special test water which aids in leak detection is used in pressuring up the blowout preventers. A green fluorescent dye (developed by the Navy in World War II) is added to test water in the holding tank. Even slight weeping-type leaks in flange connections are easily detected by this green-dyed water. Water also has very low compressibility, a characteristic which makes it a desirable medium for pressure testing. A sensible principle employed in testing blowout preventer systems is to restrict the portion tested to the smallest possible area of the system. Testing small or isolated parts reduces the possible places where leaks might occur, aids in leak detection, and saves time in testing which, of course, is money. Many operators, and all prudent operators, test the entire blowout preventer system and all related equipment which may be subject to well pressure. A well control system is only as good or bad as its weakest point. The following paragraphs describe parts of the system which are tested, and these are presented in the general testing sequence. KILL LINE. The entire length of the kill line from the mud pump connection to the valves on the drilling spool is tested to the rated working pressure but not less than 1500 psi for 20 minutes. Pressure is applied (test water pumped) into the auxiliary kill line which is tied to the main kill line. This auxiliary 2fl-valved kill line should be available for service company hook-up in the event the mud pumps fail or cannot handle the well control operation. Testing the kill line in this manner does not allow for a pressure test on the kill line check valve, which must be tested later from the well-bore toward the check valve. The two recommended valves between the check valve and drilling spool are each individually tested with 3000 psi pressure, applied from the spool toward the valves. STAND PIPE & KELLY COCKS. The entire system from mud pump discharge to the kelly is pressure tested by pumping back up the kelly. A special fitting which screws onto the kelly sub allows pressure testing of the kelly cocks, swivel, drilling hose, stand pipe, and line to the mud pumps. Figure 13. Pressure test of blind rams and outer valves on spool. Darkened portion under pressure. (Courtesy of NL Shaffer) CHOKE LINE & MANIFOLD. The choke line and manifold (including all valves) are pressure tested to 3000 psi. This can be accomplished by pumping test water through the choke pressure-gauge fitting on the choke manifold without the loss of rig time. Test Circular 17 Œ Page 9 of 17
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