ICWF Study Pack

IWCF Well Control Study Pack Level 2, 3 and 4

IWCF Well Control Study Pack

Introduction: The intent of this study guide is to help you prepare for the IWCF Level 3 and Level 4 Supervisor Well Control Exam (Surface and Combined Surface and S ubsea BOP). This guide does not replace the requirement to attend a certified I WCF Well Control school, instead, it serves to supplement the training received in the classroom and to ensure you’re as prepared as possible on examination day (usually the last day of your IWCF class). This guide assumes that you have a “general” idea how oil and gas wells are drilled and at least a basic

understanding of common well control calculations from an introductory IADC or IWCF well control course and/or company provided training material. This guide also assumes you have have at least a month

to study BEFORE your IWCF exam. Strengthening the need for this guide, many companies and organizations (including the one I work for) are pushing for an “Enhanced Standard” of well co ntrol requiring students to obtain an average score of at least 80% to be recognized as having passed the course (even t hough the minimum IWCF passing grade is 70%). I’ll start with the “basics” and then break down each individual test (Simulator, Equipment and P&P) into its own section with some of t he preparation tips that helped me pass the exam. I’ll also add that this guide is NOT a well control manual. Instead, it is a tool to help you study for and pass the IWCF Level 3 and Level 4 well control certification exams using information that is already available to you on the internet and in Study Pack in the Appendix of this guide.

Basics: Firstly, the IWCF test is no joke. Whether you’re taking IWCF Level 2, Level 3, or Level 4, it is as difficult difficult as everybody says it is. If you don’t prepare prior to the class and you’ve never been through IWCF advanced well control before you’re not going to do very well . This is especially true for for students pursuing Level 3 or Level 4 certification as it adds a graded pract ical exam (simulator exercise) to the mix. The GOOD NEWS is you have control over your own destiny and it’s only a matter of how important passing is to you. You WILL PASS the class if you put the effort in. EVEN BETTER, you can ACE the exam if you follow my techniques. By far the most IMPORTANT thing you can do to prepare for the IWCF exam is to review the “Study Pack” questions in the appendix. Even if you know nothing about well control, control, you’ll pick up a great deal going through the questions over and over. At first it seems like you’re doing nothing but memorizing the answers, but after a while the questions start to “connect” and you begin to get a sense of what w hat is actually going on.

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IWCF Well Control Study Pack I would estimate that I went through every question in the Study Pack at least 5 t imes (approximately 450 questions spread out over 8 sections). After a while, there will be many questions that will become easier than others. I would highlight the most difficult and challenging challenging questions with a red highlighter so I could focus more on those and not waste time studying the easier questions I already understood (it’s all about efficiency). The most effective way I found to do this was to hit the mate rial in small 30-45 minutes blocks a few times each day. Not only will this prevent you from from burning out, but it will also allow time for the material to sink in so you can build on it during the next study section. I found it was also helpful to take a day or two off every once in a while to reset. The knowledge you gain from reviewing the study pack questions will help you in all three exams required by IWCF Level 3 and Level 4 certification.

The Simulation “Practical Exam”: If you’ve never had any real re al drill floor experience at the Assistant Driller or Driller level, you’re going to be out of your comfort zone when it comes to the simulator exercise. This is especially true if you’re taking the ICWF Level 3 or Level 4 supervisor exam. By registering for the class, it is assumed that you’re comfortable with drilling operations and will know exactly what you need to do to line up the drilling equipment and give the driller “instructions”. The IWCF provides a general “outline” of w hat points you’ll be graded on but it offers absolutely no help with what you’re actually supposed to say during the exercises (you literally have to act o ut a scenario and give realistic instructions to the driller who is coming on “tour”). This was a challenge for me since I’ve NEVER been directly involved in the drilling operation during my career. Not only did I not know much about lining up a choke manifold or standpipe manifold, I knew virtually nothing about what RPM to drill at, how much pressure to maintain on the drillpipe (or SPM on the mud pumps), how much weight to maintain on the drill bit while drilling, etc.

Well Control Simulation Video: A great resource that helped me was a YouTube video produced by the Arabian Drilling Company that walks you step-by-step through the IWCF well control drilling simulation process: https://www.youtube.com/watch?v=hiTaE6lDH_U) I’ll be the first to admit that the video is a little cheesy but it follows the IWCF well control script perfectly and covers virtually every aspect o f a well control situation that you’ll likely encounter during your IWCF simulation exam. I will add that the well control simulator used in the video is probably probably a lot more sophisticated than you’ll find in the well control school that you attend but the overall concept and theory is exactly the same.

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I basically memorized what the toolpusher’s instructions were to the driller in the video and repeate d them during my time in the simulator. The best part about doing this is the “instructions” you give to the driller count for a very large percentage of your IWCF simulator score. Even if you don’t do so hot exercising the choke during the well kill simulation, you can still get a decent score by following the script outlined in the Arabian Drilling Company Well Control Video. During the week of my well control school I would practice the script in my hotel room by rehearsing what I was supposed to say into the voice recorder on my iPhone again and again until I could go all the way through the “driller instructions” without missing any of the “criteria” on the IWCF score sheet. I know this sounds lame to many of you reading this, but it HELPS! Here’s a rough transcript of what I practiced saying to the driller during the initial set-up of the drilling operations. The good news is you don’t have to say these in the exact order as long you cover all the basic points as outlined in the IWCF criteria.

“Good morning, driller. I hope you had a good night’s rest. Today we’re going to be drilling at 100 RPM, 25,000 to 30,000 weight on bit with 2500psi on the drillpipe pressure gauge. However, before you get started I want you to check your equipment and make sure you have everything set up the way it needs to be.” “Please check your BOP panel for proper valve positions and ensure you have the appropriate pressure readings on your gauges. Check your standpipe manifold for proper valve alignment, we’re going to be drilling using mud pump #1 today. Also check your choke and kill manifold and ensure it is set up for a “hard shut-in since this is the Page 3 of 24

IWCF Well Control Study Pack method I want you to use as per company policy in the event we do need to shut the well in.” “You’ll also need to take your slow circulating rates at 25 and 30 strokes per minute (SPM) on mud pumps 1 and 2 as well as find the choke line friction losses for both pumps at 25 and 30 SPM as well.” “Once you have your pumps up and running. Make sure you set your pit level and flow meter alarms and find your “space out” and “hang-off” positions. In the event we need to hang off, I’d like you to hang-off 50% of the string weight on the upper pipe ram.” “Finally, I want you to flow check all drilling breaks and shut the well in immediately if you have any concerns or doubts. DO NOT CALL ME FIRST.”

TIP 1: If you have difficulty “memorizing” the well control instruction roll play script you’re supposed to give to the driller, you can also just use the well control equipment in the simulator room to “prompt” you with what to say. For example, the simulator equipment above is typical of what you might find at a typical drilling school. You can just work your way through each piece of equipment on the control panels and on the computer screen to help you to make sure you don’t miss any of the points covered in the video. On the computer screen you’ll see (from right to left) the choke manifold, drill pipe manifold, drillers panel and BOP panel. You could give your driller instructions in the order the equipment is presented to make sure you don’t miss anything.

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IWCF Well Control Study Pack “Driller, please check your choke manifold, stand pipe manifold, drillers panel, and BOP panel for proper alignment and settings.” BOOM, that’s probably 15-20% of your grade right there just using what’s available to you! On the left hand panel, you’ll see the alarm settings for the flow meter and pit gain alarms. If you’ve missed these alarms during your instructions to the driller, you’ll remember them if you go through all the equipment gauges prior to starting up the exercise.

TIP 2: Another invaluable thing to do is take a few pictures of the various scree ns and panels during your practice simulator exercise that you can review in your hotel room in the evening. Practice your “roll playing” again using these pictures as prompts and guides. It will be tremendously helpful!

TIP 3: On the IWCF practical exam (simulator), you get to decide which method to use to “kill” the well. I HIGHLY recommend that you use the “Drillers” method. The IWCF practical exam concludes after the initial influx is circulated from the well which means if you chose the drillers method, you’ll only have to make the first circulation and not have to worry about following the drillpipe pressure schedule you created on your killsheet (more on this later). You can fool around using the Wait and Weight method if you want to, but following the drillpipe pressure schedule on your kill sheet will make it much more difficult to detect one of the four “problems” (see next paragraph) that will be thrown at you during your exam by your instructor.

The Four IWCF Simulator Problem Scenarios: As mentioned above, you’re expected to know what to do in the event you encounter any “problems” during your IWCF practical simulator exam. Fortunately, the Arabian Drilling Company well control video covers the four basic problems that you’ll likely encounter during your well control simulator exam. I’ve summarized each below but you’ll probably get more out of just watching the video a few times until you understand exactly what the choke operator is doing. You can count on experiencing at least one of the below problems during your practical exam so mastering t hese concepts is time well spent and an easy way to pad your exam score.

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Choke is Washing-Out : Detecting a Washed-out Choke: If you have to keep closing the choke to maintain drillpipe, casing and kill-line pressure, you can reasonably assume that the problem is a washed-out choke (you’ll notice the casing and kill-line pressure start to drop first followed a short time later by the drill pipe pressure). If you use the driller’s method like I recommend, this scenario will be relatively straightforward to detect.

Dealing with a Choke Wash-out: If you detect that your choke is washing out you should immediately order the driller to isolate the choke by closing a valve upstream of the choke. Once the washed out choke is isolated, you need to quickly shut down the pump to avoid adding too much bottom hole pressure (from pumping against a closed choke). Once the pump is shut down you can line up on choke #2 (backup choke) and resume the k ill. (Note: This was the scenario I was given during my practical exam).

Choke is Plugging: Detecting a Plugged Choke : If you have to keep opening the choke frequently to maintain drillpipe, killline and casing pressure, you can reasonably assume that the choke is plugging (you’ll notice the choke pressure and kill line pressure start to rise first, followed a short time later by the drillpipe pressure gauge). Again, if you elect to use the driller’s method during your IWCF simulator exercise this scenario will be much easier to detect.

Dealing with a Plugged Choke : If you detect that your choke is plugging, you should immediately shut down the mud pump. After the pump is off, line up on choke #2 and start back up the well killing process.

Mud Pump Trips Offline : Detecting a Tripped Mud Pump : Detecting a tripped mud pump is probably the easiest problem to detect during an IWCF well control simulator exam. In this scenario, you’ll notice your strokes per minute counter either go to “0” or go blank and your drill pipe pressure drop off quickly. If the simulator room is equipped with sound effects (like the o ne I was in), you’ll also notice the r oom get very quiet.

Dealing with a Tripped Mud Pump : If your mud pump trips offline during your well control scenario, all you have to do is immediately close the choke and then line up to use mud pump #2. Even if you chose to use the driller’s method to kill the well, you’ll need to remember to recalculate your Initial Circulating Pressures and Final Circulation Pressures, as well as your “step down” pressure schedule on your kill sheet since you’ll be using a different m ud pump that likely has a different “slow pump rate” (more on this later).

Plugged Bit: Detecting a Plugged Bit : The forth and final “problem” that could be thrown at you during your IWCF simulator exercise is the plugged bit. In this case, you’ll see your drillpipe pressure gauge increase Page 6 of 24

IWCF Well Control Study Pack sharply while the casing gauge and kill-line gauge (assuming you’re on a subsea well) will remain approximately the same.

Dealing with a Plugged Bit : If you encounter a plugged bit, take note of the pump pressures. It will be expected that you slowly stop the mud pump (gradually slowing the pump maintaining casing and killline pressure). Once you’re confident that the issue is indeed a plugged bit, you’ll start the pump back up and the new Initial Circulating Pre ssure will likely be whatever the drillpipe pressure gauge was reading before you started shutting the pump down.

Creating Simulator Flash Cards: To help me prepare for any of the above issues, I made fo ur flash cards (one for each possible scenario). On the front of the card, I drew little gauges with pressure readings with a brief description that represented the tell tales of each possible problem that the simulator instructor could throw at me. On the back of the card, I would write out what I needed to do to remedy the problem. Every once in a while I would run through these cards until it became second nature to identify the problem and what would need to be done to solve it. Since you’re guaranteed to get at least one of these problems during your exercise, it is another excellent opportunity to master these are as to pad your final practical exam grade.

Operating the Choke: The final piece of the simulator exam is learning to properly operate the c hoke to circulate out the influx while maintaining bottom hole pressure. This was a very intimidating skill for me to obtain especially after the first day in the simulator (during one of the practice ex ercises) when I just couldn’t figure out how to keep the drill pipe pressure where I wanted to. Fortunately, as the week went on I got better and better. Remember, there is a “lag time” between opening or closing the choke and noticing a change in your drill pipe pressure gauge (approximately 2 sec for every 1,000 ft MD of the well). Most of the scenarios you’ll be doing in your simulator exercises are between 5,000 and 8,000 feet so you can expect a 10-20

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IWCF Well Control Study Pack second delay for choke adjustments to be reflected in your drillpipe pressure. This was one of the most challenging aspects of the simulations for me until I learned to simply use the casing gauge and kill gauges (for subsea wells) to monitor and detect sudden changes in the annulus’s pressure. For example, if you close the choke, you’ll see the affect on the casing gauge almost immediately vs. waiting 10-20 seconds to see the change in your drill pipe gauge.

Here’s the pressure graph from my actual IWCF Level 4 simulation exam :

Minutes 0-40: The first 40 minutes or so of the exam was going over the “instructions” to the driller as well taking the slow pump rates (SPR) and c hoke line friction (CLF) values.

Minutes 40-70: During this time frame, the driller starts actually drilling the well and the supervisor (Level 4 candidate) is actually out of the simulator room. The blue line represents the drill pipe pressure and you can see he actually shut down the mud pumps a couple of times to “flow che ck” some drilling breaks that he recognized (Drilling Breaks: Dr illing breaks are when the rate of penetration (ROP) of the drill bit increases dramatically over a short period of time).

Minute 70-73. The driller detecting a kick and the well is flowing. He shuts the well in and calls the supervisor (Level 4) into the simulator room.

Minute 73-105: The mud pump is slowly brought up to kill rate speed in 5 SPM intervals while the Level 4 supervisor slowly opens the choke to maintain the original casing pressure. Once the mud pump is

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IWCF Well Control Study Pack slowly brought up to the kill rate speed, you need to take note of the Initial Circulating Pressure to make sure it is close to what you calculated on your kill sheet (more on Kill Sheets in a bit).

Minute 105: At approximately minute 105, you can see where the black line (bottom hole pressure) started to drop off. This was when the simulator instructor initiated a “problem” into the scenario. The problem in my case was a washed out choke. You can see where I had the driller isolate the choke and we lined up on choke #2 to resume the scenario. You’ll also note that bottom hole pressure (black line) never dipped below the formation pressure (green line).

Minutes 105 to End: The rest of the simulation was simply adjusting the choke to account for the expansion of the gas from the well. This gets particularly challenging once the gas enters the choke lines and you really need to pay close attention to your kill and casing gauges to “check” any sudden increases and decreases to ensure you can maintain drill pipe pressure constant (which will ensure bottom hole pressure remains constant). Don’t make the same mistake that I made near the end of the scenario where I was so excited to have gotten through “most” of the scenario that I let bottom hole pressure drop below formation pressure. The scenario isn’t over until the instructor says it’s over! Fortunately for me the scenario was over before any additional influx came which could have affected my score.

The Equipment Exam: One of the biggest complaints I hear about the IWCF exam is that the equipment covered is outdated at best and even obsolete in some cases whether you’re taking the surface or subsea exam. This is th

th

th

especially true if you are fortunate enough to have started out offshore on a 4 , 5 , or 6 generation drilling rig. As I mentioned above, the most helpful thing for me was going through the e quipment sections in the study pack over and over. You eventually start picking up on things and making connections between the questions and the various pieces of e quipment (even if you’ve never seen or heard of the equipment before). As you learn more and more about the various equipment and their components, the next group of questions in the study pack become easier and easier. Approximately 25% of your test grade w ill be based on your ability to identify various components of well control equipment. Included in the study pack is a section with diagrams and drawings of most (if not all) of the equipment that you’ll likely encounter on your exam. Study the drawings and practice memorizing the various components. After a while, you can white out the labels on the equipment and test yourself to see if you can make it all the way through the equipment drawings without referring to an un-whited out version. When you can do this you’re ready for the exam. Because of the outdated equipment covered in the ICWF Level 2, Level 3 and Level 4 you’re best option for learning the material is to simply study as many of the questions in the study pack over and over

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IWCF Well Control Study Pack again. I cannot emphasize this enough, you really do learn about the equipment by studying the questions and it all starts to make sense after a while.

The P&P Exam: The P&P exam is probably the most difficult part of the test for most people I’ve talked to. It is also the longest. Level 3 candidates are given 2 hours to complete the exam and Level 4 candidates are given 2 ½ hours to complete the exam (not really sure why Level 4 gets more time). The P&P test covers a variety of skills and knowledge including the completion of a “Kill Sheet”, gauge interpretation, various drilling formula calculations, and “general” theory questions.

Practice the Kill Sheets: Another easy way to pad your grade on the IWCF Level 3 and Level 4 exam is to master filling out Kill Sheets. Kill sheets may seem intimidating at first but they’re actually quite easy to learn using the IWCF preformatted kill sheets that you’re allowed to use during the test. I’ve included a sample IWCF Kill Sheet Exercise below to show you how to fill out a typical Kill Sheet similar to what you’ll find on an IWCF Level 2, Level 3 or Level 4 exam: Example Kill Sheet Problems with Explanations:

Hole Size: 8-1/2 inch Hole Depth: 10450 (TVD/MD) Casing Shoe: 9-5/8 inch 7800 feet (TVD/MD) Internal Capacities:

Drill Pipe: 5 inch 0.0172 bbl/ft Heavy Weight Drill Pipe: 5 inch, length 723 feet, capacity 0.0088 bbl/ft Drill Collars: 6-1/2 x 2-13/16 inch, length 912 feet, capacity 0.0077 bbl/ft Choke Line: 2-1/2 inch ID, length 415 feet, capacity 0.0061 bbl/ft Marine Riser Length: 400 feet, capacity 0.3892 bbl/ft Annulus Capacities Between:

Drill Collars in Open Hole: 0.0292 bbl/ft Drill pipe/HWDP in Open Hole: 0.0447 bbl/ft Drill pipe/HWDP in Casing: 0.0478 bbl/ft Drill Pipe in Riser: 0.3638 bbl/ft Mud Pump Data:

Displacement at 98% volumetric efficiency 0.12 bbl/stroke Page 10 of 24


Slow pump rate data:

@45 SPM through the riser 780 psi @45 SPM through the choke line 900 psi Other relevant information:

Active surface volume 480 bbls Drill pipe closed end displacement 0.0254 bbl/ft Formation strength test data:

Surface leak-off pressure with 11 ppg mud 1900 psi Kick Data:

The well kicked at 10450 ft vertical depth Shut in drill pipe pressure 550 psi Shut in casing pressure 820 psi Pit gain 10 bbl Mud Density 11.5 ppg Completed IWCF Subsea Kill Sheet with Detailed Explanations : The following IWCF kill sheet has been completed with the above data:

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IWCF Well Control Study Pack Title Bar:

Remember to put your name and date on your sheet! Formation Strength Data:

For this section, you need to fill in the blocks using the data from the example kill sheet data pages above. For (A) you use the surface leak-off pressure from the “Formation Strength Test Data” section. For (B) you use the mud weight used during the surface leak-off pressure test from the same section. (C) is calculated by plugging (A) and (B) into the formula given to you in the box. Caution: If you do your calculations correctly, you’ll come up with 15.6844 ppg. Since mud weights are generally recorded to one decimal place (tenths) you’ll need to round 15.6844 ppg. However, you CAN’T round up because you will exceed the maximum allowable mud weight if you round up to 15.7. You must round down to 15.6 ppg to record the proper maximum allowable mud weight on the kill sheet.

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IWCF Well Control Study Pack Mud Pump Data and Slow Pump Rate Pressures:

The mud pump pressure section of the kill sheet is filled out almost entirely from information from the data sheet you’re given at the start of the test. The displacement per stroke of the pump is given to you as well as the slow pump rate data through the riser and the choke line. The only thing you’ll need to calculate in this section is the choke line friction loss which is simply the difference between the slow pump rate in the Choke Line (900) and the slow pump rate in the riser (780) = 120.

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IWCF Well Control Study Pack Current Well Data:

The information for this section is also pulled from the example kill sheet problem data. Marine Riser and Choke line length are given to you on the data sheet in the “Internal Capacities” section. Drilling mud weight is given to you in the “Kick Data” section. Casing size and measured depth (MD) and total vertical depth (TVD) are given to you at the very top of the kill sheet problem as well as the Hole Size and Hole Depth in MD and TVD. Caution: Remember the difference between Total Vertical Depth (TVD) and Measured Depth (MD). Measured depth is used when calculating volumes of fluids. TVD is used when calculating hydrostatic pressures. For example, you would use MD when calculating the volume

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IWCF Well Control Study Pack of fluid in the drill pipe but you would use TVD when calculating the hydrostatic pressure of the fluid in the drill pipe. Drill String Volume:

Calculating the drill string volume is as simple as plugging the length of your drill pipe, heavy weight drill pipe (hevi wall or HWDP) and drill collar into the drill string volume section. The capacities for all three are given to you in the problem in the “Internal Capacities” section. The only tricky thing is figuring out the drill pipe length. Since the length of Heavy Weight Drill Pipe and Drill Collars are given to you, all you need to do is subtract these two values from the total MD of the well to find the drill pipe length. In our example problem this would be 10,450 – 723 – 912 = 8815. Once you’ve plugged in the length of each section of drill string and the capacities you simply multiply each row to find the barrels of mud in each section and add them up to find the total drill string volume. After you find the total drill string volume (165 bbls in our example) you divide the bbls by the pump displacement per stroke (.12 bbls in our example) to figure out how many strokes of the mud pump are needed to completely displace the drill string (165/.12 = 1375). Once you’ve calculated the pump strokes needed to displace the riser, you divide the total strokes by the strokes per minute (SPM) of the mud pump to find out how much time would be needed to totally displace the volume of the drill string. Since our mud pump is pumping at 45 SPM we get 1375/45 spm = 30.5 minutes. Open Hole and Total Annulus/Chokeline Volume:

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IWCF Well Control Study Pack This section is filled out very similar to the section above except now you’re calculating the volume of mud in the open hole and casing minus the space taken up by the drill pipe, HWDP and Drill Collars. You’re given the length of the drill collars in the data sheet for the problem. To find the length of DP and HWDP in the uncased section of the well (the open hole section) you need to first find out how much open hole you have. You do this by subtracting the shoe TVD from the TVD of the entire well (10450-7800 = 2650 feet of open hole). Since 912 feet of this open hole is filled with drill collar, the rest (2650’ – 912’ = 1738’) is the length of drill pipe/HWDP in the hole. Total Well System Volume:

The total well system volume is calculated by adding values (D) and (I) from above which gives you 624.8 bbls. Divide this by your pump displacement per stoke (.12 bbls/stroke) to calculate the total strokes this represents (5207 strokes). From here divide this by the SPM you’re using (45 SPM) and this will tell you how long it will take to displace the Total Well System Volume with the mud pump (115.7 minutes). The active surface volume is given to you in the data sheet so you record it in this section and then divide it by the pump displacement (.12 bbls/stroke) to find out how many strokes it would take to displace the active surface volume. Total active fluid system volume is calculated by adding the previous two volumes and strokes together. Marine riser length is given to you on the data sheet in the “Internal Capacities” section as well as the annulus capacity with drill pipe in the riser in the “Annulus Capacities Between” section. Caution: Make sure you use the Riser capacity with drill pipe in the riser vs. the riser capacity that is listed in the “Internal Capacities” section which does not account for lost capacity due to the drill pipe being in the riser. Kick Data Section:

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IWCF Well Control Study Pack The kick data section is filled with information directly off the kill sheet data page in the “Kick Data” section. Kill Mud Weight:

Kill mud weight is calculated by plugging the numbers into the formula provided in the section. You’re already given Shut-in Drill Pipe Pressure (SIDPP), the TVD of the well and the current mud weight. All you need to do is plug the numbers in and calculate the mud weight needed to kill the well. If you’ve run the numbers correctly you should get a calculated kill weight mud of 12.5121 ppg. Kill mud is usually recorded to one decimal place so it would be natural to want to round this value down to 12.5 ppg. However you always round up kill mud weight to the nearest tenth so 12.5121 would be rounded to 12.6 ppg. The reason being if you made it 12.5 ppg, there wouldn’t be enough hydrostatic pressure created in the well to “kill” the well. Caution: Remember you always round up Kill Mud Weight to the nearest tenth and you always round down your Maximum Allowable Mud Weight to the nearest tenth. Initial Circulating Pressure:

You calculate initial circulating pressure (ICP) by simply adding the Dynamic Pressure Loss through the riser (780 in our example) to the Shut In Drill Pipe Pressure (550) given us 1330 PSI in our example. This is the pressure you expect to see on the drill pipe pressure gauge when first starting to circulate out the kick.

Final Circulating Pressure:

You calculate the final circulating pressure by dividing your new kill mud weight by the current mud weight and then multiply this value by the same dynamic pressure loss you used above.

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IWCF Well Control Study Pack This is the pressure you expect to see on the drill pipe gauge once all of the kill mud is pumped down the drill string and is starting to enter the annulus. PSI Drop Per 100 Strokes:

This section is where you calculate the pressure drop per every 100 strokes of the mud pump as you start pumping heavier kill weight mud down the hole. All you do is find the difference between the ICP and FCP that you calculated above and then plug that number into the next formula where you multiply it by 100 and divide it by the (E) which is the number of strokes needed to displace the drill sting. When you start pumping kill weight mud down the hole you need to be at or above the ICP to ensure you don’t let more formation fluids into the hole. As the drill string is displaced with the heavier weight mud (and therefore creating more hydrostatic pressure) you’ll need to adjust the drill pipe pressure down using the choke to keep the bottom hole pressure constant. In other words, for every 100 strokes you pump with your mud pumps the drill pipe pressure should drop 34.5 psi (based on our example kill sheet). Pressure per Stroke Table: Once you’ve calculated your ICP, FCP and pressure drop per 100 strokes, you can fill out the strokes/pressure table (step down chart) to the right. In the left hand column start at 0 and increase in 100 stroke increments until you get to the total number of strokes needed to displace the drill string (1375 in our example). On the right hand side start with your ICP and decrease the pressure by 34.5 psi (calculated in the previous section) for every 100 strokes until you get to the FCP. It looks complicated but it really isn’t after you’ve done it a couple times.

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IWCF Well Control Study Pack Graphing the Pressure Drop from ICP to FCP:

The last part of the ICWF Kill Sheet is plotting out the pressure drop per 100 strokes as you go from ICP to FCP when pumping kill weight mud down the drill string. It is usually not required on an actual IWCF exam but in case you wanted to know what it might look like, here you go!

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Understanding the Formulas: One nice thing about the IWCF IWC F exam is that you’ll be given a copy of the IWCF formula sheet to use as part of your test. Although this is convenient, I’ll warn you not to get over confident about taking the exam. At first, I thought that as long as I had the formula sheet available I didn’t really need to study the problems. The truth is, the more you understand the formulas and when to use them, the better off you’ll be come test day. The IWCF exam almost always gives you WAY more information than you need to answer the question. This is why it is so important to understand exact ly what the question is asking and which specific formula is needed to answer the question. There will be many instances when you’ll need to refer to two or more formulas to get the correct answer. Likewise, there will be t imes when you’re given a ridiculous amount of information and the answer is actually given to you as part of the problem. The more problems you go through, the more you will be exposed to the “tricky” problems and the better prepared you’ll be for test day. Try solving as many problems as you can without without referring to the formula sheet. Try to think your way through what the problem is asking and what you actually need to solve for to get t he answer.

For example, if you’re tripping pipe out “wet” and you want to know what the bottom hole pressure drop is per stand of drill pipe, try to think your way through what you nee d to solve for… In this case you’re solving for t hree things:

First you need to figure o ut the volume of mud being displaced by the me tal in each stand of drill pipe that is being removed from the casing or riser (depending on if you’re on a surface or subsea well). Since you’re pulling it “wet” you’ll also need to account for the internal capacity of the drill pipe (full of mud) being removed as well (not just the metal displacement). t he riser or casing will drop per Secondly, you’ll need to figure out how far the level of mud in the stand as each stand of drill pipe is pulled o ut (since you’re losing the metal displacement volume and the internal capacity volume of the pipe, the mud level in the casing or riser will drop).

Finally, you’ll need to calculate what the resultant pressure drop is per stand due t o the dropping fluid level in the riser or casing. For example, a 10 ft drop in fluid level means a ten ft loss of hydrostatic pressure. The good news is the formula sheet provided to you during the IWCF exam combines all three of these calculations into one simple formula. The bad news is if you don’t understand what what is actually going on in the formula there is a good chance that you won’t be able to adapt when a question is asked that isn’t exactly addressed by one of the specific formulas (which happens quite a bit on the IWCF exam).

Page 20 of 24


Understanding U-Tube, Bottom Hole and Formation Pressure: Another fundamental concept you’ll need to master to do well on the IWCF exam is understanding UTube balance, formation pressure and bottom hole pressure. pressure is the actual actual pressure of Formation Pressure vs. Bottom Hole Pressure : Remember, formation pressure the formation you are drilling into. Bottom hole pressure is the pressure at the bottom of the well that is created by the hydrostatic weight of the mud in the well plus any additional forces created by annular friction from circulating mud through the well. The goal is to maintain bottom hole pressure above formation pressure to prevent formation fluids from entering the well (i.e. taking taking a kick or influx). On the flipside, if too much bottom hole pressure is applied to the formation you could fracture the well which could allow drilling fluids fluids to enter the formation (lost circulation). In turn, this would cause the mud level in your well to drop w hich could eventually lead to a drop in hydrostatic pressure which could allow a larger influx into the wellbore. how the u-tube is always balanced balanced even U-Tube: You need to understand how though you may see different pressure r eadings on the drill pipe and pressure gauges. In almost every IWCF well control situation, situation, the casing gauge reads higher than the drill pipe pressure. This is because the lighter “influx” (formation fluid) on the casing side of the U-Tube is lighter and therefore exerting less pressure down on the bottom hole than the “clean” drilling mud that is in the drill pipe side of the U-Tube. This loss of hydrostatic pressure pressure is compensated by the increase in casing pressure. In the example to the right, you can see that t hat the drill string is full of clean drilling mud even through there is an influx in the well. Because you have a known column of fluid in the drill pipe you can figure o ut the formation pressure by simply adding the drill pipe reading to the hydrostatic pressure of the drilling mud in the drill pipe. You can’t do this with the casing gauge because you don’t know the density of the influx in the annulus of the well (but it will almost always be less than the drilling mud). The additional 200 psi on the casing gauge is the additional pressure needed to keep the U-Tube balanced between the casing side and the drill pipe pressure side. Understanding this concept is very beneficial when you start studying studying the practice questions. It is especially helpful when determining what happens to casing pressure, drill pipe pressure and bottom hole pressure when hydraulic changes are made w hen circulating out a kick (plugged bit, change in pump speed, washed out choke, plugged choke, etc.). It is equally helpful for P&P questions such as calculating the pressure at the casing shoe when there are several sever al different layers of fluid in the hydrostatic column. As I mentioned with the formulas above, the more you can think your way through a problem and understand what is being asked, the e asier it will be for you to answer the question.

Page 21 of 24


Mastering IWCF Gauge Problems: Another area where you can score huge points points on the IWCF exam is on the gauge problems. I had probably 10 of these problems on my IWCF Level 4 exam and they made up a very large percentage of my final score. When I first started practicing them, most of them made very little sense to me what so ever. As I continued to review the study material and gained a better idea of the equipment and the relationships of bottom hole pressure, formation pressure and the U-Tube, the gauge problems started to become easier and easier. Here are some IWCF gauge problem tips that will help you master the gauge problems on your IWCF exam.

When answering a gauge problem, you’ll need to look at all of the information that is provided to you in the question. While you may get a stand alone gauge question, in most cases you’ll get a series of gauge questions that are all connected together in sequence in which you are given a completed kill sheet and corresponding well data to help interpret the gauges. You probably won’t do any better than I did at first when you start going through these questions, however, once you start going through some o f the sample IWCF questions and do a few kill sheets, it all starts to come c ome together.

IWCF Gauge Problem Tips :

Page 22 of 24

IWCF Well Control Study Pack 1) Pump Rate: Always look at the mud pump rate. If you’re supposed to be pumping at 30 SPM and the gauge shows that you ar e pumping above or below that, you’re pretty much guaranteed that the answer to the question is to either speed up or slow down the pump speed to the speed used in the kill sheet calculations. 2) Pressure too High: On the IWCF exam, your drill pipe pressure gauges are considered to be too “high” if they are 70 psi above what they’re supposed to be for that particular situation. For example, if you’re starting to circulate out a kick in the well and your “actual” initial circulating pressure is 71 psi more than your calculated ICP then the correct answer is most likely going to be to open the choke slightly to bring the drill pipe pressure back down to range. 3) Pressure too Low: On the other hand, if at anytime your drill pipe pressure is below where it is supposed to be (even by 1 psi), the correct answer is most likely to close the choke slightly to bring your drill pipe and/or casing pressures back up. For example, if you’ve pumped 700 strokes and your pressure chart says you’re supposed to be at 1010 psi on the drill pipe gauge but your actual drill pipe pressure gauge reads 100 9 psi, you should close the choke ever so slightly to bring the pressure back up. 4) “Dramatic” Key Words : If the gauge question includes verbiage such as “hoses begin shaking violently” or “jumping wildly”, etc. then the corr ect answer is likely to shut the well in and reassess. 5) Everything is “OK”: There are also many instances when the correct answer is “everything is OK”. This occurs when the pump rate, casing pressure, drill pipe pressure, etc. are all were they are supposed to be. On my test, 3 of the 10 correct answers on my IWCF Level 4 exam where “everything is OK”.

General Theory and Knowledge Questions: Another large component of the P&P exam is general theory and knowledge questions about well control. These could be questions ranging from the difference between the various well kill methods (Drillers, Weight and Wait, Volumetric, Lubricate and Bleed, Bullheading, etc.) to what could cause formations to become abnormally pressurized. As with the equipment questions, the best w ay I’ve found to prepare for theory questions is to keep reviewing the various sample IWCF questions in the study pack. As I’ve already mentioned a couple of times, once you review the questions a couple times the questions start to connect and then you can make educated guesses on the next batch of questions based on what you’ve learned from the previous questions. On test day, I had a ton of theory questions that I had never seen before. However, because I had learned so much from studying the other questions (and asking questions from people during the class about things I didn’t quite understand) I was able to correctly guess what the answer was to the questions on the exam.

Page 23 of 24


Good Luck! As mentioned above, there are three exams that you’ll take as part of your IWCF Level 3 and/or Level 4 certification (Simulator, Equipment, and P&P). If you’ve worked your way through the study material at the end of this guide then you should be in really good shape by the first day of class. If you arrive to class unprepared (especially if this is your f irst IWCF well control course) you’re going to be struggling to keep up. The instructor has a lot of material to cover in the week leading up to the exam and you’re going to fall behind very quickly to stay on top of the material. Remember, the more you prepare, the less stressful the examination process will be! Good luck with your IWCF exam, I hope this guide has been helpful!

Page 24 of 24

IWCF Equipment Diagrams

1. Flex (ball) joint 2. Flexible choke/kill line 3. BOP Control lines 4. Subsea accumulator bottles 5. Annular Preventer 6. Control Pod 7. LMRP Connector

Typical Koomey Blowout Preventer Control System 1.

Customer Air Supply: Normal air supply is at 125 psi. Higher air pressure may require a reducing valve for No. 88660 air pumps.

2.

Air Lubricator: Located on the air inlet line to the air operated pumps. Use SAE 10 lubricating oil.

3.

Bypass Valve: To automatic hydro-pneumatic pressure switch. When pressures higher than the normal 3,000 psi are required, open this valve. Keep closed at all other times.

4.

Automatic Hydro-Pneumatic Pressure Switch: Pressure switch is set at 2,900 psi cut-out when

air and electric pumps are used. Otherwise, set at 3,000 psi for air pumps alone. Adjustable. 5.

Air Shut-Off Valves: Manually operated – to open or close the air supply to the air operated hydraulic pumps.

6.

Air Operated Hydraulic Pumps: Normal operating air pressure is 125 psi for No. 88660 pumps.

7.

Suction Shut-Off Valve: Manually operated. Keep normally open. One for each air operated hydraulic pump suction line.

8.

Suction Strainer: One for each air operated hydraulic pump suction line. Has removable screens.

9.

Check Valve: One for each air operated hydraulic pump delivery line.

10.

Electric Motor Driven Triplex or Duplex Pump Assembly.

11.

Automatic Hydro-Electric Pressure Switch: Pressure switch is set at 3,000 psi cut-out and 250 psi cut-in differential. Adjustable.

12.

Electric Motor Starter (Automatic): Automatically starts or stops the electric motor driving the triplex or duplex pump. Works in conjunction with the automatic hydro-electri c pressure switch.

13.

Suction Shut-Off Valve: Manually operated, normally open. Located in the suction line of the triplex or duplex pump.

14.

Suction Strainer: Located in the suction line of the triplex or duplex pump.

15.

Check Valve: Located in the delivery line of the triplex or duplex pump.

16.

Accumulator Shut-Off Valve: Manually opened. Normally in open position when the unit is in operation. Close when testing or skidding rig or when applying pressure over 3,000 psi to open side of ram preventers. OPEN WHEN TEST IS COMPLETED.

17.

Accumulators: Check nitrogen precharge in accumulator system every 30 days. Nitrogen precharge should be 1,000 psi ± 10%. CAUTION: Use NITROGEN when adding to precharge. Other gases and air may cause fire and/or explosion.

18.

Accumulator Relief Valve: Valve set to relieve at 3,500 psi.

19.

Fluid Strainer: Located on the inlet side of the pressure reducing and regulating valves.

20.

Koomey Pressure Reducing and Regulating Valve: Manually operated. Adjust to the required continuous operating pressure of ram type BOP’s. Check Valve: Located on the delivery side of the pressure reducing and regulating valve.

21. 22.

4-Way Valves: With air cylinder operators for remote operation from the control panels. Keep in open position when controls are not in use.

23.

Bypass Valve: Keep closed unless 3,000 psi (or more) is required on ram type BOP’s.

24.

Manifold Relief Valve: Valve set to relieve at 5,500 psi.

25.

Hydraulic Bleeder Valve: Manually operated – normally closed. NOTE: This valve should be kept OPEN when precharging the accumulator bottles.

Typical Koomey Blowout Preventer Control System (cont’d) 26.

27.

Panel-Unit Selector: Manual 3-way valve. Used to allow pilot air pressure to the air operated

Koomey pressure reducing and regulating valve, either from the air regulator on the unit or from the air regulator on the control panel. Koomey Pressure Reducing and Regulating Valve – Air Operated: Reduces the accumulator pressure to the required annular operating pressure. Pressure can be varied for stripping operations. Maximum downstream pressure for the annular preventer should not be exceeded.

28.

Accumulator Pressure Gauge

29.

Manifold Pressure Gauge

30.

Annular Preventer Pressure Gauge

31.

Pneumatic Pressure Transmitter for Accumulator Pressure

32.

Pneumatic Pressure Transmitter for Manifold Pressure

33.

Pneumatic Pressure Transmitter for Annular Preventer Pressure

34.

Air Filter: Located on the supply line to the air regulators.

35.

Air Regulator for Koomey Pressure Reducing and Regulating Valve – Air Operated.

36.

Air Regulator for Pneumatic Transmitter for Bag Pressure, Air Regulator Controls for Items 31, 32, 33, Pneumatic Pressure Transmitters: Normal pressure setting on regulators for pneumatic pressure transmitters is 12 to 15 psi. Calibrate the receiver gauges located on the panel to hydraulic pressure gauge on the unit in this manner. a.

Hydraulic pressure gauge should be at the highest operating range of the system; i.e., accumulator and manifold pressure gauges are at 3,000 psi and the annul ar preventer gauge is at 1,500 psi.

b.

Increase or decrease air pressure, using the air regulators provided, to calibrate panel gauge to hydraulic pressure gauge on the unit.

37.

Air Junction Box: To connect the air lines on the unit to the air lines coming from the remote control panels through air cable.

38.

Fluid Level Indicator

39.

Hydraulic Fluid Fill Hole:

40.

Rig Skid and Test Line – 4 Way Valve: Manually operated, open center. Accumulator Position: Valve handle to the right position. Test Position: Valve handle to the center position. Skid Position: Valve position to the left position. CAUTION: Return valve handle to accumulator position after skidding or testing.

41.

Check Valve: Located on the outlet line from the rig skid and test valve and inlet line to the

accumulators. 42.

Rig Skid Relief Valve: Located on the rig skid line.

43.

Rig Skid Customer Connection

44.

Test Line Customer Connection

45.

Rig Skid Return Customer’s Connection Inspection Plug

46.

    1.

Calculate volume of nitrogen in a 10-gallon cylinder with a 1,000 psi nitrogen precharge that has been pressured up to 3,000 psi. (a) (b) (c) (d)

2.

Calculate the volume of nitrogen in a 10-gallon cylinder with a 1,000 psi nitrogen precharge that now has 1,200 psi. (a) (b) (c) (d)

3.

6.67 gal 3.33 gal 8.33 gal 1.67 gal

Calculate the amount of hydraulic fluid that has been used in a 10-gallon cylinder with a 1,000 psi nitrogen precharge that was charged up to 3,000 psi after it has dropped down to the 1,200 psi minimum pressure. (a) (b) (c) (d)

4.

6.67 gal 3.33 gal 8.33 gal 1.67 gal

6.67 gal 5.00 gal 8.33 gal 1.67 gal

What is the total amount of hydraulic fluid needed to close, open and close the following BOP system? One Annular: 16 gallons to close; 15.8 gallons to open Three Rams: 8 gallons to close each; 7.5 gallons to open each Two HCR Valves: 2 gallons to open; 2 gallons to close (a) 86.3 gal (b) 51.3 gal (c) 98.8 gal (d) 130.3 gal

5.

The driller closes the annular preventer. Which two pressure gauges will show fluctuation on the accumulator unit? (Two Answers) (a) (b) (c) (d)

6.

Accumulator gauge Manifold pressure gauge Annular pressure gauge Air pressure gauge

The Rig Air Pressure drops to 10 psi. You are about to close the well from the remote panel. Which of the following statements is true? (a) Only the annular preventer could be operated. (b) Only the blind/shear rams could be operated. (c) Only the drill pipe rams could be operated. (d) No BOP function could be operated from the remote panel.

7.

What is used in the accumulator as a pre-charge material? (a) Oxygen (b) Hydrogen (c) Nitrogen (d) Water

8.

All BOP and wellhead equipment must be sized to: (a) (b) (c) (d)

9.

Slightly larger than the largest piece of drilling equipment to be lowered through the stack. Same size as the first casing shoe Whatever size the Company Man asks for Comply with safety regulations.

What is the normal closing pressure range for pipe rams? (a) 600 – 900 psi (b) 1,200 – 1,500 psi (c) 1,500 – 1,800 psi (d) 1,500 – 3,000 psi

10.

What is the normal closing pressure range for 13 ⅝ʺ Hydril GK Annular preventer? (a) 600 – 900 psi (b) 1,200 – 1,500 psi (c) 1,500 – 1,800 psi (d) 1,500 – 3,000 psi

11.

How should shear rams be used? (a) (b) (c) (d)

12.

What is the normal accumulator pressure used in a 3,000 psi BOP system? (a) (b) (c) (d)

13.

To close well in with drill pipe in the hole. To shut off shallow kick. To control a blowout through the drill string. To hang off on drill string.

1,500 psi 2,000 psi 3,000 psi 1,000 psi

What is the normal manifold pressure used in a 3,000 psi BOP control system? (a) (b) (c) (d)

1,500 psi 2,000 psi 3,000 psi 1,000 psi

14.

What is the normal annular pressure used in a 3,000 psi BOP control system? (a) 3,000 psi (b) 600 psi to 1,500 psi (c) 2,000 psi (d) 500 psi

15.

You are drilling ahead and the BOP control system reads as follows.

(a) (b) (c) (d) (e) 16.

Everything is okay. There is a leak in the hydraulic system. There is probably a malfunction in the pressure transducer assembly. There could be a malfunction in the hydraulic regulator. Could be either c or d.


(a) (b) (c) (d)

Everything is okay. There is a leak in the hydraulic system. There is a malfunction in the pressure transducer assembly. There is a malfunction in the hydraulic regulator.

17.


(a) (b) (c) (d) 18.

What is the unit/remote switch used for on the Driller’s BOP Panel? (a) (b) (c) (d)

19.

To bypass the Driller’s Panel and go to the remote panel. To bypass the regulated hydraulic pressure and use the accumulator pressure. To bypass the Driller’s Panel with air pressure. To bypass all BOP functions and operate the blind/shear ram.

Indicator light does not operate but BOP gauges fall and rise back up to the normal once the BOP is operated. (a) (b) (c) (d)

21.

To check if the read back gauges are working properly. To increase and decrease the regulator. To set regulator control to the Driller’s Panel in the master control unit. To isolate air on the Driller’s Panel.

What is the bypass valve used for on the Driller’s BOP control panel? (a) (b) (c) (d)

20.

Everything is okay. There is a leak in the hydraulic system. There is a malfunction in the pressure transducer assembly. There is a malfunction in the hydraulic regulator.

4-way valve failed to shift. Indicator light failed, possible blown fuse. Hydraulic leak in control lines. Blockage in BOP control lines.

Indicator light operates but BOP gauges remain constant. Identify the most probable cause. (a) (b) (c) (d)

4-way valve failed to shift. Indicator light failed, possible blown fuse. Hydraulic leak in control lines. Blockage in BOP control lines.

22.

Indicator light operates but BOP gauges fall and do not come back up. Identify the most probable cause. (a) (b) (c) (d)

23.

Indicator light does not operate and BOP gauges do not drop. Identify the most probable cause. (a) (b) (c) (d)

24.

4-way valve failed to shift. Indicator light failed, possible blown fuse. Hydraulic leak in control lines. Blockage in BOP control lines

4-way valve failed to shift. Indicator light failed, possible blown fuse. Air pressure lost to panel. Blockage in BOP control lines

What position is the 4-way valve in on the BOP master control panel while drilling? (a) Open (b) Closed (c) Neutral or block (d) Open or closed

25.

You are testing the BOP stack with a test plug. The side outlet valves below the plug should be kept in the open position. (a) (b) (c) (d) (e)

26.

Because the test will create extreme hook loads. Because of potential damage to the casing and open hole. Otherwise reverse circulating will be needed to release test plug. To check for a leaking test plug. Both b and d are correct.

Under what circumstances would a “cup-type” tester be used in preference to a “test plug” when testing a BOP stack? (a) There is no difference; they are interchangeable. (b) When you are required to test either casing head outlets and casing to wellhead seals. (c) To test stack without applying excessive pressure to wellhead and casing.

27.

You are drilling in an area where local regulations require the BOP equipment must be rated so that maximum anticipated formation pressure does not exceed 75% of the BOP equipment pressure rating. What is the minimum acceptable rating for equipment to be used in normally pressured formation to 8,000 feet TVD? (The normal pressure gradient is 0.465 psi/ft.) (a) 2,000 psi (b) 3,000 psi (c) 5,000 psi (d) 10,000 psi (e) 15,000 psi

28.

When an operation is made to open or close the annular, which gauges would you expect to see a reduction in pressure? (Two Answers) (a) (b) (c) (d)

Air Pressure Accumulator Manifold Annular

Use the diagram above to answer questions 29-38. 29.

Identify the triplex pump assembly. (a) 6 (b) 10 (c) 11 (d) 12

30.

Identify the check valve for the triplex pump. (a) 5 (b) 7 (c) 8 (d) 15

31.

Identify the accumulators. (a) 6 (b) 17 (c) 18 (d) 12

32.

Identify the four-way valves. (a) (b) (c) (d)

33.

21 22 23 24

Identify the accumulator pressure gauge. (a) 28 (b) 29 (c) 30

34.

Identify the manifold pressure gauge. (a) 28 (b) 29 (c) 30

35.

Identify the regulator for the manifold, accumulator and annular pressure transmitters. (a) (b) (c) (d)

36.

31 32 33 36

Identify the air pump. (a) 4 (b) 6 (c) 10 (d) 12

37.

Identify the air junction box. (a) 1 (b) 12 (c) 34 (d) 39

38.

Identify the suction strainer for the air pumps. (a) 8 (b) 9 (c) 13 (d) 14

39.

Pipe rams have been functioned from the Driller’s Remote Panel. The accumulator and manifold pressure have dropped down and stabilized and are not rising. Which of the following may be the cause of the problem? (a) (b) (c) (d) (e)

40.

After connecting the open and closed hoses to the stack, you should first: (a) (b) (c) (d)

41.

Hydraulic closing line to BOP is leaking. 4-way valve has not actuated. Charge pumps are not working A & C are correct A, B, and C are correct.

Take a slow circulating rate. Drain accumulator bottles to check precharge. Function test all items on stack. Place all function to neutral (block) position to charge up the hose.

The Master control valve on the Driller’s Remote BOP control panel must be depressed for five seconds then released before operating a BOP function. (a) True (b) False

42.

The Master Control valve on the Driller’s Remote BOP control panel must be depressed while BOP functions are operated. (a) True (b) False

43.

The Master Control valve on an air operated panel allows air pressure to go to each function in preparation for operating the function. (a) True (b) False

44.

If you operate a function on the Driller’s Remote BOP control panel without operating the master control valve, the function will not work. (a) True (b) False

45.

What is the API closing time for an annular over twenty inches on a surface BOP stack? (a) (b) (c) (d)

60 sec 30 sec 45 sec 75 sec

46.

What is the API closing time for a ram preventer on a surface BOP stack? (a) (b) (c) (d)

47.

60 sec 30 sec 45 sec 75 sec

What is meant by API closing ratio between preventer control pressure and wellbore pressure? (a) Time to close the preventer (b) Wellbore pressure versus preventer closing pressure (c) Size of element to use.

48.

If gauge #1 on remote panel reads 0 psi, which of the following statements are true? (a) Annular preventer can be operated from remote panel. (b) Choke and Kill lines can still be operated. (c) No stack function can be operated from remote. (d) All functions operate remotely.

49.

Identify the body of the Cameron Type U Pipe Ram Preventer. (a) 1 (b) 5 (c) 12

50.

Identify the operating cylinder of the Cameron Type U Pipe Ram. (a) 7 (b) 8 (c) 9

51.

Identify the bonnet of the Cameron Type U Pipe Ram. (a) 4 (b) 5 (c) 6

52.

Identify the operating piston of the Cameron Type U Pipe Ram. (a) 7 (b) 9 (c) 11

53.

Identify the lower ram assembly of the Cameron Type U Blind Shear Ram. (a) 1 (b) 7 (c) 4 and 5

54.

Identify the top seal of the Cameron Type U Blind Shear Ram. (a) 1 (b) 3 (c) 6

55.

Identify the face packer of the Cameron Type U Blind Shear Ram. (a) 3 (b) 4 (c) 5

56.

Identify the upper ram assembly of the Cameron Type U Blind Shear Ram. (a) 1 (b) 3 (c) 7

57.

Identify the side packers of the Cameron Type U Blind Shear Ram. (a) 3 (b) 4 and 5 (c) 7

58.

Identify the opening chamber of the Hydril GK Annular Preventer. (a) (b) (c) (d)

59.

Identify the closing chamber of the Hydril GK Annular Preventer. (a) (b) (c) (d)

60.

1 2 3 9

Identify the piston of the Hydril GK Annular Preventer. (a) (b) (c) (d)

63.

2 3 4 5

Identify the travel indicator of the Hydril GK Annular Preventer. (a) (b) (c) (d)

62.

5 6 7 8

Identify the packing unit of the Hydril GK Annular Preventer. (a) (b) (c) (d)

61.

1 5 6 8

4 5 7 8

Identify the seals of the Hydril GK Annular Preventer. (a) (b) (c) (d)

1 3 8 9

64.

With the drill string in hole and the well shut in with 5 ʺ pipe ram, can the blind shear ram be repaired? (Use top diagram at right.) (a) Yes (b) No

65.

With no drill string in hole and well shut in with the blind shear ram, can repairs be made to the blind shear ram? (Use top diagram at right.) (a) Yes (b) No

66.

With drill string in hole and well shut in with annular, can the blind shear ram be changed to a 5ʺ pipe ram? (Use top diagram at right.) (a) Yes (b) No

67.

With pipe in hole, can the blind shear ram be repaired with well shut in with the lower 5ʺ pipe ram? (Use bottom diagram at right.) (a) Yes (b) No

68.

Can the well be circulated and killed when the upper 5 ʺ pipe ram is closed and drill string is in hole? (Use bottom diagram at right.) (a) Yes (b) No

69.

Would it be a good drilling practice to circulate and kill the well with the lower 5 ʺ pipe ram closed and the drill string in the hole? (Use bottom diagram at right.) (a) Yes (b) No

70.

Can the manual valve on the choke line be repaired if the well is shut in with the blind shear ram and no drill string in the hole? (Use bottom diagram at right.) (a) Yes (b) No

71.

Can the well be killed with drill string in hole and the well shut in with 5 pipe ram? (Use top diagram at right.)

ʺ

(a) Yes (b) No 72.

Can the annular be repaired with no drill string in hole and well closed in with the blind shear ram? (Use top diagram at right.) (a) Yes (b) No

73.

Can the blind shear ram be changed to a 5 ʺ pipe ram with the 5 ʺ pipe ram closed and the drill string in the hole? (Use top diagram at right.) (a) Yes (b) No

74.

Could the HCR valve on the choke line be repaired if the well was shut in with the annular and drill string is in hole? (a) Yes (b) No

75.

Calculate how much pressure would be required to close a ram preventer for a well bore pressure of 11,000 psi with a closing ratio of 10.56:1. (a) 142 psi (b) 1,042 psi (c) 1,500 psi (d) 3,000 psi

76.

From the bottom to top of BOP stack is made up of Ram 1, Spool and choke, Ram 2, and Annular. Can the well be killed with Ram 1 closed? (See Diagram at top right.) (a) Yes (b) No

77.

From the bottom to top of BOP stack is made up of Ram 1, Spool and choke, Ram 2, and Annular. Can the well be killed with Ram 2 closed and Ram 1 open? (See Diagram at top right.) (a) Yes (b) No

78.

From the bottom to top of BOP stack is made up of Ram 1, Spool and choke, Ram 2, and Annular. Can the annular be repaired with Ram 1 closed? (See Diagram at top right.) (a) Yes (b) No

79.

From the bottom to top of BOP stack is made up of Ram 1, Spool and choke, Ram 2, and Annular. Is it possible to reverse circulate with Ram 2 closed? (See Diagram at top right.) (a) Yes (b) No

80.

From the bottom to top of BOP stack is made up of Ram 1, Spool and choke, Ram 2, and Annular. Can the stack diverter be used with Ram 1 closed? (See Diagram at top right.) (a) Yes (b) No

81.

Which dimension should dictate the diameter of a ram and annular when open. (a) Outside diameter of DC (b) Outside diameter of last casing string (c) Bore of uppermost casing head

82.

When should the BOP be tested? (a) When installed. (b) Before drilling out after each string of casing is set. (c) Following BOP repair. (d) All the above. (e) None of the above.

83.

Which of the following is true concerning the ram packer element? (a) (b) (c) (d)

84.

Ram packer should normally be checked and if worn, changed whenever the bonnet is opened. Motion reversal can cause extensive wear. Closing a pipe ram on an open hole may damage the element. All of the above are true.

The kill line should enter the stack so that: (a) The well can be killed if the pipe ram is being used. (b) The well can be killed if the blind ram is used. (c) Both of the above are true. (d) None of the above are true.

85.

During the weekly pressure test of BOPs, a weep hole on one of the ram preventers is found leaking. What action should be taken? (a) (b) (c) (d)

86.

Everything is okay; it is normal to have a small leak. Put grease in weep hole and carry on. Stop operation, as main seal has failed, and repair failure. The rubber seals and ram packer are adjusting so this is a normal sign of wear.

The annular preventer is sitting in the set back area prior to nippling up on a well. What should the annular preventer be tested to before nippling up? (a) 70% of rated working pressure. (b) 50% of rated working pressure. (c) 100% of rated working pressure. (d) 125% of rated working pressure.

87.

Which piece of equipment can be used to hang off the DP in an emergency? (a) (b) (c) (d)

88.

Annular Blind shear ram Pipe ram Diverter element

What is the rated working pressure for BOP equipment according to API STD 53? (a) (b) (c) (d) (e)

Maximum anticipated bottom-hole pressure. Maximum anticipated pore pressure. Maximum anticipated surface pressure. Maximum anticipated dynamic choke pressure. Maximum anticipated MAASP.

89.

What is the API STD 53 recommendation for BOP pressure testing? (Three answers) (a) After circulating out a gas kick. (b) After any change of a component in the BOP. (c) Not to exceed 21 days. (d) After setting casing string. (e) Prior to entering a known pressure transition zone.

90.

What is the maximum allowable closing time for a 21¼ ʺ ram on a surface stack according to API STD 53? (a) Less than 30 sec. (b) Less than 45 sec (c) Less than 2 min

91.

While testing the pipe rams, it is noticed that the weep hole on one of the preventer bonnets is leaking. What action should be taken? (a) The ram packing elements on the ram body are worn out; secure the well and replace immediately. (b) The primary ram shaft seal is leaking; secure the well and replace immediately. (c) The weep hole checks the operating chamber. If the amount of leaking fluid is small, no action is required until next scheduled maintenance. (d) Energize emergency packing ring. If leak stops, leave it till next scheduled maintenance.

92.

What functions on a BOP stack is supplied from the annular pressure regulator? (a) Rams and hydraulically operated choke and kill line valves. (b) Annular preventer only. (c) Annular BOP and hydraulically operated choke and kill line valves. (d) Ram, annular preventer, and hydraulically operated choke and kill line valves. (e) No function is supplied with this pressure. The valves shown on the gauge only indicated the maximum allowable working pressure for the annular preventer in use.

93.

What is the most common action (and considered a good practice) that should be taken after connecting the open and closed hydraulic lines to a surface installed BOP stack? (a) (b) (c) (d)

Drain the accumulator cylinder and check nitrogen pre-charge pressure. Function test all items on the BOP stack. Place all functions in neutral position and start pressure testing the BOP stack. Perform accumulator unit pump capacity test.

IWCF E   1.

Before a 10,000 psi preventer is initially accepted and brought into the field for work, it must have a body shell test of: (a) (b) (c) (d)

2.

100% of its rated working pressure. 125% of its rated working pressure. 150% of its rated working pressure. 200% of its rated working pressure.

Identify the release rod on the diagram of the Inside Blow Out Preventer (IBOP) at right. (a) 1 (b) 4 (c) 7

3.

Identify the valve seat on the diagram of the IBOP at right. (a) 5 (b) 6 (c) 7

4.

Identify the valve spring on the diagram of the IBOP right.

at

(a) 3 (b) 4 (c) 7 5.

Identify the upper body on the diagram of the IBOP (above right). (a) 2 (b) 5 (c) 8

6.

Identify the rod lock screw on the IBOP (above right). (a) 1 (b) 3 (c) 4

7.

Is reverse circulating an advantage or disadvantage if a non-return valve is being used in the DS? (a) Advantage (b) Disadvantage

8.

Is reading shut-in drill pipe pressure an advantage or disadvantage if a non-return valve is being used in the drill string? (a) Advantage (b) Disadvantage

9.

Is preventing back flow up the drill string an advantage or disadvantage if a nonreturn valve is being used in the drill string? (a) Advantage (b) Disadvantage

10.

Is surge pressure during stripping a consideration due to a non-return valve being used in the drill string? (a) Yes (b) No

11.

Is performing wire line operations below the non-return valve an advantage or disadvantage if a non-return valve is being used in the drill string? (a) Advantage (b) Disadvantage

12.

The API STD 53 states that blowout preventers must be tested after setting casing. What are two other times that are recommended? (Two Answers) (a) After circulating out a kick (b) Not to exceed 21 days (c) After preventer repairs (d) After every 1000 feet drilled (e) Prior to entering a known pressure transition zone

13.

What is meant by the API term RX 54 for a gasket? (Two Answers) (a) (b) (c) (d)

14.

Shut-in drill pipe pressure will not be registered on the gauge if one of the following is used. (a) (b) (c) (d)

15.

Type Size Manufacturer Serial #

Internal float valve 10,000 psi choke Annular preventer Survey baffle plate

Identify the valve ball from the diagram to the right. (a) 1 (b) 2 (c) 4 (d) 15

16.

Identify the Stop Ring from the diagram. (a) 1 (b) 2 (c) 14 (d) 15

17.

Identify the Check Valve Assembly from the diagram. (a) (b) (c) (d)

18.

1 2 3 7

Identify the Packer from the diagram above right. (a) 2 (b) 4 (c) 13 (d) 14

19.

Identify the Body of the Landing Sub from the diagram above right. (a) 1 (b) 2 (c) 13 (d) 14

20.

Identify the Slip Body Assembly from the diagram above right. (a) 7 (b) 8 (c) 9 (d) 10

21.

You are going to trip out of the well and your safety valve has a 4½ ʺ IF connection. There are 8 ʺ drill collars in the drill string. What cross-over would you have on the drill floor if you had to shut in the well, when 8 ʺ drill collars are in slips at the rotary table? 8 ʺ drill collars has 6 ⅝ reg. connections. (a) (b) (c) (d)

4½ʺ IF box and 7 ⅝ʺ regular pin 4½ʺ IF pin and 6 ⅝ʺ regular box 4½ʺ IF box and 6 ⅝ʺ regular pin 4½ʺ IF pin and 7 ⅝ʺ regular box

22.

A test plug is in the hole while testing the preventers. Why is it important to have underneath the test plug vented to surface? (a) (b) (c) (d)

23.

Identify the ball in the diagram of the kelly cock at right. (a) (b) (c) (d)

24.

6 7 8 9

Identify the operating stem (crank) in the diagram of the kelly cock at right. (a) (b) (c) (d)

25.

To help seat the test plug. In order to not damage the casing and formation. To assist the test plug to seal. So the test string can be pulled dry when pulling out of the hole after testing.

3 4 5 6

Identify the upper body in the diagram of the kelly cock at right. (a) 4 (b) 5 (c) 6 (d) 14

26.

Identify the seats in the diagram of the kelly cock at right. (a) (b) (c) (d)

2 3 4 8

27.

The wind is blowing from port to starboard. While drilling the well starts to flow. What functions would you operate if your system is not automatically controlled? (a) (b) (c) (d)

Pressure A, Close B, Open C Open F, Close C, Pressure A Open F, Open B, Pressure A Open B, Close C, Pressure A

28.

What is the main function of a diverter? (a) (b) (c) (d)

29.

If a diverter system incorporates a valve on the vent line, which one of the following would be preferred as the method to operate the system? (a) (b) (c) (d)

30.

3,000 psi 1,500 psi 1,000 psi 2,000 psi

On a floating rig, the diverter should be placed: (a) (b) (c) (d)

33.

Pipe ram Annular preventer Blind ram Rotating head BOP test plug

What is the normal supply of hydraulic pressure to a diverter system? (a) (b) (c) (d)

32.

Open vent line, close diverter. Keep vent line open at all times; close diverter when kick occurs. Close diverter, then open vent line valve. Have an automatic system that will open vent line prior to closing diverter element.

Which one of the following pieces of equipment functions effectively as a diverter when pipe is in the well? (a) (b) (c) (d) (e)

31.

To shut in shallow kick. To direct flow a safe distance away from the rig floor. To create a backpressure sufficient to stop formation fluid. To act as a back up system if the annular preventer fails.

Directly below the preventer stack. Blow slip joint, but above sea level. Above slip joint. In shaker room.

Which of the following is generally used as a diverter? (a) Hydril GK (b) Hydril GL (c) Hydril MSP

34.

The blind shear ram is used on a floating rig only for emergency rig evacuation. (a) True (b) False

35.

Which of the following lines normally has the largest ID? (a) (b) (c) (d)

36.

Choke line Kill line Annular preventer closing line Diverter vent line

When using normally weighted muds, should the remote operated HCR valve be used as the inner or outer kill valve on the preventer stack? (a) Inner (b) Outer

37.

Kill lines are: (a) Placed below the pipe ram most commonly used. (b) Used to pump fluid into the well if normal circulating path cannot be used. (c) Not used as fill up lines. (d) All of the above. (e) None of the above.

38.

How should the choke manifold be set up for a soft shut in while drilling? (a) (b) (c) (d)

39.

HCR valve closed, CL open to shakers through remote adjustable choke, remote adjustable choke closed. HCR valve closed, choke line open to shakers through manually operated choke, manual choke closed. HCR valve open, choke line open through remote adjustable choke open, remote choke open. HCR valve closed, choke line through remote adjustable choke open, remote adjustable choke open.

What is the main purpose of the choke and kill manifolds? (a) (b) (c) (d)

Close in the well. To read shut in pressures. To hold back pressure and safely allow kick to be circulated out. To test the preventer and casing.

40.

What valves on the diagram above must be opened to use the mud pump to circulate through the manual choke and out to the mud gas separator? (a) (b) (c) (d)

41.

Which valves on the diagram above need to be open to use the cement pump to pump through the drill string and run a L.O.T.? (a) (b) (c) (d)

42.

1, 3, 7, 8, 10, 13, 16, 19 1, 4, 5, 6, 7, 8, 10, 11, 14, 17 2, 3, 7, 8, 10, 11, 14, 19 2, 4, 5, 6, 7, 8, 10, 13, 16, 19

1, 2, 3, 4, 5, 6 1, 3 2, 3, 4, 5, 6 2, 4, 5, 6

What valves on the diagram above must be open for pressure testing a casing string with cement pump against blind rams? (a) (b) (c) (d)

1, 3, 7, 8 2, 3, 5, 6 2, 4, 5, 6 1, 3, 5, 6

43.

On the diagram on the previous page, what valves should be open for a hard shut in using the mud pump and remote choke to the mud gas separator while drilling? (a) (b) (c) (d)

44.

Choose the following list of valves that would be left open when lining the choke up for a soft shut-in. (a) (b) (c) (d)

45.

To close the well in quickly. To save erosion in the flow line. To measure flow rate. To give safety and flexibility to the circulation and discharge of kick fluid.

From what direction should a valve in the choke and kill manifold be tested? (a) (b) (c) (d)

47.

V1, V2, V4, V5, V6, V8, R1 V1, V2, V5, V6, V7 V1, V2, V9, C1, V10, V11 V1, V2, V11, V6, V8, R1

The main consideration for the choke manifold in the overall BOP system is: (a) (b) (c) (d)

46.

1, 3, 7, 10, 11, 14, 19 1, 2, 3, 4, 5, 8, 10, 11, 14 2, 3, 7, 8, 10, 11, 14, 19 2, 4, 5, 8, 9, 10, 11, 14, 19

Does not matter; the valve is made to test both sides. Always on the top side. From the side fluid would be expected to come from in a well control situation. Always on the bottom side.

Which of the following is not essential to the choke panel? (a) (b) (c) (d)

Drill pipe pressure gauge Casing pressure gauge Flow rate indicator Strokes per minute gauge

48.

Choke line between preventer stack and choke manifold should: (a) (b) (c) (d) (e)

49.

What dimensions create pressure in the mud gas separator? (a) (b) (c) (d)

50.

D1 and H2 D1 and H3 D1 and H1 D4 and L4

What dimension(s) determine the operating pressure of a mud gas separator? (a) (b) (c) (d)

51.

Be as straight as possible. Be firmly anchored. Have sufficient bore to prevent erosion. Have rated pressure at least equal to stack working pressure. All of the above.

H1 H1 and H3 H1 and H2 D1, D2, and H2

Based on the diagram, with a mud weight of 9.8 ppg flowing through the mud gas separator and liquid seal, how much hydrostatic pressure would have to be overcome to allow gas to vent to the shale shakers? (H 1 = 10ʹ, H2 = 15ʹ, D1 = 8ʺ) (a) 9.17 psi (b) 5.10 psi (c) 14.27 psi (d) 4.08 psi

52.

What does 13⅝ mean when the BOP equipment in use is described as 15M – 13 ⅝? (a) (b) (c) (d)

Exterior diameter of the flange or hub. Exterior diameter of the BOP Cylinder diameter of the hydraulic actuator for the Ram BOPs. The throughbore ID of the BOP.

53.

Figures 1, 2, and 3 illustrate the profiles of three different types of end outlet connections of side outlet connections used on BOP. Which is a flanged connection (bolted connection)? (a) Figure 1 (b) Figure 2 (c) Figure 3

54.

Figures 1, 2, and 3 illustrate the profiles of three different types of end outlet connections of side outlet connections used on BOP. Which is a studded connection? (a) Figure 1 (b) Figure 2 (c) Figure 3

55.

Figures 1, 2, and 3 illustrate the profiles of three different types of end outlet connections of side outlet connections used on BOP. Which is a clamp hub connection? (a) Figure 1 (b) Figure 2 (c) Figure 3

56.

Which of the two flanges below has a specified distance between made up flanges which require occasional re-tightening of bolts/studs and nuts? (a) API Type 6B (b) API Type 6BX

57.

Critical dimensions have been numbered: 1, 2, 3, 4. Which number indicates the normal flange dimension? (a) (b) (c) (d)

58.

Dimension 1 Dimension 2 Dimension 3 Dimension 4

What has to be checked before the installation of any annular packing element? (Two Answers) (a) Temperature rating of the element. (b) Type of mud to be used. (c) Desired hydraulic closing pressure. (d) Maximum pipe O.D.

Page 272 IWCF EQUIPMENT 3

59.

The illustration above shows cross sectional profiles of four different API ring gaskets commonly used on wellhead equipment. Indicate the type of ring gasket that matches the type 6 BX flange. (a) (b) (c) (d)

60.

Most of the conventional front packer elements fitted on BOP rams are enclosed between steel plates. What are the main reasons for this type of design? (Two Answers) (a) (b) (c) (d)

61.

Type R Octagonal Type R Oval Type RX Type BX

To support the weight of the drill string during hang-off. To prevent the rubber extruding top and bottom when the rams are closed. To feed new rubber into sealing contact with the pipe when the sealing face becomes worn. To prevent any swelling when used during high temperature operations.

Is it an advantage to use a full closing float valve in the drill string to avoid flow back while tripping or during a connection? (a) Yes (b) No

62.

Is it an advantage to use a full closing float valve in the drill string to read drill pipe pressure value following a well kick? (a) Yes (b) No

63.

Is it an advantage to use a full closing float valve in the drill string to allow reverse circulation? (a) Yes (b) No

64.

Is it an advantage to use a full closing float valve in the drill string to reduce surge pressure? (a) Yes (b) No

65.

From the diagram of the Regan-Vetco Diverter on the right, identify the flowline seals. (a) (b) (c) (d)

66.

From the diagram of the Regan-Vetco Diverter on the right, identify the flowline. (a) (b) (c) (d)

67.

2 3 4 5

From the diagram of the Regan-Vetco Diverter on the right, identify the closing port. (a) (b) (c) (d)

70.

1 3 4 7

From the diagram of the Regan-Vetco Diverter on the right, identify the diverter housing. (a) (b) (c) (d)

69.

2 3 4 5

From the diagram of the Regan-Vetco Diverter above, identify the insert packer. (a) (b) (c) (d)

68.

1 2 5 8

1 2 3 4

What are the two main components in a 29½ ʺ diverter system? (Two Answers) (a) (b) (c) (d) (e)

A low pressure annular preventer with a large ID. A vent line of sufficient diameter to permit safe venting using the mud gas separator. A high pressure ram type preventer with a large ID. A vent line with a manually operated full opening valve. A vent line of sufficient diameter to permit safe venting and proper disposal of flow from the well.

71.

Well kicks with bit off bottom and is shut in. Decision is made to strip back into the hole. What equipment should be made up onto the string prior to performing the stripping operation safely, assuming there is no float sub or dart sub in the string? (a) (b) (c) (d) (e)

72.

The lower kelly cock, upper kelly cock, drill pipe safety valve, and Inside BOP are some tools used to prevent flow from inside the drill string. To what pressure should these components be tested? (a) (b) (c) (d)

73.

Two times the rated working pressure of the tool (up to 5,000 psi) One and a half times the rated working pressure of the tool. Always use a pressure value equal to 10,000 psi. Test to a pressure at least equal to the maximum anticipated surface pressure, but limited to the maximum rated working pressure of the BOP stack in use.

API STD 53 states that each closing unit should be equipped with sufficient number and sizes of pumps to satisfactorily perform the closing unit capacity test. With the accumulator system isolated, the pumps should be capable of closing the annular preventer on the size of DP being used, open the hydraulically operated choke line valve and obtain a minimum of 200 psi pressure above accumulator pre-charge pressure on the closing unit manifold within: (a) (b) (c) (d)

74.

Only the drill pipe safety valve (closed) Only the Inside BOP. DP safety valve (open) with Inside BOP installed on top. Inside BOP with drill pipe safety valve (closed) on top. Only the drill pipe safety valve (open).

1 min or less 2 min or less 3 min or less 4 min or less

Which is the correct definition of the “usable fluid volume of an accumulator”? (a) Total volume to be stored in the accumulator tank. (b) Total volume to be stored in the accumulator cylinder. (c) Total volume recoverable from the cylinders between the accumulator operating pressure and the minimum operating pressures. (d) Total volume recoverable from the cylinders between the accumulator operating pressures and the precharge pressure. (e) Total volume recoverable from the cylinder between the accumulator operating pressure and 500 psi above the pre-charge pressure.

75.

Using the diagram at right and the information below, answer the following question. If gas condensate is being run through the mud gas separator, and the pit is full of condensate, what is the blow-through pressure? H2: H1: H3: D1: D3: MW: Gas Condensate: (a) (b) (c) (d)

76.

8.5 feet 12.5 feet 25 feet 4.5 feet 8 inches 11.1 ppg 6.5 ppg

4.90 psi 2.87 psi 7.21 psi 4.22 psi

Using the information below, calculate the tension to be applied when using a Type F Cup Tester and testing with 5,000 psi. Casing ID: Area: DP OD: DP Area: (a) (b) (c) (d)

151,250 lbs 253,307 lbs 507,500 lbs 605,000 lbs

12.41ʺ 121 sq. inches 5ʺ 19.5 sq. inches

IWCF    Use the diagram to the right to answer questions 1-4. 1.

The shuttle valves isolate pressurized control fluid communication between the selected system and the redundant system. (a) True (b) False

2.

The shuttle valves are pilot operated. (a) True (b) False

3.

The shuttle valves allow retrieving a malfunctioning pod without losing hydraulic BOP control. (a) True (b) False

4.

The shuttle valves automatically seal any hydraulic leaks in the selected pod. (a) True (b) False

5.

The API STD 53 states the maximum closing times for surface and subsea blowout preventers. What is the stipulated time requirement for an 18¾ ʺ Annular on a surface stack? (a) (b) (c) (d)

6.

The API STD 53 states the maximum closing times for surface and subsea blowout preventers. What is the stipulated time requirement for an 18¾ ʺ Annular on a subsea stack? (a) (b) (c) (d)

7.

30 sec 45 sec 60 sec Two min


The API STD 53 states the maximum closing times for surface and subsea blowout preventers. What is the stipulated time requirement for a 13 ⅜ʺ Ram on a surface stack? (a) (b) (c) (d)


8.

The API STD 53 states the maximum closing times for surface and subsea blowout preventers. What is the stipulated time requirement for a 20 ʺ Annular on a surface stack? (a) (b) (c) (d)

9.


The API STD 53 states the maximum closing times for surface and subsea blowout preventers. What is the stipulated time requirement for a 16 ʺ ram on a subsea stack? (a) (b) (c) (d)


Use the following data to answer questions 10 - 13. MW: Seawater Gradient: Depth of water: Air Gap: TVD: DP: DC: Riser: Stack: Accumulator: Atmospheric Pressure:

10.5 ppg 0.445 psi/ft 2,000 feet 50 feet 8,500 feet 5ʺ, 19.5, XH 6¼ʺ × 213/16ʺ, 91 lbs/ft 22ʺ OD, 20ʺ ID Four (4) 18¾ʺ Cameron 10,000 psi Type U Rams Two (2) 18¾ʺ Shaffer 5,000 psi Annular Preventers 3,000 psi, 1,000 psi precharge, 1,200 psi minimum drawdown 14.7 psi

The rams require 5.4 gallons each to close and 5.2 gallons each to open. The annular preventers require 30.0 gallons to close and 24.0 gallons to open. A decision has been made to require 100 gallons of useable fluid in the subsea accumulator. The remaining gallons of hydraulic fluid will be stored on the surface.

10.

If we want enough hydraulic fluid to close, open, and close all the BOPs and have an additional 25% safety factor, what is the total amount of hydraulic fluid required? (a) (b) (c) (d)

11.

232 gal 290 gal 150 gal 350 gal

What is the hydrostatic pressure of the seawater? (a) 868 psi (b) 890 psi (c) 912 psi (d) 1,092 psi

12.

What would be the total pressure in the accumulator with a 1000 psi nitrogen pre-charge? (Surface precharge compensated for depth) (a) (b) (c) (d)

13.

What is the total volume of hydraulic fluid in the surface accumulator needed with the remainder of the hydraulic fluid stored at the surface? (a) (b) (c) (d)

14.

1,000 psi 1,200 psi 1,890 psi 1,905 psi

381 gal 290 gal 281 gal 190 gal

Master electric panels as well as electric mini-panels for operation of functions on subsea BOP’s are supplied with an electric Memory Function. Which statement is correct? (a) Memory Function indicates a malfunction by giving permanent light on the alarm panel after an alarm has been acknowledged and the audible alarms have stopped. (b) Memory Function reminds the driller to engage the wedge locks before hanging off the drill pipe. (c) Memory Function reminds the driller to add glycol (anti-freeze fluid) when the temperature drops below a certain level. (d) Memory Function indicates the previous position before “Blocked Position” of three functions.

15.

Identify the one ram locking device from the list below that does not allow for self feeding ram packers to allow for packer wear. (a) (b) (c) (d) (e)

16.

According to the API, what is the Rated Working Pressure for BOP equipment? (a) (b) (c) (d)

17.

Shaffer “Ultralock” Koomey “Autolock” Hydril “MPL” Cameron “Wedgelock” Shaffer “Poslock”

Maximum anticipated reservoir pressure. Maximum anticipated bottom hole pressure. Maximum anticipated surface pressure. Maximum anticipated hydrostatic drilling fluid pressure.

While testing the pipe rams, a leak in the weep hole on one of the preventer bonnets is found. What is the proper action that should be taken? (a) Energize emergency packing ring. If leak stops, leave it until next scheduled maintenance. (b) The weep hole checks the operating chamber. If the amount of leaking fluid is small, no action is required until scheduled maintenance. (c) The primary ram shaft seal is leaking. Secure the well and replace immediately. (d) The ram packing elements on the ram body are worn out. Secure the well and replace immediately.

18.

According to the API SPEC 16D, what is the usable fluid volume of an accumulator? (a) The total volume to be stored in the accumulator tank. (b) The total volume recoverable from the c ylinders between the accumulator operating pressure and the precharge pressure. (c) The total volume recoverable from the c ylinders between the accumulator operating pressure and the 200 psi above the pre-charge pressure. (d) The total volume to be stored in the accumulator cylinders.

19.

On the electric drillers panel (surface BOP); a ram close function was activated. What is the cause of the problem based upon the following observations that were made: Green light went out. Red light came on. Annular pressure did not change. Manifold pressure did not change. Accumulator pressure did not change. (a) (b) (c) (d)

20.

Which pressure readings would decrease if you operated the pipe rams. (a) (b) (c) (d)

21.

Manifold Pressure and Annular Pressure. Manifold Pressure and Accumulator Pressure. Annular Pressure and Accumulator Pressure. Pre-charge Pressure and Manifold Pressure

When a function on the Subsea BOP is activated from the Driller’s panel a certain process takes place. Which of the following sequences is correct? (a) (b) (c) (d)

22.

Electric pressure switches are malfunctioning. There is a blockage in the hydraulic line connecting the BOP to the BOP Control Unit. There is a leak in the hydraulic line connecting the BOP to the BOP Control Unit. The electric driven triplex pump is malfunctioning.

The selected function is activated only from control fluid stored in the surface accumulators. The pilot pressure is sent to the relevant SPM valves in both pods. The pilot pressure activates the relevant SPM valve only in the selected pod. The selected function is activated only from control fluid stored in the subsea accumulator cylinders.

On the hydraulic BOP control unit manifold for a subsea BOP, a number of Manipulator valves are installed. Manipulator valves control the SPM valves in the subsea pods. Which is the correct description of a Manipulator valve? (a) A manipulator valve is a 3-position 4-way directional control valve that has the pressure inlet port blocked and the operator ports vented in the center position. (b) A manipulator valve is a 3-position 4-way directional control valve that has the pressure inlet blocked and the operator ports blocked in the center position. (c) A manipulator valve has two or more supply pressure ports and only one outlet port. When fluid is flowing through one of the supply ports, the internal shuttle seals off the other inlet port and allows flow to the outlet port only. (d) A manipulator valve is an electrically operated valve that controls a hydraulic or pneumatic pilot signal or function.

23.

On a subsea BOP control panel with 2-position, 3-way Sub Plate Mounted (SPM) valves that are normally closed, pilot operated and of the spring return type, the SPM valve is opened by spring force. (a) True (b) False

24.

On a subsea BOP control panel with 2-position, 3-way Sub Plate Mounted (SPM) valves that are normally closed, pilot operated and of the spring return type, the SPM valve is opened when regulated hydraulic control fluid is supplied to the actuator. (a) True (b) False

25.

On a subsea BOP control panel with 2-position, 3-way Sub Plate Mounted (SPM) valves that are normally closed, pilot operated and of the spring return type, the SPM valve is closed by spring force and sea water hydrostatic pressure. (a) True (b) False

26.

On a subsea BOP control panel with 2-position, 3-way Sub Plate Mounted (SPM) valves that are normally closed, pilot operated and of the spring return type, the SPM valve is opened when hydraulic pilot fluid is supplied to the actuator. (a) True (b) False

27.

What is meant by the closing ratio for a ram type BOP? (a) Ratio between closing and opening volume. (b) Ratio between closing and opening time. (c) Ratio of the wellhead pressure to the pressure required to close the BOP.

For questions 28-29, use the following information. BOP: Accumulator: Closing Ratio required: Hydraulic Fluid required: 28.

13⅝ʺ, 10,000 psi 3,000 psi, 1,000 psi pre-charge, 1,200 psi minimum draw down 8.0 to 1 300 gallons needed to function all components.

What is the final pressure required based upon the closing ratio required? (a) 1,000 psi (b) 1,250 psi (c) 3,000 psi (d) 10,000 psi

29.

How many 10-gallon bottles are required to store the 300 gallons of hydraulic fluid? (a) 10 bottles (b) 50 bottles (c) 65 bottles (d) 100 bottles

30.

What are the main advantages of having a riser fill-up valve installed on the marine riser system? (a) (b) (c) (d)

31.

Less tension is required for the riser and it reduces the risk of riser collapse. It allows pumping of heavy mud in the riser during kill operations and it reduces the risk of riser collapse. It keeps the well full of mud when tripping out of the hole and there is less tension required for the riser. It reduces the risk of riser collapse and it continuously supplies sea water to the well in case of total loss of returns.

On a semi-submersible rig, why does the driller need information about the tides? (a) To correctly set ram closing pressure and to correctly hang-off during well control operations. (b) To calculate riser tensioner ton miles and to adjust riser tensioners. (c) To know the position of tool joints in the stack relative to the rams and to correctly hang off during well control operations. (d) To know the position of tool joints in the stack relative to the rams and to correctly set ram closing pressure.

32.

In case of diverting a shallow gas blowout through a long marine riser, which of the following is a risk? (a) (b) (c) (d)

The riser may burst due to extreme internal pressures. The riser may collapse due to the light hydrostatic of the gas. The riser may have excessive tension placed on it because of the lighter hydrostatic. The riser automatic disconnect function may be engaged, causing it to disconnect.

33.

Using the diagram above, which diagram represents the Manipulator valve? (a) Diagram A (b) Diagram B

34.

Using the diagram in the previous question, which diagram represents the Selector valve? (a) Diagram A (b) Diagram B

35.

If the Manipulator four-way valve is shifted to the center or “block” position, the pressure will be vented from the line previously pressurized. (a) True (b) False

36.

The Manipulator four-way valve can be used for troubleshooting hydraulic leaks. (a) True (b) False

37.

The pod selector valve on the subsea hydraulic control system is the manipulator type. (a) True (b) False

For questions 38 and 39, use the information below and the graphic on the right. Maximum MW: MW in the Hole: Glycol: KMW: CL/KL Length: Casing Shoe: Total Depth: 38.

What is the MAASP with the choke line full of glycol? (a) (b) (c) (d)

39.

1248 psi 1414 psi 764 psi 2579 psi

After circulating kill mud of 13.0 ppg to the surface, what is the new static MAASP? (a) (b) (c) (d)

40.

15.5 ppg 12.5 ppg 9.3 ppg 13.0 ppg 1,000 feet 8,000 feet (MD/TVD) 10,000 feet (MD/TVD)

1040 1248 1300 1414

psi psi psi psi

Using the information below, determine what the dynamic MAASP is while circulating the first circulation using the Driller’s Method. Maximum Mud Weight from L.O.T.: Mud Weight: Kill Mud Weight: Slow Circulating Rate: Dynamic Pressure Loss through Riser at 30 SPM: Dynamic Pressure Loss through CL at 30 SPM: Annular Pressure Loss: TVD/MD: Casing TVD/MD: SIDPP: SICP: (a) (b) (c) (d)

1207 psi 907 psi 887 psi 1254 psi

15.5 ppg 10.5 ppg 11.2 ppg 30 SPM 450 psi 580 psi 20 psi 8,700 feet 5,400 feet 317 psi 430 psi

QA-RD7AE-V8

Section 1.

ISO 9001:2008

January 2012

Formula Sheet

English - API (Field Units)

Page 1 of 4

Filled-in Kil l Sheet Exercises - Gauge Problem Actio ns.

Gauge Problem Exercises are constructed from a completed kill sheet ‘filled-in’ with a ll relevant volume and pressure calculations. Each question is based on the strokes, pump rate, drill pipe and casing gauge readings at a specific point in time during a well kill operation. Any one or a combination of these readings could indicate the action required. Options are shown in the multiple-choice answers. The casing and/or drill pipe pressures will only be relevant to the action if – • •

The casing and/or drill pipe pressures given in the question are below the expected pressures, or The casing and/or drill pipe pressures given in the question are 70 psi or more above the expected pressures.

Section 2.

Calculatio n Formula. Abbr evi ati on s u sed in th is docu men t

1.

bbl

=

Barrels (US)

bbl /ft

=

Barrels (US) per foot

bbl /min

=

Barrels (US) per minut e

bbl /stroke

=

Barrels (US) per strok e

BHP

=

Bott om Hole Pressure

BOP

=

Blow out Preventer

ft

=

Feet

ft/hr

=

Feet per hou r

ft/min

=

Feet per minu te

lb/bbl

=

Pounds per barrel

LOT

=

Leak-off Test

MAASP

=

Maximum Allow able Annu lar Surface Pressure

ppg

=

Pounds per gallon

psi

=

Pounds per square inch

psi/ft

=

Pounds per square inch per foot

psi/hr

=

Pounds per square inch per hour

SICP

=

Shut in Casing Pressure

SIDPP

=

Shut in Drill Pipe Pressure

SPM

=

Strokes per minu te

TVD

=

True Vertical Depth

0.052

=

Constant factor

HYDROSTATIC PRESSURE (ps i) Mud Density (ppg) x 0.052 x TVD (ft)

2.

PRESSURE GRADIENT (ps i/f t) Mud Density (ppg) x 0.052

3.

DRILLING MUD DENSITY (ppg) Pressure (psi) ÷ TVD (ft) ÷ 0.052 or

Pressure (psi) TVD (ft ) x 0.052

International Well Control Forum, Inchbraoch House, South Quay, Montrose, Angus DD10 9UA, United Kingdom. Tel: +44 1674 678120 Fax: +44 1674 678125

QA-RD7AE-V8

4.

ISO 9001:2008

January 2012

Formula Sheet


FORMATION PORE PRESSURE (ps i) Hydrostatic Pressure in Drill String (psi) + SIDPP (psi)

5.

PUMP OUTPUT (bbl /min ) Pump Displacement (bbl/stroke) x Pump Rate (SPM)

6.

ANNULAR VELOCITY (ft/m in)

Pump Output (bbl/min) Annular Capacity (bbl/ft) 7.

EQUIVALENT CIRCULATING DENSITY (pp g) [Annular Pressure Loss (psi) ÷ TVD (ft) ÷ 0.052] + Mud Density (ppg) or

Annular Pressure Loss (psi) + TVD (ft) × 0.052 8.

Mud Density (ppg)

MUD DENSITY WITH TRIP MARGIN INCLUDED (pp g) [Safety Margin (psi) ÷TVD (ft) ÷ 0.052] + Mud Density (ppg) or

Safety Margin (psi) + TVD (ft) × 0.052 9.

Mud Density (ppg)

NEW PUMP PRESSURE (ps i) WITH NEW PUMP RATE app ro xi mate

Old Pump Pressure (psi) ×

Pump Rate (SPM) New Old Pump Rate (SPM) 

2

10. NEW PUMP PRESSURE (ps i) WITH NEW MUD DENSITY app ro xi mate

Old Pump Pressure (psi) ×

New Mud Density (ppg) Old Mud Density (ppg)

11. MAXIMUM ALL OWABLE MUD DENSITY (ppg ) [Surface LOT pressure (psi) ÷ Shoe TVD (ft) ÷ 0.052] + LOT Mud Density (ppg) or

Surface LOT Pressure (psi) + Shoe TVD (ft )× 0.052

LOT Mud Density (ppg)

12. MAASP (psi ) [Maximum Allowable Mud Density (ppg) – Current Mud Density (ppg)] x 0.052 x Shoe TVD (ft) 13. KILL MUD DENSITY (ppg ) [SIDPP (psi) ÷ TVD (ft) ÷ 0.052] + Original Mud Density (ppg) or

SIDPP (psi) TVD (ft )× 0.052 +

Original Mud Density (ppg)

14. INITIAL CIRCULATING PRESSURE (ps i) Kill Rate Circulating Pressure (psi) + SIDPP (psi)


Page 2 of 4

QA-RD7AE-V8

ISO 9001:2008

January 2012

Formula Sheet


15. FINAL CIRCULATING PRESSURE (ps i)

Kill Mud Density (ppg) Original Mud Density (ppg)

× Kill Rate Circulating Pressure (psi)

16. BARYTE REQUIRED TO INCREASE DRILL ING MUD DENSITY (lb /bb l)

Kill Mud Density (ppg) − Original Mud Density (ppg)] × 1500 35.8 − Kill Mud Density (ppg)

[

17. GAS MIGRATION RATE (ft/h r) Rate of Increase in Surface Pressure (psi/hr) ÷ Drilling Mud Density (ppg) ÷ 0.052 or

Rate of Increase in Surface Pressure (psi/hr) Drilling Mud Density (ppg) × 0.052 18. GAS LAWS P1 x V1 = P2 x V2

P2 =

P × V V

V2 =

P × V P

19. ACCUMULATOR BOTTLE USEABLE FLUID (gall ons )

Pressure (psi)  Precharge Pressure (psi) × Bottle size (gallons) Precharge Minimum Pressure (psi) Maximum Pressure (psi) 20. PRESSURE DROP PER FOOT TRIPPING DRY PIPE (ps i/f t)

Drilling Mud Density (ppg) × 0.052 × Metal Displacement (bbl/ft) Riser or Casing Capacity (bbl/ft) − Metal Displacement (bbl/ft) 21. PRESSURE DROP PER FOOT TRIPPING WET PIPE (psi/ft)

Drilling Mud Density (ppg) × 0.052 × Closed End Displacement (bbl/ft) Riser or Casing Capacity (bbl/ft) − Closed End Displacement (bbl/ft) 22. LEVEL DROP PULLING REMAINING COLLARS OUT OF HOLE DRY (ft )

Length of Collars (ft) × Metal Displacement (bbl/ft) Riser or Casing Capacity (bbl/ft) 23. LEVEL DROP PULLING REMAINING COLLARS OUT OF HOLE WET (ft )

Length of Collars (ft) × Closed End Displacement (bbl/ft) Riser or Casing Capacity (bbl/ft) 24. LENGTH OF TUBULA RS TO PULL DRY BEFORE OVERBAL ANCE IS LOST (ft)

Overbalance (psi) × [Riser or Casing Capacity (bbl/ft) − Metal Displacement (bbl/ft)] Mud Gradient (psi/ft) × Metal Displacement (bbl/ft) 25. LENGTH OF TUBULA RS TO PULL WET BEFORE OVERBALANCE IS LOST (ft)

Overbalance (psi)× [Riser or Casing Capacity (bbl/ft)− Closed End Displacement (bbl/ft)] Mud Gradient (psi/ft) × Closed End Displacement (bbl/ft) 26. VOLUME TO BL EED OFF TO RESTORE BHP TO FORMATION PRESSURE (bb l)

Increase in Surface Pressure (psi) × In�lux Volume (bbl) Formation Pressure (psi) − Increase in Surface Pressure (psi) International Well Control Forum, Inchbraoch House, South Quay, Montrose, Angus DD10 9UA, United Kingdom. Tel: +44 1674 678120 Fax: +44 1674 678125

Page 3 of 4

QA-RD7AE-V8

ISO 9001:2008

January 2012

Formula Sheet


27. SLUG VOLUME (bb l) FOR A GIVEN LENGTH OF DRY PIPE

Length of Dry Pipe (ft ) × Pipe Capacity (bbl/ft) × Drilling Mud Density (ppg) Slug Density (ppg) − Drilling Mud Density (ppg) 28. PIT GAIN DUE TO SLUG U-TUBING (bbl)

Slug Volume (bbl) ×

Slug Density (ppg)  1 Drilling Mud Density (ppg)

29. RISER MARGIN (pp g)

 

[Air Gap (ft ) + Water Depth (ft)] × Mud Density (ppg) [Water Depth (ft ) × Sea Water Density (ppg)] TVD (ft ) Air Gap (ft ) Water Depth (ft)



30. HYDROSTATIC PRESSURE LOSS IF CASING FLOAT FAIL S (ps i)

Mud Density (ppg) × 0.052 × Casing Capacity (bbl/ft) × Un�illed Casing Height (ft) Casing Capacity (bbl/ft) + Annular Capacity (bbl/ft)

International Well Control Forum Inchbraoch House South Quay Montrose Angus DD10 9UA United Kingdom Tel: 44-1674-678120 Fax: 44-1674-678125 email: [email protected] www.iwcf.org

The International Well Control Forum is a legally constituted non-profit making organisation whose articles of association are bound by the laws of the Netherlands. The Forum is registered at The Dutch Chamber of Commerce in The Hague, The Netherlands, Reg. No. 41157732


Page 4 of 4

 

For questions 1-23, use the following information: Bit and Hole: DP: Metal Disp.: DC:

8½ 5 , 19.5, Grade E, 7,680´, Cap – 0.01745 bbl/ft, 0.008 bbl/ft 6 ½ x 2 13/16 , 91 lbs/ft, 720´, Cap. – 0.00768, Metal Disp. – 0.033 Casing: 9 5/8 , ID 8.681 , MD 6,250´, TVD 6,250´, Cap. – 0.0732 bbl/ft Depth: TVD – 8,400´, MD – 8,400´ Mud Density: 10.4 ppg L.O.T.: 10.0 ppg with applied surface pressure of 1,450 psi Pump Output: 0.1097 bbl/stk Slow Circulating Rate: 30 SPM Dynamic Pressure Loss: 650 psi @ SCR of 30 SPM Annular Pressure Loss: 590 psi SIDPP: 450 psi SICP: 580 psi ″

″

″

″

1.

3,380 psi 3,738 psi 4,993 psi 4,543 psi

What is the annular velocity around the drill pipe in open hole? (a) (b) (c) (d)

5.

0.598 0.541 0.520 0.465

What is the formation pore pressure? (a) (b) (c) (d)

4.

4,543 psi 5,023 psi 3,380 psi 5,443 psi

What is the pressure gradient of the original mud? (a) (b) (c) (d)

3.

″

What is the hydrostatic pressure of the original mud in the well, before killing the well? (a) (b) (c) (d)

2.

″

71.69 ft/min 35.36 ft/min 23.92 ft min 22.45 ft min

What is the equivalent circulating density with the original mud? (a) (b) (c) (d)

11.8 ppg 11.5 ppg 10.4 ppg 11.4 ppg

6.

What is the maximum allowable mud density? (a) (b) (c) (d)

7.

10.4 ppg 14.4 ppg 14.5 ppg 15.3 ppg

What is the maximum allowable annular surface pressure (MAASP)? (a) 1,790 psi (b) 1,747 psi (c) 1,300 psi (d) 942 psi

8.

What is the required kill mud weight? (a) (b) (c) (d)

9.

11.0 ppg 11.4 ppg 11.5 ppg 12.0 ppg

What will be the required lbs/bbl of barite (baryte) to increase the drilling mud density to the kill density? (a) 61.73 (b) 67.90 (c) 129.63 (d) 87.75

10.

What will be the Initial Circulating Pressure? (a) 650 psi (b) 1,040 psi (c) 1,240 psi (d) 1,100 psi

11.

What will be the Final Circulating Pressure? (a) 719 psi (b) 650 psi (c) 1,100 psi (d) 1,040 psi

12.

What will be the new pump pressure if the toolpusher decides to pump at a slow circulating rate of 25 SPM? (a) (b) (c) (d)

650 psi 550 psi 451 psi 410 psi

13.

What will be the new dynamic pressure loss at the slow circulating rate of 30 SPM after the well has been killed? (a) (b) (c) (d)

14.

If the shut in casing pressure increases to 20 in ten minutes, what is the rate of percolation? (a) (b) (c) (d)

15.

12.0 ppg 11.9 ppg 11.5 ppg 12.5 ppg

If a slug is not used on the trip out of the hole (after killing the well), what will be the pressure drop per foot when tripping wet pipe? (a) (b) (c) (d)

17.

37 ft/hr 201 ft/hr 222 ft/hr 277 ft/hr

After killing the well a decision is made to trip out of the hole to change the bit. A safety margin of 200 psi will be used. What will be the required mud to trip? (a) (b) (c) (d)

16.

719 psi 650 psi 795 psi 549 psi

1.365 psi/ft 0.319 psi/ft 0.169 psi/ft 2.253 psi/ft

If a slug is not used when tripping out of the hole (after killing the well), what will be the level drop for pulling the remaining collars out of the hole wet? (a) 172 feet (b) 2,291 feet (c) 325 feet (d) 400 feet

18.

If a proper slug is used when tripping out of the hole (after killing the well), what will be the pressure drop per foot when pulling dry pipe? (a) (b) (c) (d)


19.

How much will the fluid level drop as the remaining drill collars are pulled from the hole? (a) 400 feet (b) 172 feet (c) 325 feet (d) 2,291 feet

20.

If two 94-ft stands of dry pipe are desired to be pulled, what slug volume is required if a 12.0 ppg slug is used? (a) (b) (c) (d)

21.

What will be the pit gain due to the slug u-tubing? (a) (b) (c) (d)

22.

23.43 bbl 23.85 bbl 21.32 bbl 25.15 bbl

2.8 bbl 2.3 bbl 3.3 bbl 2.5 bbl

If a proper slug is used on a trip after killing the well and a 200-psi overbalance is used (safety margin), what would be the length of tubulars to pull dry before overbalance is lost? (a) 1,680 feet (b) 2,726 feet (c) 627 feet (d) 1,290 feet

Use the following data to answer questions 23-24. Circulating Rate: Pump Output: Dynamic Pressure Loss: Influx volume: Increase in Surface Pressure: TVD: Mud Density in Hole: Formation Pressure: 23.

What is the pump output? (a) (b) (c) (d)

2.24 bbl/min 3.24 bbl/min 4.24 bbl/min 5.24 bbl/min

30 SPM 0.108 bbl/stk 700 psi 10 bbl 700 psi 4850 feet 9.5 ppg 2746 psi

24.

How many barrels must be bled off to restore the bottom-hole pressure back to the formation pressure? (a) (b) (c) (d)

25.

2.24 bbl 3.42 bbl 4.24 bbl 5.42 bbl

If the formation pressure is 7250 psi, the TVD of the 13 5/8 casing is 5800 ft, the TVD of the 9 5/8 casing is 11,450, and the TVD is 14,250, what is the required mud density to keep the well balanced? (a) 9.0 ppg (b) 9.7 ppg (c) 9.8 ppg (d) 12.2 ppg

Use the following information to answer question 26. Air Gap: Water Depth: TVD: Sea Water Density: Shoe TVD: Mud Density 9.8 ppg 26.

72 feet 6,700 feet 13,500 feet 8.5 ppg 10,700 feet

What would be the required mud density to keep the well balanced if the riser must be disconnected? (a) 9.8 ppg (b) 10.2 ppg (c) 11.2 ppg (d) 12.2 ppg

27.

How many gallons of hydraulic fluid are required to pressure up a 1,000 psi pre-charged 10-gallon nitrogen bottle to 3,000 psi? (a) (b) (c) (d)

3.33 gal 5.00 gal 6.67 gal 7.25 gal

Use the following data to answer question 28-29. Mud Density: Casing: DP: DC: Hole/Bit: 28.

″

″

″

″

″

What will be the hydrostatic pressure loss if the casing float fails and the unfilled casing height is 370 feet? (a) (b) (c) (d)

29.

9.8 ppg 9 5/8 , 8.681 ID, 47 lb/ft, 0.0732 bbl/ft 5 , 19.5, XH, 0.017310 bbl/ft 6 ½ x 2 ¾ , 0.0073 bbl/ft 12 ¼

107 psi 174 psi 236 psi 331 psi

What will be the hydrostatic pressure loss if the casing float fails and the unfilled casing height is 600 feet? (a) (b) (c) (d)

107 psi 174 psi 236 psi 331 psi

G  For Questions 1-6, use the following well data. Treat each problem independently from the others. All problems will be based on the pump down plan provided. Well Data: Depth:

7,523ʹ MD/TVD

Bit/Hole:

8½″

Casing:

9⅝″, N-80, 8.681 ″ ID Shoe @ 4,700ʹ MD, TVD

Drill Pipe:

5″, 19.5, “S”, 7,013 ʹ

Drill Collars:

6½″ × 213/16″, 510ʹ

Pumps:

National 10-P-160, 0.1100 bbl/stk

SRP:

575 psi @ 30 spm

Mud:

9.0 ppg

L.O.T.:

17.4 ppg @ 4,700 ʹ MD, TVD

SIDPP:

525 psi

SICP:

708 psi

Pit Gain:

14.5 bbl

Kill MW:

10.4 ppg

IWCF GAUGE EXERCISE 1.

Using the Wait & Weight Method, the Driller and Toolpusher have brought the pump up to Initial Circulating Pressure (ICP) and have pumped 15 strokes. (a) Everything is okay, continue with the plan. (b) The Driller needs to increase the pump rate. (c) The Toolpusher needs to close the choke a little bit.

2.

Using the Wait & Weight Method, the Driller and Toolpusher have brought the pump up to ICP and are 25 strokes into the plan. (a) Everything is okay. (b) The Toolpusher needs to open the choke some to get the Drill Pipe Pressure to match the Drill Pipe Pump Down Plan. (c) There is a hydraulic change in the system and the pump down plan needs to be revised.

3.

Using the Wait & Weight Method, the Driller and Toolpusher have pumped 360 strokes. (a) Everything is okay, continue with the plan. (b) The Toolpusher should close the choke some. (c) The Toolpusher should open the choke some to reduce the casing pressure.

4.

Using the Wait & Weight Method, The Toolpusher notices that after 800 strokes that the Casing Pressure and the Drill Pipe Pressure have both started decreasing. (a) Everything is okay, continue circulating. (b) The Toolpusher should try closing the choke, and if that does not rectify the problem, he should close the valve upstream of the remote choke, shut the pump down, and line up on choke #2. (c) The Toolpusher should turn the pump off, close the valve upstream of the choke, and line up to use choke #2.

5.

Using the Driller’s Method, The Toolpusher and Driller notice after 1500 strokes that Pump #1 has suddenly stopped pumping. (a) The Toolpusher should close the choke, instruct the Driller to line up on Pump #2, and bring Pump #2 up to the Slow Circulating Rate (SCR) holding the current Casing Pressure (650 psi) constant. (b) The Toolpusher should close the choke, instruct the Driller to line up Pump #2, and bring Pump #2 up to the SCR while holding 850 psi on the casing. (c) The Toolpusher should close the choke, instruct the Driller to line up Pump #2, bring Pump #2 up to SCR, and get the DP pressure back to ICP (1000 psi).

6.

Using the Wait & Weight Method, the Toolpusher and Driller notice after 3100 strokes that the Casing Pressure is increasing more rapidly. (a) Everything is okay, continue circulating. (b) The Toolpusher should try to maintain 1500 psi on the Casing Pressure. (c) The Toolpusher should open the choke and try to stabilize the Casing Pressure.

7.

The well has kicked and the Toolpusher shuts the well by closing the Upper Ram. (a) Everything is okay. (b) There is a blockage in the Annular Regulator. (c) The Pre-Charge pressure is low.

8.

Nothing has been functioned and the Toolpusher notices that the Accumulator Pressure is decreasing and the Manifold Pressure has increased to 1800 psi, 300 psi above normal. (a) (b) (c) (d)

Everything is okay. There is a leak in the Accumulator. The Pressure Regulating Valve is malfunctioning. The four-way valve on the Accumulator is broken. (e) The hydro-electric pressure switch is malfunctioning.

9.

Nothing has been functioned and the Toolpusher notices that the Accumulator Pressure and the Manifold Pressure are both decreasing, and that the Annular Pressure is staying constant. (a) Everything is okay. (b) There is a leak in the hydraulic circuit. (c) The Pressure Regulating Valve is malfunctioning. (d) The four-way valve on the Accumulator is broken. (e) The hydro-electric pressure switch is malfunctioning.

10.

Nothing has been functioned and the Toolpusher notices that the Accumulator Pressure is increasing, and the Manifold Pressure and Annular Pressure are both staying constant. (a) (b) (c) (d)

Everything is okay. There is a leak in the hydraulic circuit. The Pressure Regulating Valve is malfunctioning. The four-way valve on the Accumulator is broken. (e) The hydro-electric pressure switch is malfunctioning.

Use the diagram to the right (Pressure Gauges 5) to answer Questions 11-17.

11.

What is the normal operating pressure of Gauge #1 (Air)? (a) (b) (c) (d)

12.

What is the normal operating pressure of Gauge #2 (Accumulator)? (a) (b) (c) (d)

13.

120 psi 900-1500 psi 1500 psi 3000 psi

What is the normal operating pressure of Gauge #4 (Annular)? (a) (b) (c) (d)

15.

120 psi 900-1500 psi 1500 psi 3000 psi

What is the normal operating pressure of Gauge #3 (Manifold)? (a) (b) (c) (d)

14.

120 psi 900-1500 psi 1500 psi 3000 psi

120 psi 900-1500 psi 1500 psi 3000 psi

On which two gauges should there be a reduction in pressure when the annular preventer is functioned? (a) (b) (c) (d)

Gauge #1 and Gauge #2 Gauge #2 and Gauge #3 Gauge #2 and Gauge #4 Gauge #1 and Gauge #4

16.

On which two gauges should there be a reduction in pressure when the ram preventers are functioned? (a) (b) (c) (d)

17.

Gauge #1 and Gauge #2 Gauge #2 and Gauge #3 Gauge #2 and Gauge #4 Gauge #1 and Gauge #4

If Gauge #1 shows 0 pressure, which of the following components can be functioned? (a) Everything can be functioned. (b) Nothing can be functioned. (c) The annular preventers can be functioned, but the ram preventers cannot be functioned. (d) The ram preventers can be functioned, but the annular preventers cannot be functioned.

18.

If the light on the remote choke panel illuminates, but there is no drop in the pressure gauge, which of the following causes is related to the problem? (a) (b) (c) (d) (e)

19.

If the pressure gauge drops, but does not rise back up, which of the following causes is related to the problem? (a) (b) (c) (d) (e)

20.

The bulb has blown. The closing line to the BOP is blocked. The four-way valve on the accumulator f ailed to shift. The air pressure to the panel has been lost. There is a leak in the hydraulic lines to the BOP or in the BOP itself.

If the light does not illuminate and the pressure gauge does not drop, which of the following causes is related to the problem? (a) (b) (c) (d) (e)

21.



If the close light does not illuminate, but the pressure drops and later increases, which of the following causes is related to the problem? (a) (b) (c) (d) (e)


22.

If the charging pumps on the Accumulator continue to turn on and off even though nothing has been functioned, which of the following causes is related to the problem? (a) (b) (c) (d) (e)

23.

If a driller functions the “close top annular” button on a subsea BOP and the indicator light changes from green to red but the flow meter does not move and all the other gauges remain static, what is the first thing that should be done? (a) (b) (c) (d) (e)

24.

A pilot signal is sent to SPM valves in both pods The closing fluid is furnished by the pilot hydraulic system Only one SPM valve is actuated The fluid from the opening side of the BOP is returned to the accumulator All of the above

The well is shut-in with an annular BOP on a subsea stack and the flow meter continues to run. To preserve accumulator pressure and keep the well shut-in the driller should … (a) (b) (c) (d) (e)

26.

Attempt to close a ram BOP Attempt to close the other Annular BOP Call the subsea engineer Switch pods and try to close the top annular again Send the assistant driller to function the 4-way valve on the manifold manually to close the top annular.

When a BOP function is operated on a subsea BOP: (a) (b) (c) (d) (e)

25.


Close the well in with a pipe ram and open the annular Block the annular function, then shut in the well with a pipe ram Go to the manifold to diagnose the problem Close a pipe ram and monitor the flow Put the annular function in block

When a ram BOP is functioned on a subsea stack which of the following indicate the operation has taken place properly? (a) (b) (c) (d) (e)

Rig air decreases then increases to the original reading Manifold pilot pressure decreases and then increases The flow meter runs and continues to run Manifold read back pressure decreases and then increases to original Annular read back pressure decreases and then increases to original

27.

A subsea BOP control system is divided into a Control System and a Pilot System. Which of the following best describes the Pilot System? (a) (b) (c) (d) (e)

28.

The Pod selector valve is: (a) (b) (c) (d) (e)

29.

The Pilot system is a closed “dead end” system The Pilot System dumps fluid to the sea on every operation of the BOP function The Pilot System control the position of all shuttle valves on the BOP stack The fluid in the Pilot system flows continuously while the function takes place. The Pilot system fluid is hydraulic fluid with a small amount of additives to limit pollution of the environment.

Located on the LMRP Located on the subsea manifold Controls the flow of pilot fluid to the pods Directs fluid from the accumulator to the active pod A pilot operated valve

When a ram BOP is placed in the block position: (a) No further fluid movement is allowed to the operating piston (b) The pilot fluid in from the opening line is vented (c) The pilot valve fluid is locked in place (d) The operating piston is automatically opened (e) The power fluid to the ram operating piston is vented

30.

Select the arrangement of control systems that is correct for a subsea BOP system. (a) Primary control systems: Acoustic and Hydraulic; Secondary control systems: Electro-Hydraulic and ROV assist (b) Primary control systems: ROV assist and Hydraulic; Secondary control systems: Electro-Hydraulic and Acoustic (c) Primary control systems: Hydraulic and Electro-Hydraulic; Secondary control systems: Acoustic and ROV assist (d) Primary control systems; Electro-Hydraulic and Acoustic; Secondary control systems; Hydraulic and ROV assist (e) Primary control systems; Acoustics and ROV assist: Secondary control systems; Hydraulic and Electro-Hydraulic

The Driller’s Method is being used on this highly deviated well. Use the data from the kill sheet provided (already filled out) to answer questions 31-40.

31.

On the first circulation, after pumping for two minutes, the following readings are observed: Drill Pipe Pressure: Casing Pressure: Strokes Circulated: Pump rate:

1135 psi 700 psi 60 stks 28 spm

Which of the following actions should be taken? (one answer) (a) (b) (c) (d) (e) 32.

Everything is okay, continue circulating. Close the choke slowly. Open the choke slowly. Increase the pump rate. Decrease the pump rate.

On the first circulation, after pumping 8 minutes, the following readings are observed: Drill Pipe Pressure: Casing Pressure: Strokes Circulated: Pump rate:




On the first circulation after pumping 10 minutes, the following readings are observed: Drill Pipe Pressure: Casing Pressure: Strokes Circulated: Pump rate:

1350 psi and increasing rapidly 950 psi and increasing rapidly 300 stks 30 spm

Which of the following actions should be taken? (one answer) (a) (b) (c) (d)

Everything is okay, continue circulating. Turn the pump off and close the choke. Decrease the pump rate. Increase the pump rate.

34.

On the first circulation after 15 minutes, the kelly hose begins to jump violently and the following readings are observed: Drill Pipe Pressure: Casing Pressure: Strokes Circulated: Pump rate:

1000 psi and increasing rapidly 710 psi and increasing rapidly 450 stks 34 spm


Everything is okay, continue circulating. Close the choke slowly. Open the choke slowly. Decrease the pump rate. Close the well in.

After 2100 strokes, the casing pressure begins to increase quickly. What is the probable cause? Drill Pipe Pressure: Casing Pressure: Strokes Circulated: Pump rate: (a) (b) (c) (d) (e)

36.

The choke is plugging. The choke is washing out. A bit nozzle is plugged. A bit nozzle is washed out. Everything is normal, the influx is moving into the vertical section.

At the end of the first circulation, all of the influx has been circulated out and the well has been shut in. What should the Drill Pipe Pressure read? (a) (b) (c) (d)

37.

1240 psi 950 psi 2100 stks 30 spm

700 psi 450 psi 0 psi 1240 psi

At the end of the first circulation, all of the influx has been circulated out. What should the Casing Pressure read? (a) (b) (c) (d)


38.

On the second circulation, kill mud is being pumped to the bit. After 500 strokes, the following readings are observed: Drill Pipe Pressure: Casing Pressure: Strokes Circulated: Pump rate:




On the second circulation, 2400 strokes have been circulated and the followings readings are observed: Drill Pipe Pressure: Casing Pressure: Strokes Circulated: Pump rate:

1185 psi 420 psi 2400 stks 30 spm

Which of the following actions should be taken? (one answer) (a) (b) (c) (d) 40.

Everything is okay, continue circulating. The choke is plugging, shut the well in. The choke is washing out, shut the well in. The bit is plugging, shut the well in.

After pumping 7600 strokes on the second circulation, the well is shut in and the following readings are observed: Drill Pipe Pressure: Casing Pressure: Strokes Circulated: Pump rate:


What is the correct explanation? (a) Everything is okay. (b) There is trapped pressure, bleed the Drill Pipe and Casing back to zero. (c) There is trapped pressure and a small amount of influx. Bleed off the excess Drill Pipe pressure and circulate out the influx.

 1.

The difference between formation pore pressure and leak-off pressure The MAASP The difference between formation pore pressure and the hydrostatic pressure of the mud in the drillpipe The trapped pressure caused by shutting in the well

While drilling ahead a well kicks and is shut-in. Drill pipe and casing pressures start rising but before stabilizing both start dropping quite rapidly. What has probably happened? (a) (b) (c) (d) (e)

5.

Another influx is entering the wellbore The influx is migrating up the wellbore The gauges are faulty The BOP stack is leaking

What does the SIDPP indicate when the well is properly shut-in on an underbalanced kick. (a) (b) (c) (d)

4.


After shutting in on a kick the SIDPP and SICP have been stable for 15 minutes, they then both start slowly rising by the same amount. Which one of the following is the probable cause? (a) (b) (c) (d)

3.

 1

Normal formation pressure gradient for continuous depositional basins is generally assumed to be: (a) (b) (c) (d)

2.

 

The drill string has parted The bottomhole assembly has packed off A weak formation has broken down The pressure gauges have both malfunctioned Gas has started to migrate up the drill string and the annulus

A vertical well is 8,020 ft deep and filled with 12.5 ppg drilling fluid. While circulating with 80 spm the friction losses in the well system are as follows: Pressure loss in the drill string Pressure loss through the bit nozzles Pressure loss in the annulus What is the circulating pressure? (a) (b) (c) (d)

2,200 psi 2,800 psi 2,850 psi 3,000 psi

= = =

800 psi 1,850 psi 150 psi

6.

A vertical well is 8,020 feet deep and filled with 12.5 ppg drilling fluid. While circulating with 80 spm the friction losses in the well system are as follows: Pressure loss in the drill string Pressure loss through the bit nozzles Pressure loss in the annulus

= = =

800 psi 1,850 psi 150 psi

What is the bottomhole pressure while circulating? (a) (b) (c) (d) 7.

Which of the following best describes fracture pressure? (a) (b) (c) (d)

8.

The pressure in excess of mud hydrostatic that, if exceeded, is likely to cause losses at the casing shoe The total pressure applied at the shoe that is likely to cause losses The maximum bottomhole pressure allowed during a kill operation The maximum pressure allowed on the drillpipe gauge during a kill operation

A well control method in which fluid is pumped into the top of the wellbore and gas is vented off in step-bystep manner is commonly called: (a) (b) (c) (d)

9.

5,013 psi 5,213 psi 5,363 psi 6,013 psi

Bullheading Volumetric Method Lubricate and Bleed Method Engineer’s Method

A gas bearing formation is over-pressured by an artesian affect. Which of the following conditions has created the overpressure? (a) The formation water source is located at a higher level than the rig floor (b) The difference in density between gas and formation fluid (c) Compaction of the formation from the above laying formation

10.

We are about to bring the well “on choke”. Our kick sheet calculations tell us we should have 1200 psi Initial Circulating Pressure on the drill pipe when the pumps are up to the kill speed of 25 spm. What is the proper procedure for bringing the well on choke and establishing the Initial Circulating Pressure (Surface BOP stack)? (a) As the driller slowly increases the pump speed, the choke operator adjusts the choke so that he will have 1200 psi on the drill pipe gauge when the driller reaches 25 spm (b) As the driller slowly increases the pump speed, the choke operator adjusts the choke to maintain constant casing pressure. Once the pumps are up to speed and after the hydraulic delay, the correct ICP is shown on the drill pipe gauge

11.

The Volumetric Method is being employed to bring a gas influx to surface because circulation was impossible – no pipe in the hole. During a bleed step the choke operator should adjust the choke to accomplish what? (a) (b) (c) (d)

12.

A driller observes a warning sign for a kick. Why is it better to continue pumping while raising the pipe to the shut-in position? (a) (b) (c) (d)

13.

Bleed SICP back to the original shut-in value Bleed small amounts of mud through the choke until the SIDPP is back to the original shut-in value Bleed a “few barrels” of mud out of the annulus and see what happens Do nothing – carry the 300 psi as a safety factor

A vertical well with a surface BOP stack is shut-in after a gas kick has been taken. The bit is 950 ft off bottom and the influx is calculated to be from bottom to 300 ft above bottom. Shut-in drill pipe pressure is 450 psi. What will the most likely shut-in casing pressure be? (a) (b) (c) (d)

15.

To minimize downtime To minimize the amount of influx by keeping the annular pressure loss as long as possible The driller should shut-off the pump before picking up to identify the influx as soon as possible To prevent sticking the pipe

The well is shut-in on a gas kick and while preparing to begin the Wait and Weight Method, both SIDPP and SICP have risen by 300 psi due to gas migration. Before beginning to circulate, what must be done if constant bottomhole pressure is required? (a) (b) (c) (d)

14.

Allow SICP to rise by the calculated amount Allow SICP to fall by the calculated amount Hold SICP constant at the proper P choke value Bleed the calculated volume in a timely manner

The same as the shut-in drill pipe pressure Higher than the shut-in drill pipe pressure Lower than the shut-in drill pipe pressure Impossible to say if the exact location is not known

The principle involved in the CONSTANT BOTTOMHOLE PRESSURE method of well control is to maintain a pressure that is: (a) (b) (c) (d)

Equal to the slow rate circulating pressure At least equal to the formation pressure Equal to the shut-in drill pipe pressure At least equal to the shut-in casing pressure

16.

A vertical well with a surface BOP stack is shut-in after a kick. The pressure readings are as follows: Shut-in Drill Pipe Pressure Shut-in Casing Pressure

= =

680 psi 890 psi

What is the reason for the difference in these two pressures? (a) (b) (c) (d) 17.

Formation fluids can flow into the well if: (a) (b) (c) (d)

18.

The influx is in the drill pipe The influx has a lower density than the drilling fluid The influx has a higher density than the drilling fluid The BOP was closed too fast which caused trapped pressure

Formation pressure is greater than hydrostatic pressure Hydrostatic pressure is greater than formation pressure Answer “a” and the formation must have permeability Answer “b” and the formation must have porosity

A well is brought on choke correctly and afterward it is realized that the initial circulating pressure is higher than anticipated. This is diagnosed as a plugged jet. It is decided to proceed with this higher ICP and correct the FCP calculation. (Wait and Weight Method). Use the data below, calculate the corrected FCP. Observed ICP Calculated ICP SIDPP (a) (b) (c) (d)

19.

1500 psi 1150 psi 600 psi

Kill weight mud Original weight mud

= =

13.5 ppg 12.0 ppg

619 psi 1092 psi 1013 psi 782 psi

At what point during a well kill operation would you expect the highest pressure at the casing shoe? (a) (b) (c) (d)

20.

= = =

At initial shut-in When the top of the gas reaches the shoe When the kill weight mud reaches the bit Any of the above could be correct depending on wellbore geometry

From the following list, which “two” are considered advantages that the Wait and Weight Method of Well Control has over the Drillers Method of Well Control? (Choose two answers) (a) The Wait and Weight Method provides less "on choke" circulating time (b) The Wait and Weight Method always provides lower equivalent pressures at the casing shoe (c) Since the Wait and Weight Method is a "one circulation kill", less barite is utilized making it the cheaper method of killing a well (d) When the drill string volume is "less" than the annular open hole volume, the Wait and Weight Method will provide lower pressures at the casing

21.

During normal drilling operations, a 25 bbl slug of light drilling fluid is pumped into the drill string followed by original drilling fluid. DATA:

Well depth Drill pipe capacity Original mud weight Light mud weight

= = = =

10,000 feet 0.01776 bbl/ft 12.0 ppg 10.0 ppg

Calculate the bottomhole pressure once the light slug is inside the drill pipe. (a) (b) (c) (d) 22.

What is meant by Abnormal Pressure (over pressure) with regard to fluid pressure in the formation? (a) (b) (c) (d)

23.

Thick sandstone sections Insufficient mud weight Formation fluids supporting part of overburden weight All of the above

Which one of the following indications best suggest that mud hydrostatic pressure and formation pressures are almost equal? (a) (b) (c) (d) (e)

25.

The excess pressure due to circulating mud at high rates The excess pressure that needs to be applied to cause ‘leak-off’ into a normally pressured formation High density mud used to create a large overbalance Formation fluid pressure that exceeds normal water hydrostatic pressure

Abnormal formation pressures can be caused by: (a) (b) (c) (d)

24.

5,200 psi 5,347 psi 6,094 psi 6,240 psi

Increase in flow out of wellbore Drilled gas: Background gas, connection gas and trip gas Temperature anomalies Pit gain All of the above

Throughout the world what is the most common cause of abnormal formation pressures? (a) (b) (c) (d)

Thick sandstone sections Undercompacted shales Faults Uplifting / erosion

26.

The flow sensor shows a total loss of returns. You pick up and flow check. The mud level in the hole is out of sight. What action would you take: (a) (b) (c) (d)

27.

Which of the following statements best describes formation porosity? (a) (b) (c) (d)

28.

The ratio of the open spaces to the total volume of rock The ability of fluid and gas to move within the rock The presence of sufficient salt water volume to provide gas lift All of the above

Which of the following would be affected by the permeability of the formation from which a kick has occurred? (Pick two answers) (a) (b) (c) (d) (e)

29.

Pump at a reduced rate while mixing lost circulation Continue drilling blind Close the well in and check pressures Fill the annulus with fluid (either mud or water) noting how many barrels are required to fill the hole

The time taken for the shut-in pressure to stabilize The calculated kill mud density The Initial Circulating Pressure The size of the influx in the wellbore The shut-in drill pipe

What is the reason for circulating a kick out from the wellbore at a slow rate? (a) Obtain a smaller expansion of gas influx and thereby reduce casing pressure during the kill process (b) Create a sufficient pressure loss in the circulation system to give greater overbalance for a safer kill operation (c) Minimize excess pressure exerted on formations during the kill process

30.

Many factors should be considered when selecting a kill pump rate. However the objective should be to regain control of the well: choose the one answer that best meets this objective. (a) (b) (c) (d)

31.

By using the slowest pumping rate Before the end of the tour As safe as possible considering all aspects of the kill As fast as possible by using the maximum rate

Pick five (5) situations, from the following list, under which you would consider taking a new SCRP. (a) (b) (c) (d) (e) (f) (g) (h)

Every shift Mud weight changes Mud property changes Before and after a leak-off test After each connection when drilling with top drives When long sections of hole are drilled rapidly After recharging pulsation dampeners on mud pump discharge line When returning to drilling after a kick

32.

The following slow rate circulation pressures (SCRP) were recorded. correct? (a) 40 spm = (b) 30 spm = (c) 50 spm =

33.

Which one does not seem to be

180 psi 100 psi 400 psi

After a round trip at 8,960 ft. with 10.9 ppg mud we kick the pump in and start to circulate. An increase in flow was noticed and the well was shut in with 0 psi on the drillpipe and 300 psi on the casing. What kill mud is required? (There is no float in the drill string). (a) No way of knowing (b) 11.5 ppg (c) 10.9 ppg (d) 12.0 ppg

34.

What was most probable in causing the influx or well kick in the last question? (a) (b) (c) (d)

35.

Abnormal pressure was encountered The mud weight was not high enough to contain formation pressure It was swabbed in or the hole was not properly filled while pulling out It is impossible to tell

In which of the following cases would you be most likely to swab in a kick? (a) When the bit is pulled up into the casing (b) When the first few stands are being pulled off bottom (c) About halfway up the hole

36.

Which three of the following practices are likely to increase the chance of swabbing? (a) (b) (c) (d) (e) (f)

37.

Pulling pipe slowly Maintaining high mud viscosity Pulling through tight spots with pump off Pulling through tight spots with pump on Pulling pipe quickly Pumping out of the hole

Which one of the following causes of well kicks is totally avoidable and due to a lack of alertness by the driller? (a) Lost circulation (b) Gas cut mud (c) Not keeping hole full (d) Abnormal pressure

38.

In which of the following circumstances would a kick be most likely to occur through failure to fill the hole? (a) When the first few stands are pulled off bottom (b) When pulling the drill collars (c) When the drill collars enter the casing

39.

While pulling out of the hole it is noticed that mud required to fill the hole is less than calculated. What action must be taken? (a) (b) (c) (d) (e)

40.

Which of the following is the first reliable indication that you have taken a kick? (a) (b) (c) (d)

41.

Gas cut mud A drilling break A decrease in pump pressure Gain in pit volume Change in nature of cuttings

Of all the following warning signs, which two signs would leave little room for doubt that the well is kicking? (a) (b) (c) (d) (e) (f)

43.

Increase in torque Gas cut mud Decrease in pump pressure Increase in flow rate

Which of the following is the first reliable indication that an influx has entered the wellbore? (a) (b) (c) (d) (e)

42.

Flow check, if negative displace a 100 ft. heavy slug into annulus and continue to pull out of hole Flow check, if negative run back to bottom and monitor returns. Pump remaining stands out of hole Flow check, if negative continue to pull out of the hole Shut the well in and circulate hole clean

Flow line temperature increase Increased rotary torque Flow rate increase Decreased drill string weight Pit volume gain Increased rate of penetration

Which one of the following is NOT a warning sign of when a kick may be occurring? (a) (b) (c) (d)

Flow rate increase Increased torque Pit gain Well flowing with the mud pumps off

44.

It can be said that closing in the well promptly is one of the most important duties of a driller. Any delay may make the well potentially more difficult to kill. From the list of practices shown below, choose the six most likely to lead to an increase in the size of the influx. (a) Switching off the flow meter alarms (b) Regular briefing for the derrickman on his duties regarding the monitoring of pit levels (c) Drilling a further 20 ft. after a drilling break, before flow checking (d) Running regular pit drills for drill crew (e) Maintaining stab-in valves (f) Testing stab-in valves during BOP tests (g) Excluding the drawworks from the SCR assignment (h) Keeping air pressure on choke control console at 10 psi (i) Calling toolpusher to floor prior to shutting in the well (j) Not holding down master air valve on remote BOP control panel while functioning a preventer

45.

Which two of the following drilling practices should be considered when connection gas is noticed? (Choose two answers) (a) (b) (c) (d) (e)

46.

Which one of the following would not be a warning sign that the bottom hole pressure is approaching formation pressure? (a) (b) (c) (d)

47.

Pumping a low viscosity pill around bit to assist in reduction of balled bit or stabilizers Control drilling rate so that only one slug of connection gas is in the hole at any one time Pulling out of the hole to change the bit Raising the mud yield point Minimizing the time during a connection when the pumps are switched off

Increase in pump pressure Well flows with pumps off Increase in chloride content Increase in connection gas

While drilling along at a steady rate the derrickman asks to slow the mud pumps down so that the shakers can handle the increase in cuttings coming back in the returns. Which one of the following would be the safest course of action? (a) Continue at the same rate allowing the excess to bypass the shakers and get caught in the sand traps which can be dumped later (b) Pick up off bottom and check for flow, if there is not any then circulate bottoms up to a reduced rate so shakers can handle cuttings volume, flow-check periodically during circulation (c) Slow down the mud pump until the shakers can handle the volume of cuttings in the returns as requested by derrickman (d) Slow down the drilling rate and the pump rate until the shakers clear up then go back to the original drilling parameters

48.

In which situation would a pit gain be noticed? (a) Gas kick in an oil based mud (b) Gas kick in a water based mud

    2 1.

While tripping in, the actual volume of mud displaced is less than the calculated volume. What could be the cause of this? (a) The hole is flowing (b) A kick may have been swabbed in during the trip out (c) The formation is taking fluid

2.

If flow through the drillpipe occurs while tripping, what should the first action be? (a) (b) (c) (d)

3.

Pick up and stab the top drive Run back to bottom Close the annular preventer Stab a full opening safety valve

What is the correct meaning of the terminology “Secondary Well Control”? (a) Preventing flow of formation fluid into the well bore by maintaining drilling fluid hydrostatic pressure equal to or greater than formation pressure (b) Preventing flow of formation fluid into the well bore by maintaining the sum of drilling fluid hydrostatic pressure and dynamic pressure loss in the annulus equal to or greater than formation pressure (c) Preventing flow of formation fluid into the well bore by maintaining the dynamic pressure loss in the annulus equal to or greater than formation pressure (d) Preventing flow of formation fluid into the well bore by using BOP equipment in combination with hydrostatic pressure in the well bore to balance the formation pressure

4.

When tripping out of the hole, with 30 stands remaining it is noticed that the well is flowing. Which one of the following actions should be taken to close the well in using the soft shut-in? (a) Close the BOP, stab full opening safety valve, close the safety valve, open choke, record pressure (b) Stab a full opening safety valve, close the safety valve, open BOP HCR, close the BOP, close choke, record the pressure (c) Stab full opening safety valve, open BOP HCR, close BOP, close choke, record pressure. (d) Open BOP HCR, close BOP, stab full opening safety valve, close safety valve, close choke

5.

Which list below (a, b, c or d) describes how the choke manifold will most likely be set up for Soft Shut-in while drilling?

(a) (b) (c) (d)

BOP Side Outlet Hydraulic Valve (HCR)

Auto Choke (Remote Adj. Choke)

Degasser Valve

Open Open Closed Closed

Closed Open Open Closed

Closed Closed Open Open

6.

The difference between a hard shut-in and soft shut-in is that in the hard shut in: (a) (b) (c) (d)

7.

The main advantage of the soft shut-in procedure over the hard shut-in procedure is: (a) (b) (c) (d)

8.

The blind rams are used The blowout preventer is closed with the choke open The blowout preventer is closed with the choke closed The kick is diverted

To stop a “hydraulic shock” which might break down the formation To prevent further influx of formation fluids To allow pressures to be determined All of the above

When a kick occurs, why is it important to get the well shut-in as soon as possible? (a) A larger pit gain will result in a higher SIDPP resulting in a heavier kill mud weight (b) A larger pit gain will result in higher SIDPP and SICP (c) A larger pit gain will result in higher SICP but SIDPP will stay the same

9.

Which of the following parameters primarily affect the value of the shut-in casing pressure when a well is shut in during a kick? (Choose three answers) (a) (b) (c) (d) (e) (f)

10.

A hydraulic delay exists between the time the choke is adjusted to the time the drillpipe pressure reacts. This hydraulic delay is: (a) (b) (c) (d)

11.

Equal to the speed of sound About 1 second per 300 meters of travel time Always equal to 20 seconds This is a myth, no hydraulic delay actually exists

Mud weight increase required to kill a kick should be based upon: (a) (b) (c) (d)

12.

The pore pressure The bottom hole temperature The hole or annulus capacity The drill string capacity The kick volume The length of the choke line

Shut-in drill pipe pressure Shut-in casing pressure Original mud weight plus slow circulation rate pressure losses Shut-in casing pressure minus shut-in drill pipe pressure

The correct gauge to use for calculating the kill weight mud is: (a) (b) (c) (d) (e)

The gauge on the choke and kill manifold The drill pipe pressure gauge on the driller’s console The casing gauge on the driller’s console The drill pipe pressure gauge on the remote auto choke panel The casing pressure gauge on the remote auto choke panel

13.

A flowing well is closed in. Which pressure gauge reading is used to determine formation pressure? (a) (b) (c) (d)

14.

Shut-in casing pressure is used to calculate: (a) (b) (c) (d)

15.

BOP manifold pressure gauge Choke console drillpipe pressure gauge Driller's console drillpipe pressure gauge Choke console casing pressure gauge

Kill weight mud Influx gradient and type when influx volume and well geometry are known Maximum allowable annular surface pressure Initial circulating pressure

On a surface stack, what would happen if when bringing the pumps up to kill speed the casing pressure was allowed to fall below shut-in casing pressure? (a) Formation would most probably break down (b) More influx would be let into the wellbore (c) It would have no effect on anything

16.

Why is a 20 barrel kick in a small annulus more significant than a 20 barrel kick in a large annulus? (a) (b) (c) (d)

17.

The kill weight mud cannot be calculated as easily It results in higher annulus pressures The kicks are usually gas The pipe usually gets stuck

The slow circulating rate pressure (SCRP) is being determined by bringing the pump rate up to a predetermined 30 spm by holding the shut-in casing pressure constant. The well is shut-in with 220 psi shut-in drill pipe pressure. At 30 spm the drill pipe circulating pressure is 1060 psi. Calculate the slow circulating rate pressure. (a) (b) (c) (d)

18.

700 psi 770 psi 800 psi 840 psi

To find the initial circulating pressure on a surface BOP stack when the slow pump rate circulating pressure is not known and a kick has been taken: (a) Circulate at desired strokes per minute to circulate out the kick, but hold 200 psi back pressure on drill pipe side with choke (b) Add 400 psi to casing pressure and bring pump up to kill rate while using the choke to keep the casing pressure +400 constant (c) Bring pump strokes up to kill rate while keeping casing pressure constant by manipulating the choke. After the hydraulic delay, the pressure shown on the drill pipe pressure gauge is the Initial Circulating Pressure (d) Add 1,000 psi to shut in drill pipe pressure and circulate out the kick

19.

If, while waiting for kill mud to be mixed, both drillpipe and annulus pressures started to rise, what type of influx does this indicate? (a) (b) (c) (d)

20.

Company policy states, "... when killing a well you will always attempt to kill the well using a method that minimizes the pressure on the stack and upper casing". Which method would you choose? (a) (b) (c) (d)

21.

At initial shut-in When kill mud reaches the bit When kill mud reaches the casing shoe When top of gas reaches the shoe

We are planning to circulate a kick with the wait & weight method. The volume of the surface lines on this rig is 20 bbls. Identify the best procedure for dealing with the volume of the surface lines? (a) (b) (c) (d)

23.

Wait and Weight Drillers Lubricate and bleed Volumetric

At what point while correctly circulating out a gas kick is it possible for the pressure at the casing shoe to be at its maximum? (Select three answers) (a) (b) (c) (d)

22.

Fresh water Salt water Oil Gas

Re-zero the stroke counter once kill mud reaches the bit Subtract 20 bbls (adjusted for pump strokes) from the strokes-to-bit total on the kill sheet Ignore 20 bbls and use it as a safety factor Re-zero the stroke counter when kill mud starts down the drillpipe

Why do we need to take into account a large surface line volume (from the mud pumps to the drill floor) when preparing a kill sheet for killing the well with the Wait & Weight Method? (Choose two answers) (a) (b) (c) (d) (e)

If we don’t, following the drill pipe pressure graph will result in a BHP too low If we don’t, there will be no effect on the bottom-hole pressure. If we don’t, following the drill pipe pressure graph will result in a BHP too high If we don’t, the total time for killing the well will be shorter than calculated If we don’t, the total time for killing the well will be longer than calculated

You are circulating out a gas kick using the wait and weight method. What will happen to bottom-hole pressure in each of the following situations? 24.

If drillpipe is held constant while kill mud is being pumped to the bit. (a) Increase (b) Decrease (c) Stay the same

25.

If drillpipe pressure is held constant while kill weight mud is being pumped up the annulus. (a) Increase (b) Decrease (c) Stay the same

26.

If SPM is increased and Drillpipe pressure is held constant. (a) Increase (b) Decrease (c) Stay the same

27.

If the gas bubble is not allowed to expand. (a) Increase (b) Decrease (c) Stay the same

28.

While killing a well, as pump speed is increased, what should happen to casing pressure in order to keep bottom hole pressure steady? (a) Casing pressure should be held steady during SPM change (b) Casing pressure should be allowed to rise during SPM change (c) Casing pressure should be allowed to fall during SPM change

29.

A gas kick is being circulated up the hole. What is surface pit volume most likely to do? (a) Increase (b) Stay the same (c) Decrease

30.

Why must the pit volume be monitored during a kick killing operation? (a) (b) (c) (d)

31.

To determine kill weight mud To determine influx volume To determine if lost returns occurs To determine the gain due to barite additions

When starting the kill operation with a surface BOP, the choke pressure is kept constant while bringing the pump up to speed. The drill pipe gauge now reads 250 psi higher than the pre-calculated initial circulating pressure (ICP). To maintain constant BHP, what is the best action to take? (a) Open the choke and let the standpipe pressure drop to the pre-calculated value (ICP) (b) Continue to circulate with the new ICP and adjust the drill pipe pressure graph accordingly (c) There will now be 250 psi overbalance on the bottom which is acceptable. Nothing needs to be done

32.

You have to increase the drillpipe pressure by approximately 100 psi by manipulating the choke, during a well kill operation. Of the following options, which one would you choose? (a) Keep closing the choke until you see the drillpipe pressure start to rise (b) Increase the choke pressure by 100 psi and wait for the drillpipe pressure to rise

33.

A well is being killed correctly, using a constant bottom hole pressure method. At what stage during a kill operation can choke pressure readings exceed MAASP without affecting Casing Shoe integrity? (a) (b) (c) (d)

34.

Kill mud circulated to bit Influx is in annulus above casing shoe Influx is on bottom Influx is in open hole section

A kick is being circulated out at 30 SPM, Drill Pipe Pressure reads 550 psi, and casing pressure 970 psi. It is decided to slow the pumps to 20 SPM while maintaining 970 psi on the casing gauge. How will this affect bottom-hole pressure (exclude any ECD effect)? Pick one answer. (a) Increase (b) Decrease (c) Stay the same (d) No way of telling

35.

Well Data: Slow rate circulation pressure = 500 psi at 40 strokes/min The well has been shut-in after a kick Shut-in Drill Pipe Pressure = 800 psi Shut-in Casing Pressure = 1,100 psi Circulation is started with the original mud. While the pump is being brought up to 40 strokes/min, which pressure has to remain constant to maintain the correct bottom-hole pressure? (a) (b) (c) (d)

36.

800 psi on the drill pipe gauge 2,300 psi on the drill pipe gauge 1,100 psi on the casing gauge 1,600 psi on the casing gauge.

If a well was closed in after the first circulation of the driller's method, what value would you expect on the drill pipe and casing pressure gauges? (a) Shut in drill pipe pressure = 0 psi; shut in casing pressure = 525 psi (b) Both pressures should be equal to the original shut in drill pipe pressure. (c) Both pressures should read zero.

37.

On the second circulation of the driller's method if the casing pressure was held constant until the kill mud reached surface, what would happen to the bottom hole pressure? (a) Increase (b) Decrease (c) Stay the same

38.

A well is being killed using the Driller’s method. Original Shut-in Drill Pipe Pressure = 500 psi Original Shut-in Casing Pressure = 900 psi After the first circulation the well is shut-in and pressures allowed to stabilize. They then read: Shut-in Drill Pipe Pressure = 500 psi Shut-in Casing Pressure = 650 psi It is decided not to spend any more time cleaning the hole. Which one of the following actions should be taken? (a) (b) (c) (d)

39.

A saltwater kick is circulated out using the Drillers method. The drill string consists of drill collars plus drill pipe and a surface BOP stack is used. When will the surface casing pressure be at its maximum value? (Assume there is gas in the salt water kick.) (a) (b) (c) (d) (e)

40.

Prepare to use the wait and weight method Bullhead annulus until shut-in casing pressure is reduced to 500 psi Reverse circulate until shut-in casing pressure is reduced to 500 psi Continue with second circulation of driller’s method (holding casing pressure constant until kill mud reaches the bit)

When the kill fluid is entering the drill pipe When the kick has been circulated to the surface Only when a kick reaches the casing shoe Just after the kill fluid reaches the bit Immediately after the well has been shut in

Which statement is correct when comparing the Drillers method and the Wait & Weight method? (a) The Drillers method will give the lowest casing shoe pressure when the open hole annulus volume is larger than the drill string volume (b) The Wait & Weight method will give the lowest casing shoe pressure when the open hole annulus volume is smaller than the drill string volume (c) The Wait & Weight method will give the lowest casing shoe pressure when the open hole annulus volume minus the gain is larger than the drill string volume (d) The Wait & Weight method will always give a lower maximum pressure on the casing shoe than the Drillers method

For each of the following statements note whether it relates to the Drillers M ethod or the Wait and Weight Method. 41.

Minimize pressures generated in the annulus due to gas expansion. (a) Drillers (b) Wait and Weight

42.

Remove influx from hole before pumping kill mud. (a) Drillers (b) Wait and Weight

43.

Pump kill mud while circulating influx up the a nnulus. (a) Drillers (b) Wait and Weight

44.

Maintain Drill Pipe pressure constant for 1st circulation. (a) Drillers (b) Wait and Weight

45.

Under which circumstances would the Wait and Weight Method provide lower equivalent pressures at the casing shoe than the Drillers Method? (a) When the drill string volume is greater than the annulus open hole volume (b) When the drill string volume is less than the annulus open hole volume (c) The pressures at the casing are the same regardless of the method used

46.

The main purpose of a diverter system is to: (a) Shut the well in (b) Divert shallow gas over the side (c) To prevent gas entering the wellbore

47.

Kicks taken while drilling shallow formations should be: (a) (b) (c) (d)

Closed in with the Hydril Closed in with the rams Ignored Diverted

Answer questions 48-49 using the information below and the graphic to the right. Gradient of gas section: 0.1 psi/ft Gradient of top shale section: 0.7 psi/ft Gradient of bottom shale section: 0.68 psi/ft MW Required at 7500 ft: 13.5 ppg 48.

If 13.5 ppg mud weight is needed to balance formation pressure at the bottom of the shale section (7500 feet), what is the formation pressure at the bottom of the gas leg (8100 feet)? (a) (b) (c) (d)

49.

psi psi psi psi

If the initial overbalance at 7500 feet is 30 psi and the well is drilled to 8500 feet with 13.5 ppg mud, what is the overbalance at 8500 feet? (a) (b) (c) (d)

50.

5265 5325 5626 5686


Using the Driller’s Method, after the 2 nd circulation, kill mud has been circulated up the choke line to the surface, which two of the following steps should be taken? (a) Displace the riser with Kill Mud. (b) Displace Kill Line with Kill Mud, verify there is no pressure under the BOP’s, and then open the BOPs. (c) Flush out the BOP stack to remove any trapped gas, circulate kill mud back to the surface, verify there is no pressure under the BOP’s and then open the BOPs. (d) Conduct a BOP test

    3 1.

While preparing to circulate Kill Weight Mud the gas bubble begins to migrate. If no action is taken, what will the pressure in the gas bubble do as the gas rises? (a) Increase (b) Decrease (c) Remain approximately the same

2.

What will happen to bottom-hole pressure? (a) Increase (b) Decrease (c) Remain approximately the same

3.

What will happen to shut-in casing pressure? (a) Increase (b) Decrease (c) Remain approximately the same

4.

What will happen to pressure on the casing seat? (a) Increase (b) Decrease (c) Remain approximately the same

5.

If it is decided to use the correct volumetric procedure, that is, bleed enough mud to keep the drill pipe pressure constant at 450 psi, (SIDPP = 350 plus 100 psi safety margin). What would the pressure in the bubble do as the gas rises? (a) Increase (b) Decrease (c) Remain approximately the same

6.

What would happen to bottom-hole pressure? (a) Increase (b) Decrease (c) Remain approximately the same

7.

What would happen to shut-in casing pressure? (a) Increase (b) Decrease (c) Remain approximately the same

8.

What would happen to pressure on the casing seat while the bubble is still below the casing shoe? (a) Increase (b) Decrease (c) Remain approximately the same

9.

What would happen to the pressure on the casing seat as the bubble is passing from the open hole into the casing? (Note: some influx is in the open hole and some is in the casing). (a) Increase (b) Decrease (c) Remain approximately the same

10.

What would happen to pressure on the casing seat while the bubble is above the casing shoe? (a) Increase (b) Decrease (c) Remain approximately the same

11.

If the original closed in pressures were 300 psi drill pipe and 500 psi on annulus and both started rising close to maximum allowable, would you: (a) Bleed off until annulus pressure was 500 psi (b) Bleed off until drill pipe pressure was 300 psi (c) Bleed off until annulus pressure was 300 psi

12.

A gas kick has been taken in a well with a large open hole section. After a short time the drillpipe becomes plugged – presumably by debris blocking the bit. Drill pipe pressure cannot be read and no pumping is possible down the drill pipe. There is evidence of gas migration taking place. Which one of the following well control procedures can be applied? (a) (b) (c) (d)

13.

Driller’s Method Lubricate and Bleed technique Wait and Weight Method Volumetric technique

The well has been shut in after a kick. Slow rate circulation pressure = 500 psi at 40 strokes/min Shut-in Drill Pipe Pressure = 800 psi Shut-in Casing Pressure = 1,100 psi Before starting to kill the well, there is a complete failure of the pumps. Which pressure has to remain constant in order to maintain the correct bottom-hole pressure if the influx migrates? (a) 1,600 psi at the casing gauge (b) 1,100 psi at the casing gauge (c) 1,300 psi at the drill pipe gauge (d) 800 psi at the drill pipe gauge

14.

While drilling ahead, a heavy mud pill is circulated in the well without stopping the pump at any time. At what moment will the bottom-hole pressure start to increase? (a) As soon as the pill starts to be pumped into the drill string (b) Once the entire pill is in the annulus (c) Once the pill starts to be displaced into the annulus

15.

While drilling ahead, a light mud pill is circulated in the well without stopping the pump at any time. At what moment will the bottom-hole pressure start to decrease? (a) As soon as the pill starts to be pumped into the drill string (b) Once all the pill has been displaced into the annulus (c) Once the pill starts to be displaced into the annulus

16.

A kick was taken and is being circulated out in a deep well with casing set very deep. The casing pressure is approaching the maximum allowable annular surface pressure. The influx is still in the open hole. Of the actions listed below, which one would be the most appropriate to take at this time? (a) Start pumping mud that is a least 2 ppg higher than the kill Weight mud down the drill pipe (b) Maintain the casing pressure at the maximum allowable pressure value by adjusting the choke (c) Minimize any extra pressure in the annulus without allowing bottomhole pressure to drop below formation pressure

17.

Which one of the following best describes the Volumetric Method of Well Control? (a) (b) (c) (d)

18.

While drilling ahead a well kicks and is shut-in. Drill pipe and casing pressure start rising but before stabilizing both start dropping quite rapidly. What has probably happened? (a) (b) (c) (d)

19.

Maintains a constant pressure in the influx as it migrates up the wellbore Maintains a constant BHP as the influx migrates up the wellbore Maintains a constant casing pressure as the influx migrates up the wellbore Maintains a constant pressure at the casing shoe as the influx migrates up the wellbore

The drill string has parted The bottomhole assembly has packed off A weak formation has broken down The pressure gauges have both malfunctioned

The well has been shut-in on a swabbed kick while pulling the pipe out of the hole. The SIDPP and SICP are both reading 350 psi. The bit is 30 stands off bottom. Which one of the following would be the safest course of action to take in order to bring the well back under primary control? (a) Calculate KWM using 350 psi and circulate the well out at that depth using the wait and weight method of well control (b) Bring the well on choke by holding the casing pressure constant as the pump is brought up to kill rate. Then circulate the influx out using the drillers method of well control (c) Strip the pipe back to bottom using proper stripping procedures then circulate the influx out using the drillers method of well control

20.

While drilling a gas kick is taken and the well is shut-in. SIDPP = 300 psi SICP = 475 psi There is a total pump failure and the influx starts to migrate up the hole, the drill pipe and casing pressure start to increase. If the casing pressure is kept constant by adjusting the choke, what affect will this have on the BHP? (a) It will stay constant (b) It will increase (c) It will decrease

21.

While in the process of killing a well, partial loss of returns occurs. What can be done to reduce the pressure at the loss zone? (a) Reduce the pump speed thus reducing the annular friction pressure (b) Keep the drill pipe pressure as close to the actual pressure that is supposed to be on the drill pipe gauge. No safety factors (c) Use the exact mud density required to kill the well. No safety factors (d) All of the above

22.

If flow rate is kept constant, which two of the following factors will increase the circulation pressure? (a) (b) (c) (d)

23.

Which one of the following actions taken while stripping into the hole will help maintain an acceptable bottom-hole pressure? (a) (b) (c) (d)

24.

Kelly cock in closed position Kelly cock in open position Inside BOP with Kelly cock in open position Inside BOP with Kelly cock in closed position

Gas cut drilling mud normally does not reduce the bottom-hole pressure enough to cause a well kick. But the bottom-hole pressure is reduced most when: (a) (b) (c) (d)

26.

Pumping a volume of mud into the well, equal to the drillpipe closed end displacement at regular intervals Bleeding off the drillpipe steel displacement at regular intervals Pumping a volume of mud into the well, equal to the drillpipe steel displacement, at regular intervals Bleeding off the drillpipe closed end displacement at regular intervals

When stripping pipe into the hole, which valve should be used? (a) (b) (c) (d)

25.

When the mud density in the well is lowered When the drilled depth is increased When the bit nozzle size is increased When the length of drill collars is increased

The gas is near the surface The gas is at or near the bottom The gas is about halfway up the wellbore All are about the same

Problems that occur during a killing operation may affect the parameters you are monitoring at surface. State the immediate effect on the drillpipe pressure, casing pressure and bottomhole pressure if there is a choke washout. (a) Increase (b) Decrease

27.

Problems that occur during a killing operation may affect the parameters you are monitoring at surface. State the immediate effect on the drillpipe pressure when casing pressure and bottomhole pressure remain constant and there is a nozzle blowout. (a) Increase (b) Decrease

28.

Problems that occur during a killing operation may affect the parameters you are monitoring at surface. State the immediate effect on the drillpipe pressure, casing pressure and bottomhole pressure if there is a choking plugging. (a) Increase (b) Decrease

29.

Problems that occur during a killing operation may affect the parameters you are monitoring at surface. State the immediate effect on the drillpipe pressure when casing pressure and bottomhole pressure remain constant and there is nozzle plugging. (a) Increase (b) Decrease

30.

During the well kill operation, slowly but regularly you have had to reduce choke size because the drill pipe and casing pressures keep dropping with constant pump strokes. What is a likely cause of this? (a) A bit nozzle is washing out (b) The choke is washing out (c) You have a washed out pump swab

31.

Which of the following parameters can be affected by a string washout during a well kill operation? (Pick two answers) (a) (b) (c) (d)

32.

How is a choke washout recognized? (a) (b) (c) (d)

33.

Bottom-hole pressure Kick tolerance Formation fracture pressure Low circulating rate pressure

Rapid rise in casing pressure with no change to drillpipe pressure Increase in drillpipe pressure with no change to casing pressure Continually having to open choke to maintain drillpipe and casing pressure Continually having to close choke to maintain drillpipe and casing pressure

A kick is being circulated from a well using the Drillers method; pumping pressure having been established as 1,000 psi at 30 spm. During the operation pressure suddenly increases to 1,350 psi. You are reasonably sure that a nozzle of the bit is plugged. What should you do? (a) (b) (c) (d)

Reduce pump pressure to 1000 psi by adjusting the choke Shut the well in and re-establish the pumping pressure Hold casing pressure constant at the value recorded just before the bit plugged (a) and (b) are acceptable courses of action

34.

A well is being killed using the Drillers method. During the first circulation the drill pipe pressure is kept constant at 690 psi and the pump speed at 30 spm. Halfway through this first circulation the operator on the choke observes a sudden increase in drill pipe pressure. There is no significant change in choke pressure and the pump speed is still 30 spm. What could have happened? (select three answers) (a) (b) (c) (d) (e) (f)

35.

During a well kill operation, using the Drillers method, the choke pressure suddenly increases by 150 psi. Shortly thereafter the operator observes the same pressure increase on the drill pipe pressure gauge. What is the most likely cause for this pressure increase? (a) (b) (c) (d) (e)

36.

The bit nozzles have partly plugged The choke has partly plugged The kick is about to enter the choke A partial blockage in the kelly hose Pressure has built up in the mud/gas separator A partial blockage in the drill string has occurred

A second influx entered the well A restriction in the kelly hose A plugged nozzle in the bit The choke is partly plugged A wash out in the drill string

During a kill, while displacing the drill string with kill fluid, a sudden loss in drillpipe pressure was noticed. The driller continued pumping at the same pump rate, while the supervisor adjusted the choke and continued to follow the drillpipe pressure graph as originally planned. What happened to the bottom-hole pressure as a result of this? (a) (b) (c) (d) (e)

37.

The bottom-hole pressure increased then decreased The bottom-hole pressure remained unchanged The bottom-hole pressure decreased The bottom-hole pressure decreased then increased The bottom-hole pressure increased with the choke adjustment

Of the following, which one would require opening the choke and shutting in the well? (a) (b) (c) (d) (e) (f)

Bit nozzle plugged Bit nozzle washout Washout in drill string Pump failure Choke plugged Choke washout

38.

During a kill operation, the choke operator notices the drill pipe pressure rises sharply, though the casing pressure is steady. He reacts by opening up the choke to maintain correct pumping pressure. This situation continues with increasing regularity. The choke operator notices that during this operation the choke has been adjusted from 1/4 open to 5/8 open. What is the likely cause of this problem? (a) Choke plugging (b) Choke washout (c) Pipe washout (d) Nozzle plugging

39.

While circulating a kick the choke operator has been continually closing the choke in order to maintain the correct drill pipe circulating pressure. The mud logger reports that both drill pipe and casing pressure have been increasing. Note: the choke operators gauges operate from a different sensor than the mud logger. A check of the gauges on the standpipe and choke manifold confirm the mud loggers report. Which is the most likely explanation? (a) (b) (c) (d)

40.

Lost circulation during a well control operation is usually detected by: (a) (b) (c) (d)

41.

Monitoring the return flow with the flowshow Monitoring the mud volume in the mud tanks Monitoring the pump speed indicator Monitoring the weight indicator

A kick has been taken and it is known that a potential lost circulation zone exist in the open hole. Select correct actions, which can be taken to minimize pressure in the annulus during the kill operation. (a) (b) (c) (d)

42.

The choke is washing out The choke operators gauge sensor is malfunctioning The choke is plugging The mud loggers gauge sensors are malfunctioning

two

Maintain extra backpressure on the choke for safety Use the wait and weight method Choose a lower circulating rate Choose a higher circulating rate

Does a kick always occur in the event of a total loss of circulation? (a) Yes, losses will always occur above any potential kick zone (b) No, it depends on the drill string weight reduction noted on the weight indicator (c) No, it depends on the mud level in the annulus and the formation pressure

43.

While running pipe back into the hole, it is noticed that the normal displacement of mud into the trip tank is less than calculated. After reaching bottom and commencing circulation the return flow meter is observed to reduce from 50% to 42%. A pit loss of 2 barrels is noted. What is the most likely cause of these indications? (a) (b) (c) (d)

Partial lost circulation has occurred Total lost circulation has occurred A kick has been taken The well has been swabbed

ANSWER 

  

  

1. B

35. D

69. B

1. C

35. D

69. B

2. C

36. B

70. A

2. A

36. B

70. A & E

3. B

37. D

71. A

3. B

37. D

71. C

4. D

38. A

72. A

4. A

38. D

72. D

5. A & C

39. C

73. A

5. A

39. C

73. B

6. D

40. C

74. A

6. C

40. A

74. C

7. C

41. B

75. B

7. B

41. C

75. B

8. A

42. A

76. B

8. B

42. C

76. C

9. B

43. A

77. A

9. A

43. A

10. B

44. A

78. A

10. A

44. A

11. C

45. C

79. A

11. B

45. D

12. C

46. B

80. B

12. B & C

46. C

13. A

47. B

81. C

13. A & B

47. C

14. B

48. C

82. D

14. A

48. E

15. E

49. C

83. D

15. C

49. B

16. B

50. B

84. C

16. D

50. A

17. D

51. B

85. C

17. A

51. B

18. C

52. A

86. A

18. C

52. D

19. B

53. B

87. C

19. D

53. C

20. B

54. C

88. C

20. A

54. A

21. D

55. A

89. B & C & D

21. C

55. B

22. C

56. A

90. A

22. B

56. A

23. A

57. B

91. B

23. D

57. A

24. D

58. C

92. B

24. A

58. A & B

25. E

59. D

93. B

25. B

59. D

26. B

60. C

26. A

60. B & C

27. C

61. A

27. B

61. A

28. B & D

62. C

28. B

62. B

29. B

63. D

29. D

63. B

30. D

64. A

30. B

64. B

31. B

65. B

31. B

65. D

32. B

66. B

32. C

66. C

33. A

67. A

33. C

67. D

34. B

68. A

34. B

68. D

 

G 

   1

1. A

1. B

1. D

38. B

2. B

2. C

2. B

39. B

3. C

3. A

3. C

40. D

4. A

4. B

4. C

41. D

5. A

5. B

5. B

42. C & E

6. B

6. A

6. C

43. B

7. C

7. A

7. B

44. A,C,G,H,I,J

8. C

8. C

8. C

45. B & E

9. B

9. B

9. A

46. B

10. D

10. E

10. B

47. B

11. A

11. A

11. C

48. B

12. C

12. D

12. B

13. A

13. C

13. B

14. C

14. B

14. A

15. A

15. C

15. B

16. B

16. B

16. B

17. D

17. B

17. C

18. B

18. B

18. C

19. C

19. E

19. D

20. C

20. C

20. A & D

21. C

21. A

21. D

22. B

22. E

22. D

23. B

23. D

23. C

24. B

24. A

24. C

25. C

25. B

25. B

26. C

26. D

26. D

27. C

27. C

27. A

28. A

28. D

28. A & D

29. B

29. B

29. C

30. C

30. C

31. D

31. B,C,F,H

32. A

32. C

33. B

33. C

34. E

34. C

35. E

35. B

36. B

36. B & E

37. B

37. C

38. C 39. D 40. C

   2

   

  

1. C

38. A

1. C

38. D

1. A

2. D

39. B

2. A

39. B

2. B

3. D

40. C

3. A

40. B

3. A

4. B

41. B

4. A

41. B & C

4. B

5. C

42. A

5. B

42. C

5. B

6. C

43. B

6. C

43. A

6. C

7. A

44. A

7. A

7. A

8. C

45. B

8. A

8. B

9. A,C,E

46. B

9. B

9. B

10. B

47. D

10. C

10. B

11. A & D

48. B

11. B

11. B

12. D

49. D

12. D

12. D

13. B

50. A & C

13. D

13. D

14. B

14. C

14. D

15. B

15. C

15. E

16. B

16. C

16. C

17. D

17. B

17. C

18. C

18. C

18. C

19. D

19. C

19. B

20. A

20. C

20. B

21. A,B,D

21. D

21. B

22. D

22. D

22. B

23. A & E

23. D

23. B

24. A

24. C

24. B

25. C

25. A

25. A

26. B

26. B

26. A

27. A

27. B

27. C

28. A

28. A

28. B

29. A

29. A

29. C

30. C

30. B

30. D

31. B

31. A & D

31. C

32. B

32. D

32. B

33. B

33. B

33. A

34. C

34. A,D,F

34. B

35. C

35. D

35. A

36. B

36. E

36. A

37. A

37. E

37. B 38. B 39. A 40. D

ICWF Study Pack

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