 Oil, gas, or geothermal well blows out when there is an uncontrolled flow of mud and formation fluid from the well. Not all blowouts include well fires, but this one did. In 1980, at a well in the Lost Hills oil field, a production packer malfunctioned during changeover operations, leading to a high casing pressure. With any vacuum truck, removing drilling mud at the site pulled away too soon, breaking off the casing valve below the BOP equipment. For an hour and 45 minutes, the well flowed oil, gas, mud, and completion fluid through the hole in the casing before a rock from the well caused a spark in the cellar and the gas ignited. Early the next morning, workmen put out the fire with a dry chemical extinguisher. Three days later, the well was killed by pumping heavy mud into the well bore. In 1974, a well being drilled at the McDonald Island gas storage field blew out and burned for 19 days. The fire was extinguished and the well was brought under control by drilling a relief well nearby. The blowout was caused by swabbing action. When the drill pipe and bit were being pulled from the hole, mud began to blow out of the drill pipe and about a minute later the gas ignited. The crew stated that although they tried to actuate the BOP hydraulic controls, the controls did not work properly, though they were apparently in working order before the blowout. This geothermal well blew out at the geysers geothermal field in March 1975. The blowout occurred when the casing was sheared off about 125 feet below the ground. The break may have been caused by a landslide. The blowout was controlled by excavating around the well casing to a depth of 82 feet and installing two steam relief systems. New segments of the casing were welded on to replace those removed through excavation and the hole was backfilled. Finally, the well was squinched by pumping in large volumes of cold water. In the early days, oil and gas wells were drilled without mud or other precautions against blowouts. Blowouts were a frequent part of oil field life, signaling production strata had been reached. Today the recognition of the enormous waste of resources that a blowout causes, as well as the damage to the environment, loss of equipment, danger to human life and financial loss have stimulated the development of modern BOP equipment and blowout prevention practices. The blowouts you have just seen were exceptional events because today blowouts rarely occur in California. We feel that one of the primary reasons for this is the enforcement of division laws and regulations by engineers such as yourselves when you witness BOP tests and inspect BOP equipment. Learning to test and evaluate BOP equipment requires both knowledge and experience. Basic BOP data are in the division publication MO7, Oil and Gas Well Blowout Prevention in California. This manual is your guide to proper BOP equipment. Study it carefully. But just knowing what is in the manual is not enough. You also need hands-on experience and the more the better. Not only are well sites and equipment different, there are four BOP classifications to become familiar with. Class three, the one most commonly used in California, is the only one discussed in this film. Only a few more steps are involved for class four. Class one and class two installation procedures are less complex than those for a class three well. Most of you know Bill Stark. Bill is a division engineer, especially familiar with BOP tests and equipment. In this film, he will demonstrate how BOP equipment is tested and inspected. He will use diagrams as well as BOP equipment set up by H&H Tool Company in Santa Paula. Appropriate sections of the blowout prevention equipment memo will be shown throughout this demonstration. This form must be completed forever well that is inspected or tested. Also, Bill will look at and discuss BOP equipment at active rigs. His comments on what he sees are the result of years of work. I am especially pleased to bring to you, through this film, the experience and knowledge that Bill Stark has about the oil patch. And in particular about BOP equipment. One of our responsibilities, of course with the help of the drilling foreman and production foreman, is to test and inspect blowout prevention equipment. For this particular demonstration, I will be manipulating the various types of valves and so forth. But if this were an actual test, that responsibility would be with the well foreman or rig foreman. The class of BOP equipment used at a particular well depends on the proposed well operations and the MPSP, or the maximum predicted surface pressure. Record this information, which is available from the P report posted at the well site. Also, fill in the casing record of the well, the hole sizes and the cement details. The information is available from the tower sheets. As a division representative, you must ensure that each well meets division requirements for casing, cementing, whole fluid monitoring equipment, BOP equipment, including the actuating system, the control stations, the emergency backup system, and the auxiliary equipment. First, we want to determine what positions the valves are in. They should all be in the open position. Then we'll notice the pressure gauge, which is the accumulator pressure gauge. In this case, it reads 3,000. We have our manifold pressure at 1,500 and our high drill pressure at about 700. With all these in the open position and the pressure remaining static, we can determine that the blowout preventer equipment is not leaking in the open position and that there is no leaks in the manifold system in the open position. To test our pressure switch, we can bleed a little fluid through the bleeder valve here. Watch the gauge for the accumulator pressure and we can see that it kicks in The backup, until it kicks off, we can determine the amount of pressure on the accumulator. It kicks off at about 2,900 to 3,000 pounds, which is good. We can determine also that the accumulator, the remote switches are electrical. We can look through the system and determine if there is any leaks in any of the valves. All the valves in this system drain right back into the reservoir. Record the working pressure, the total rated pump output, and the distance of the unit from the well bore. Also note the manufacturer's name, the accumulator's capacity, and the pre-charge pressure. This particular accumulator is an H&H, very similar to a Akumi accumulator. If the accumulator unit seems to be inadequate, it can be tested by a method described in the BOP manual. To make sure all the accumulator pumps are functioning, we will use the following test. Record the results. We will disconnect the electrical from the pump. We will then close the blind realms. And we will watch the pressure drop, and the time that it took to close them was about 3 seconds. The pressure drop, we will read that from the accumulator pressure from 3000 to 2100. Now we will plug our accumulator back into the source and time how long it takes to pump the system back up to 3000 pounds. Rated output of the pump is within 80% of its capacity. Convenient sight to show the level of our fluid. If we did not have this, we could determine it should be 10 inches below, no more than 10 inches below the top of the accumulator. We want to make sure that the electrical outlet to the accumulator unit shall not be interrupted during normal well operations. We also want to make sure that it does not share a common outlet with any other electrical plug-in in the system. We want to make sure that all the valves in the system can be operated by hand without using any other mechanical means. Two 80 gallon hydril accumulators, the nitrogen system is the same as the H&H. This is the petcock to check the fluid level in this type accumulator. This vent in our manual states to look through this vent at the return line to see if we have any leaks. I'd like to mention that to really see this you must have a mirror and in most cases the flashlight to be able to see the fluid returning through the return line. The pumps on this accumulator are located here and this particular pump puts out approximately 1.7 gallons per minute. Also you want to make sure that the accumulator is well vented. In some cases where they might have to use the nitrogen, if it's not well vented there's a possibility of bursting the reservoir. Here we have the emergency backup system hooking into the pressure block. This pressure block contains a check valve to keep the nitrogen from returning back into the accumulator when it's empty. When you look at the emergency backup system, note the system type. First we want to check each of the fittings and hoses and make sure that they're not of a low pressure. It can be very dangerous to open one of these valves and one of these blow off. So we check this to make sure that it's safe. Then we will open the first bottle, make sure that this valve is closed before you start. Now that we've got one bottle open we will check our pressure gauge. This particular bottle is about 2,700 pounds. Now we will close this one and open the next bottle. Our pressure gauge still remains at 2,700 pounds. We've determined that both of these bottles are equally pressurized at 2,700. Had this bottle been less than 2,700 pounds the pressure would have equalized into the lower pressure bottle. We will check the third bottle now. Our pressure gauge still remains at 2,700 pounds. This shows us that all the bottles are fully charged. We can now close all these off. One other thing I would like to mention that this system should have a valve of either a gate valve or some sort of valve, check valve. This particular system has a check valve. In case we have to use the nitrogen system to close the preventers in emergency we won't lose all of our nitrogen in these bottles that would be depleted. If you feel the accumulator is inadequate, isolate the accumulator pump motor from its power supply. Hang the smallest OD pipe for which the pipe ramps have been installed through the preventers and perform the following test sequence within one minute time span. Close and open the pipe ramps. The pressure should remain, should not be no lower than 1,200 psi. In this case we have approximately 1,350 pounds which shows that the accumulator is very adequate. Determine if the control manifold is an electric or hydraulic model and record this information. The distance between the control manifold and the well bore must be 50 feet. Access to the control manifold must be unobstructed. The control handles must be properly labeled as to function. Hydreal, open, close, pipe ramps, open, close, blind ramps, open, close. We want to determine as nearly as possible if the regulators on the accumulator is working properly. We have one regulator that regulates the hydreal pressure. That would be this gauge. It is increased by turning this. We can decrease it with this valve. 700 pounds is a good operating pressure for hydreal. On this side we have another regulator. This regulator regulates the manifold pressure. It reduces the 3,000 pounds down to 1,500 pounds which is operating pressure for most BOP equipment. In the same manner as the hydreal, we decrease the pressure by opening this valve. And we increase it by opening this valve. This should remain at approximately 1,500 pounds at all times. A remote station must be within 10 feet of the driller or head well puller. Record the remote station type. Check over the whole fluid monitoring equipment. Indicate whether each component has an audio or visual alarm system. This system has an audio alarm. Here is a calibrated mud pit. This is a pump stroke counter. You will find this device on the side of each pump being used. This is the pit level recorder. This is the flow sensor. This device is mounted on the flow line. And well when the mud flow is either too high or too low. The system becomes a mud totalizer simply by adding floats to each mud pit in the system. The total mud volume is then recorded on this recorder. When pressure testing is required, the kill line, BOP stack, choke lines, internal preventer, Kelly Cox and stand pipe valve must be tested in the direction of the blowout flow. Before beginning this process, examine the system and record the appropriate information. Determine that all kill lines, choke lines and fittings conform to the division's requirements. Close the choke manifold valves farthest from the well bore. Making certain that all other valves in the choke system are fully open. Close the blind ram preventer using the remote station. Apply the predetermined test pressure to the well bore through the kill line. Observing the pressure gauges at the pump and at the choke manifold to see that they coincide within 10%. When the pressure is stabilized, close the kill line control valve next to the well bore. Bleed the pressure at the pump. The pressure at the choke manifold should remain at the stabilized value. When the kill line is required to have a check valve, class 3 and class 4 BOPs, open the kill line control valve and check that there is no decrease in the pressure at the choke manifold. Working with each line in the choke manifold separately, close the next upstream valve and open the downstream valve until all the valves in the manifold except the adjustable choke have been operated. There should be no change in the pressure as indicated by the choke manifold pressure gauge. All valves should be operable by one person without mechanical assistance other than a pipe wrench. Bleed the pressure from the well bore through the choke manifold and open the blind rams. All valves on the outboard side of the manifold must be in the closed position. This valve, this valve and these two valves. All other valves in the system must be open. In this particular case that we do not have a bleed line or a choke line, but in a natural test we would have these two lines hooked up to a tank or into the production system. Close the blind ram preventer at the remote station. We see that it's operating right here. Record the test data. I am applying the predetermined test pressure to the well bore through the kill line. The pressure is indicated on the gauges here at the pumps and at the choke manifold should coincide by 10%. I will now close the kill line valve next to the well head. Now I am bleeding the pressure at the pump. The pressure at the choke manifold should stay at the stabilized value. When the system has a check valve, we must open this valve and not lose any pressure at the choke manifold. The pressure at the choke manifold should be the same as before opening this valve. We will now close this valve. We now will bleed the pressure from the choke manifold through this valve, the outboard valve. Our gauge should remain at the predetermined pressure. All class 3 BOP equipment should have a choke. And we do not require a test of the choke, but we do require that the choke be operable by one person and by hand. We will now bleed the pressure from the well bore through the choke manifold. Open the blind rams. We have two T's here. In my left hand, this is a 3,000 pound steel T. It is rated for 3,000 pound. This is a 250 to 300 pound T. If this was put into the killer choke line, it would be the weakest point of the system and could cause injury and possibly cause uncontrolled blowout. Here we have a rising stem gate valve. This valve can be used in geothermal, but should never be used in oil and gas in the killer choke lines. This valve is a 5,000 pound ball valve and it is a full opening valve. This is a very good valve to be used in the system. This valve is a non-rising stem valve. It is also a gate valve. You can tell it is a non-rising stem. If you open this valve, this part, it remains stable at this point and the stem is never in sight. I would also like to point out the armor coated lines that are now acceptable by OSHA and the division at the BOP. Run enough pipe into the hole when possible to prevent jacking the string back out when the test pressure is applied. Attach the kelly to the pipe string and establish circulation through the kelly to the flow line. Close the upper kelly cock and raise the pipe string until the kelly bushing is out of the rotary table. There should be no pipe upsets opposite the pipe ramps or annular preventer. Close the annular preventer using the remote station. Close the stand pipe valve and apply the test pressure through the kill line. Observing the choke manifold pressure gauge, the stand pipe pressure gauge should not register any pressure. Bleed the pressure from the well bore through the choke manifold and open the annular preventer, the upper kelly cock and the stand pipe valve. We have now run enough pipe into the hole to prevent jacking the string back out when the test pressure is applied. We have attached the kelly to the pipe string and have established circulation through the kelly to the flow line. We have closed the upper kelly cock and raised the pipe string until the kelly bushing is out of the rotary table. There should be no pipe upsets opposite the pipe ramps or annular preventer. Close the annular preventer at the remote station. Make sure there's no leaks in the four-way valve or the annular preventer. We'll take a look inside and everything looks good. Close the stand pipe valve and apply the test pressure through the kill line. Observing the choke manifold pressure gauge, the stand pipe pressure gauge should not register any increase. We will now bleed the pressure from the well bore through the choke manifold. Open the annular preventer, the upper kelly cock and the stand pipe valve. Close the pipe ramps using the remote station. Apply the test pressure through the kelly. Observing the pressure gauges at the stand pipe and at the choke manifold, they should coincide within 10%. When the pressure is stabilized, close the choke line control valve adjacent to the well bore. Open the choke manifold to the atmosphere. Observing the pressure at the stand pipe. There should be no deviation as the choke manifold pressure goes to zero. Close the valves downstream from the choke manifold pressure gauge. Open the choke line control valve adjacent to the well bore. The pressure gauges at the stand pipe and at the choke manifold should again coincide but at a slightly reduced reading. Close the stand pipe valve and bleed the pressure at the pump. Observing the stand pipe pressure gauge. There should be no deviation as the pump pressure goes to zero. Close the lower kelly cock if one is installed and open the stand pipe valve. Observing the pressure at the choke manifold. There should be no deviation as the stand pipe pressure goes to zero. Bleed the pressure from the well bore through the choke manifold. Break off the kelly and install the safety valve and an internal preventer in the top of the pipe string with the internal preventer uppermost. Close the safety valve and leave the internal preventer open. Apply the test pressure through the kill line. Observing the pressure at the choke manifold gauge. When the pressure is stabilized close the internal preventer and slowly open the safety valve. There should be no backflow. Bleed the pressure from the well bore through the choke manifold. Remove the safety valve and the internal preventer and open the pipe ramps. Close the pipe ramps at the remote station. We will now observe inside the river bore to see if there's any leaks in the pipe ramp in the full way valve or the ramps themselves. Everything looks okay. Apply the test pressure through the kelly. Observing the pressure gauges at the stand pipe and the choke manifold. The pressures should coincide within 10%. Then close the choke line control valve adjacent to the well bore. Open the choke manifold to the atmosphere. Observe the pressure at the stand pipe. There should be no deviation in the pressure as the choke manifold pressure goes to zero. Close the valves downstream through the choke manifold pressure gauge. Open the choke line valve adjacent to the well head. Observe the choke manifold gauge and the stand pipe gauge. The pressures should coincide but at a slightly reduced reading. Close the stand pipe valve. Bleed the pressure at the pump observing the stand pipe pressure gauge. There should be no deviation as the pump goes to zero. Bleed the pressure from the well bore through the choke manifold. Break off the kelly. Install the safety valve and the internal preventer in the top of the pipe string with the internal preventer uppermost. Close the safety valve leaving the internal preventer open. Apply the test pressure through the kill line observing the pressure at the choke manifold gauge. Slowly open the safety valve. There should be no backflow from the internal preventer. Bleed the pressure from the well bore through the choke manifold. Remove the internal preventer. Remove the safety valve. Open the pipe ramps. We also want to note the type, model and pressure rating of the different types of BOP in the stack. Here we have a Hydro GK 5,000 pound pressure rating. Here we have a double shaft type B 5,000 pound pressure rating. We have this stack on a 5,000 by 3,000 crossover mud cross. The system, the pressure rating of the system would depend upon the weakest part of the system which is 3,000 in this case. As we carry out the division's inspection procedures we play an important part in assuring a continued wise and safe development of our petroleum and geothermal resources.