Operator Assessment Exam

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Downhole Equipment1. As per 30 CFR 250, what is the interval for testing SCSSV’s?
- Not to exceed one month
- Not to exceed 6 months
- Not to exceed 1 year

About This Quiz

The 'Operator Assessment Exam' focuses on the operational standards and safety protocols for downhole equipment in the oil and gas industry. It assesses knowledge on SCSSV testing intervals, leakage rates, pressure monitoring, and equipment requirements under specific conditions, aligning with industry compliance.

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2.

Downhole Equipment2. A SCSSV has an allowable leakage rate?
- True
- False
Correct Answer

A. True

Explanation

A SCSSV (Surface Controlled Subsurface Safety Valve) is a type of safety valve used in oil and gas wells to prevent the uncontrolled release of fluids. It is designed to close automatically in the event of an emergency, such as a blowout or equipment failure. The allowable leakage rate refers to the amount of fluid that is allowed to pass through the valve when it is closed. In order to ensure the valve is functioning properly, a small amount of leakage is permitted. Therefore, the statement "A SCSSV has an allowable leakage rate" is true.

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2
3.

Downhole Equipment3. What must be done when pressure is first observed on any of the casing strings?
- Notify MMS
- Perform a diagnostic test
- Monitor Monthly
- All of the above
Correct Answer

A. Notify MMS

Explanation

When pressure is first observed on any of the casing strings, it is important to notify MMS. This is because pressure could indicate a potential issue or problem with the casing strings, and MMS needs to be informed so that appropriate actions can be taken to address the situation. Performing a diagnostic test and monitoring monthly may also be necessary, but the immediate action should be to notify MMS.

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3
4.

Downhole Equipment 4. All wells capable of natural flow need to have a ________ or ________installed in the tubing at least 100 feet below the mud line.
- SCSSV or Plug
- GLV or SSV
- SCSSV or SSCSSV
- All of the Above
Correct Answer

A. SCSSV or SSCSSV

Explanation

All wells capable of natural flow need to have a SCSSV (Surface Controlled Subsurface Safety Valve) or SSCSSV (Surface Controlled Subsurface Safety Valve) installed in the tubing at least 100 feet below the mud line. These safety valves are crucial in preventing uncontrolled flow of fluids from the well, ensuring the safety and integrity of the wellbore.

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4
5.

Downhole Equipment 5. When a well will no longer flow on it’s own, gas lift gas is the most common source of lift available to continue production offshore.
- True
- False
Correct Answer

A. True

Explanation

Gas lift is a common method used to continue production offshore when a well can no longer flow on its own. It involves injecting gas into the wellbore to reduce the density of the fluid column and lift the reservoir fluids to the surface. This helps to maintain production and ensure the flow of hydrocarbons from the well. Therefore, the statement "True" is the correct answer.

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1
6.

Downhole Equipment6. Under what conditions may a well be flowed with the SCSSV locked out or the SSCSV removed?
- During routine wireline operations
- No flow wells
- Both 1 & 2
Correct Answer

A. Both 1 & 2

Explanation

A well may be flowed with the SCSSV locked out or the SSCSV removed under both conditions 1 and 2. This means that during routine wireline operations or in the case of no flow wells, the well can still be flowed even if the SCSSV is locked out or the SSCSV is removed.

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1
7.

Downhole Equipment 7. As wells age, their flowing characteristics change. When this happens oil and gas rates usually go down and water rates increase. Which of the following explains what causes good wells to become loaded up.
- Water drive well, water increases.
- BHP is unable to overcome the hydrostatic head when heavier fluids enter the well bore.
- Good wells will always flow no matter how much water enters well bore.
- Bottom hole pressure continues to increase as the well gets older.
Correct Answer

A. BHP is unable to overcome the hydrostatic head when heavier fluids enter the well bore.

Explanation

As wells age, heavier fluids such as water enter the well bore. The bottom hole pressure (BHP) is the pressure at the bottom of the well, and it needs to overcome the hydrostatic head of the heavier fluids in order to continue flowing. However, as the well gets older, the BHP may not be able to overcome the hydrostatic head, causing the well to become loaded up and leading to a decrease in oil and gas rates and an increase in water rates.

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1
8.

Downhole Equipment 8. Name three noticeable changes that can be seen to warrant an operator to check a positive choke that may be cut out?
- Decrease flowing tubing psi, increase water production, increase gas production.
- Decrease flowing tubing psi, lower gas production, lower total fluid production.
- Increase flowing tubing psi, increase gas production, lower total fluid production.
- Increase flowing tubing psi, increase BHP, increase casing pressure.
Correct Answer

A. Decrease flowing tubing psi, increase water production, increase gas production.

Explanation

The correct answer is "Decrease flowing tubing psi, increase water production, increase gas production." These three noticeable changes can indicate a potential issue with the positive choke that may require checking or replacement. A decrease in flowing tubing psi suggests a decrease in pressure, which could be caused by a problem with the choke. An increase in water production and gas production may also indicate a problem with the choke, as it may not be effectively controlling the flow of fluids and gases. Therefore, these changes serve as indicators for the operator to inspect the positive choke.

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1
9.

Downhole Equipment 9. Problem, a gas lift well has had a history of making C O 2 and now has holes in the tubing. The holes have been sealed with pack-offs. You are unable to maintain gas lift pressure to lift the well, gases around. What do you believe has started to happen to this well?
- Pack offs are leaking.
- More holes have developed in the tubing above the liquid level
- There is a problem with one of the gas lift valves.
- More than likely, All of the above.
Correct Answer

A. More than likely, All of the above.

Explanation

Based on the given information, the well has a history of making CO2 and now has holes in the tubing. The holes have been sealed with pack-offs, but the gas lift pressure is unable to maintain, causing gases to leak. Therefore, it is possible that the pack-offs are leaking, more holes have developed in the tubing above the liquid level, and there is a problem with one of the gas lift valves. Hence, the most likely scenario is that all of the above issues are occurring in this well.

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2
10.

Downhole Equipment 10. Under what circumstances may the MMS district supervisor grant permission to lock out a SCSSV and install a SSCSV?
- The SCSSV is leaking and is a tubing retrievable safety valve.
- The well has been depleted and will no longer produce oil & gas.
- During hurricane season.
Correct Answer

A. The SCSSV is leaking and is a tubing retrievable safety valve.

Explanation

The MMS district supervisor may grant permission to lock out a SCSSV and install a SSCSV when the SCSSV is leaking and is a tubing retrievable safety valve. This indicates that there is a safety concern with the SCSSV, and replacing it with a SSCSV would ensure the safety and integrity of the well. The other two options, the well being depleted and hurricane season, do not directly relate to the need for replacing the SCSSV.

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11.

Downhole Equipment 11. Problem, you have a flowing gas well that flows cold enough in the winter to cause hydrates in the choke body. Methanol has been injected through the colder winter months to keep the choke body from freezing up. You have been asked to increase the size of the choke in this well. About an hour after increasing the choke size the well has shut in on a PSH on the flow line pilot. What could have caused the high pilot to shut in this well?
- Increased choke size raised pressure in the flowline above the pilot set point.
- Methanol injection rate was not increased and hydrates have formed in the line.
- Both 1 and 2.
- Neither 1 or 2.
Correct Answer

A. Both 1 and 2.

Explanation

The increased choke size caused an increase in pressure in the flowline, which exceeded the set point of the pilot. This caused the pilot to shut in the well. Additionally, the methanol injection rate was not increased, allowing hydrates to form in the line. Both factors, the increased pressure and the formation of hydrates, contributed to the shut-in of the well.

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2
12.

Downhole Equipment 12. A gas flow chart recorder is used to measure the volume of gas lift gas and also indicates the performance of the gas lift valves. Describe how the chart can indicate gas lift valve performance.
- Static pen indicates flow rate and differential pen indicates valve operation.
- Differential pen indicates flow rate and static pen indicates valve operation.
- Doesn’t matter which pen you use.
Correct Answer

A. Differential pen indicates flow rate and static pen indicates valve operation.

Explanation

The correct answer is that the differential pen indicates flow rate and the static pen indicates valve operation. This means that the chart recorder measures the difference in pressure between the gas lift gas and the wellbore pressure, which is represented by the differential pen. This differential pressure is directly related to the flow rate of the gas. On the other hand, the static pen indicates the opening and closing of the gas lift valves, which affects the performance of the gas lift system. Therefore, by analyzing the chart, one can determine both the flow rate and the performance of the gas lift valves.

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1
13.

Downhole Equipment 13. What is the maximum time allowed as per 30 CFR for the SCSSV to close after the ESD has been activated?
- 2 min 45 sec
- 1 min 15 sec
- 2 min
- 1 min 45 sec
Correct Answer

A. 2 min 45 sec

Explanation

The maximum time allowed for the Subsurface Controlled Safety Valve (SCSSV) to close after the Emergency Shutdown (ESD) has been activated is 2 minutes and 45 seconds. This indicates that the SCSSV is designed to respond quickly in emergency situations to prevent any potential hazards or damage.

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2
14.

Downhole Equipment 14. Gas lift gas is used to do what?
- Used to lift heavy equipment
- Used to increase gas production.
- Used to produce an oil well with low bottom hole pressure
- Used to produce water on wells with high bottom hole pressures.
Correct Answer

A. Used to produce an oil well with low bottom hole pressure

Explanation

Gas lift is a technique used in oil wells to increase production by injecting gas into the wellbore. This gas helps to reduce the pressure at the bottom of the well, allowing the oil to flow more easily to the surface. By using gas lift, the bottom hole pressure is lowered, which helps to overcome the natural pressure decline in the well and maintain or increase oil production. Therefore, the correct answer is "Used to produce an oil well with low bottom hole pressure."

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15.

WELLHEADS 1. What is the most probable cause of a well having abnormally high tubing pressure?
- Down hole valve shut in.
- Valve downstream of the well has shut in
- Choke body has been cut out.
- Well is more than likely loaded up.
Correct Answer

A. Valve downstream of the well has shut in

Explanation

The most probable cause of a well having abnormally high tubing pressure is when the valve downstream of the well has shut in. This means that the flow of fluid from the well is being blocked by the closed valve, causing pressure to build up in the tubing. The other options, such as a down hole valve shut in or a cut out choke body, may also cause high tubing pressure, but the most likely cause in this scenario is the shut-in valve downstream of the well.

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16.

WELLHEADS2. The upper master valve, (SSV) is the only safety valve on the tree the MMS requires to close within _______ seconds of ESD activation.
- 10 sec
- 30 sec
- 45 sec
- 90 sec
Correct Answer

A. 45 sec

Explanation

The upper master valve, also known as the SSV (Surface Safety Valve), is the only safety valve on the wellhead tree that needs to close within 45 seconds of Emergency Shut Down (ESD) activation. This quick closure is crucial in preventing any potential hazards or uncontrolled release of fluids from the wellhead. By closing within 45 seconds, the SSV helps to maintain the integrity and safety of the wellhead system.

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17.

WELLHEADS 3. If you have a wellhead rated for 5,000# and the well flows at 2,500# FTP, and you found 6,000# on the wellhead panel to hold the SCSSV open, it is ok to keep this pressure on the safety valve.
- True
- False
Correct Answer

A. False

Explanation

The wellhead is rated for 5,000#, but the well is flowing at 2,500# FTP. The wellhead panel should not be holding more pressure than the wellhead is rated for. Therefore, it is not okay to keep the pressure of 6,000# on the safety valve.

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1
18.

WELLHEADS 4. It is OK to remove the well head after you close the SCSSV and bleed the tubing to zero for a rig job.
- True
- False
Correct Answer

A. False

Explanation

It is not okay to remove the wellhead after closing the SCSSV (Surface Controlled Subsurface Safety Valve) and bleeding the tubing to zero for a rig job. The wellhead is an important component that provides a secure connection between the surface equipment and the wellbore. Removing the wellhead without proper procedures and precautions can lead to safety hazards and potential damage to the well. Therefore, it is not recommended to remove the wellhead in this scenario.

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19.

WELLHEADS 5. Wellheads are not required to have the OCS lease number on them.
- True
- False
Correct Answer

A. False

Explanation

Wellheads are required to have the OCS lease number on them. This is because the OCS lease number is a unique identifier for each lease and is used to track and monitor the production from that specific lease. By having the OCS lease number on the wellheads, it becomes easier for regulatory authorities and operators to manage and regulate the production activities on the offshore lease.

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1
20.

WELLHEADS 6. Problem, you have a well on a satellite structure that can only be viewed during the day, yet it has cut out 2 flow lines and made a slick in the past. What device would you install in the flow line to help prevent the sand from cutting out another flow line in the future?
- A PSH
- A Sand Probe
- A PSL
- A titanium flow line
Correct Answer

A. A Sand Probe

Explanation

A sand probe would be installed in the flow line to help prevent the sand from cutting out another flow line in the future. Sand probes are designed to detect the presence of sand or solids in the flow line. When sand is detected, appropriate measures can be taken to mitigate the issue, such as adjusting flow rates or installing sand control equipment. By detecting and addressing the presence of sand early on, the sand probe helps to prevent further damage to the flow line caused by sand erosion.

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21.

WELLHEADS 7. When greasing tree valves only that valve manufacture’s recommended grease should be used.
- True
- False
Correct Answer

A. True

Explanation

It is important to use the recommended grease by the valve manufacturer when greasing tree valves. This is because different valves may require different types or grades of grease to ensure proper lubrication and functioning. Using the wrong grease can lead to inadequate lubrication, increased friction, and potential valve failure. Therefore, it is crucial to follow the manufacturer's guidelines and use the recommended grease for greasing tree valves.

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22.

WELLHEADS 8. Flow line-check valves are allowed to leakage rates of 5 standard cubic feet of gas or 200 c.c.’s of liquid per minute.
- True
- False
Correct Answer

A. True

Explanation

Flow line-check valves are allowed to have leakage rates of 5 standard cubic feet of gas or 200 c.c.'s of liquid per minute. This means that a small amount of gas or liquid is permitted to leak through the check valves without causing any significant issues or safety concerns. Therefore, the statement is true.

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1
23.

WELLHEADS 9. The bottom manual master valve should be used to isolate the flow only as a last resort due to any down stream failures.
- True
- False
Correct Answer

A. True

Explanation

The bottom manual master valve should only be used as a last resort to isolate the flow in case of downstream failures. This suggests that there are other methods or valves in place to control and isolate the flow, and the bottom manual master valve is only to be used in emergency situations. Therefore, the statement "The bottom manual master valve should be used to isolate the flow only as a last resort due to any down stream failures" is true.

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24.

WELLHEADS 10. What device is required over each well head?
- A light fixture
- A TSE
- A Deluge system
- A pressure gauge
Correct Answer

A. A TSE

Explanation

A TSE (Temporary Safety Eye) is required over each wellhead.

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1
25.

WELLHEADS 11. What is the most probable cause of a well having abnormally Low tubing pressure?
- Down hole valve shut in.
- Valve downstream of the well has shut in.
- High gas sales pressure.
- Well has probably been gas lifted and no longer can flow.
Correct Answer

A. Down hole valve shut in.

Explanation

The most probable cause of a well having abnormally low tubing pressure is the down hole valve being shut in. This means that the valve located down the wellbore, which controls the flow of fluids from the reservoir, is closed. As a result, the pressure in the tubing is reduced because the flow of fluids from the reservoir to the surface is restricted. This can happen due to various reasons such as equipment malfunction, maintenance work, or safety concerns.

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3
26.

WELLHEADS 12. You have a well that is gas lifted and the client wants to reduce restrictions to the flow, what type of elbow would you recommend to him?
- 45 degree elbow
- 90 degree elbow
- Short radius elbow
- Long radius elbow
Correct Answer

A. Long radius elbow

Explanation

A long radius elbow would be recommended to the client in order to reduce restrictions to the flow in a gas lifted well. This type of elbow has a larger radius, which allows for a smoother flow of gas and reduces the chances of turbulence or pressure drop. This helps to minimize any restrictions or blockages in the flow, resulting in improved efficiency and performance of the well.

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1
27.

Separators 1. MMS sometimes check to see if the pressure vessels in use in federal waters are certified and are A.S.M.E. coded.
- True
- False
Correct Answer

A. True

Explanation

The explanation for the given correct answer is that MMS (Minerals Management Service) occasionally checks if the pressure vessels being used in federal waters are certified and coded according to the standards set by the American Society of Mechanical Engineers (A.S.M.E.). This suggests that there is a requirement for certification and coding for pressure vessels used in federal waters, and MMS is responsible for ensuring compliance with these standards. Therefore, the statement "True" indicates that MMS does check for certification and A.S.M.E. coding of pressure vessels in federal waters.

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28.

Separators 2. Choke nipples are installed in vessel liquid dump lines to :
- Protect downstream equipment in case of dump valve failure
- Keep backpressure on vessel.
- Keep backpressure on wells.
- Everyone knows you don’t put chokes on liquid dump lines
Correct Answer

A. Protect downstream equipment in case of dump valve failure

Explanation

Choke nipples are installed in vessel liquid dump lines to protect downstream equipment in case of dump valve failure. This is because choke nipples help regulate the flow of liquid, allowing for a controlled release of pressure. By installing choke nipples, any potential sudden surge of liquid due to dump valve failure can be prevented, thus safeguarding the downstream equipment from damage.

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29.

Separators 3. As per 14-C all separators need to have a certain number of _____ on them for fire detection.
- TSH
- TSE
- ASH
- ESD
Correct Answer

A. TSE

Explanation

According to 14-C regulations, all separators are required to have a certain number of TSE on them for fire detection.

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30.

Separators 4. If you have a separator that requires 2 PSV's; you can temporary remove one and send it in for repair but still be in compliance with the other one.
- True
- False
Correct Answer

A. False

Explanation

If you have a separator that requires 2 PSV's, you cannot temporarily remove one and send it in for repair while still being in compliance with the other one. This means that the statement is false.

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31.

Separators 5. Name the three types of gauges, which are commonly used on separators to monitor operations.
- Level, pressure, temperature.
- Voltage, amperage, frequency.
- Oil filled, air filled, electronic.
- Timing, strapping, heat.
Correct Answer

A. Level, pressure, temperature.

Explanation

The question asks for the three types of gauges commonly used on separators to monitor operations. The correct answer is "Level, pressure, temperature." These three types of gauges are essential for monitoring the operations of separators as they provide information about the level of liquid or gas inside the separator, the pressure exerted on the separator, and the temperature of the contents. By monitoring these parameters, operators can ensure that the separator is functioning properly and make any necessary adjustments or interventions if needed.

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1
32.

Separators 6. Referencing API RP-14C; there are two types of production vessels,
- Horizontal and vertical.
- Two phase and three phase.
- Atmospheric and pressure
- Oil and Gas.
Correct Answer

A. Atmospheric and pressure

Explanation

The correct answer is "Atmospheric and pressure." This answer is correct because the question is asking about the types of production vessels referenced in API RP-14C. According to the information provided, there are two types of production vessels: atmospheric and pressure vessels.

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33.

Separators 7. O.S.H.A. does require an operator to have a cage around a fixed ladder 20’ or higher.
- True
- False
Correct Answer

A. True

Explanation

According to O.S.H.A. regulations, an operator is required to have a cage around a fixed ladder that is 20 feet or higher. This is done to ensure the safety of the operator and prevent any accidents or falls from occurring. The cage provides a protective barrier and helps to minimize the risk of injuries while using the ladder. Therefore, the correct answer is true.

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1
34.

Separators 8. It is OK to put a lower rated needle valve on a vessel as long as the pressure coming in won’t exceed the needle valve’s rating. (EX: 1440 psi vessel with 1000 psi needle valve)
- True
- False
Correct Answer

A. False

Explanation

It is not okay to put a lower rated needle valve on a vessel, even if the pressure coming in won't exceed the needle valve's rating. This is because the needle valve may not be able to handle sudden pressure surges or fluctuations, which can lead to failure and potential safety hazards. It is important to always use a needle valve that is rated equal to or higher than the maximum pressure expected in the system.

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1
35.

9. Fluid levels in vessels are controlled by?
- Back pressure valves.
- Spill over plates and weirs.
- Float assemblies.
- Both 2 & 3
Correct Answer

A. Both 2 & 3

Explanation

The correct answer is "Both 2 & 3". Both spill over plates and weirs as well as float assemblies are used to control fluid levels in vessels. Spill over plates and weirs are designed to allow excess fluid to spill over and maintain a constant level, while float assemblies use a float that rises or falls with the fluid level to control the flow of fluid in and out of the vessel.

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36.

Separators 10. Sometimes separators can have the LSL device SAC’ed out with a reference number A4e3, as long as the downstream components can safely handle the maximum gas rates.
- True
- False
Correct Answer

A. True

Explanation

Sometimes separators can have the LSL device SAC’ed out with a reference number A4e3, as long as the downstream components can safely handle the maximum gas rates. This statement is true because separators are used to separate different components in a system, and sometimes it may be necessary to bypass or isolate certain devices, such as the LSL device, for maintenance or other purposes. As long as the downstream components can handle the gas rates without any safety concerns, it is acceptable to SAC out the LSL device.

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37.

Separators 11. It is permissible to permanently bypass and then remove the LSH device on separators without MMS approval.
- True
- False
Correct Answer

A. False

Explanation

Permanently bypassing and removing the LSH device on separators without MMS (Minerals Management Service) approval is not permissible.

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2
38.

Separators12. All wells not in service need to have their safety devices checked monthly or else have ________ .
- Disconnected and blind flanged from the header.
- Valves closed and tagged.
- Valves closed and tied shut
- Closed, disconnect control line to SCSSV and Lock close master valve to secure well from flow.
Correct Answer

A. Closed, disconnect control line to SCSSV and Lock close master valve to secure well from flow.
39.

Separators 13. Snap action should be used on a liquid level controller when measuring liquids through a haliburton meter?
- True
- False
Correct Answer

A. True

Explanation

Snap action should be used on a liquid level controller when measuring liquids through a haliburton meter because snap action refers to a fast and immediate response to changes in the liquid level. This is important in a haliburton meter as it ensures accurate and precise measurement of the liquid level. Snap action helps to quickly detect any fluctuations in the liquid level and make adjustments accordingly, resulting in more reliable and efficient control of the liquid level.

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10
40.

Separators 14. An ice plug has formed in the production piping. Explain the procedure to get rid of the ice plug.
- Bleed off the downstream side of the ice plug and pump chemicals to thaw.
- Bleed off the upstream side of the ice plug and try to back flow the plug to break it up.
- Isolate both sides of the ice plug, bleed off each side, let thaw and start pumping methanol.
Correct Answer

A. Isolate both sides of the ice plug, bleed off each side, let thaw and start pumping methanol.

Explanation

To get rid of the ice plug in the production piping, the correct procedure is to isolate both sides of the ice plug, bleed off each side, allow it to thaw, and then start pumping methanol. This method ensures that both sides of the plug are properly addressed and allows for the gradual thawing of the ice. Once the ice has melted, pumping methanol can help prevent the formation of future ice plugs.

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9
41.

Separators 15. The PSV on a vessel with a MAWP of 1440 psig should be set at what pressure?
- The designed working pressure of the vessel.
- Whatever the operator decides is the best set pressure he wants.
- 5% under the designed working pressure.
- 15% under the designed working pressure.
Correct Answer

A. The designed working pressure of the vessel.

Explanation

The correct answer is the designed working pressure of the vessel. The PSV (Pressure Safety Valve) on a vessel should be set at the same pressure as the designed working pressure of the vessel. This ensures that the PSV will activate and release excess pressure when the vessel reaches its maximum safe operating pressure. Setting the PSV at a lower pressure could result in the valve not opening when needed, potentially leading to a dangerous overpressure situation.

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8
42.

Pumps 1. API RP-14 C requires positive displacement pumps with discharge pressure > than the MAWP of the discharge piping to be equipped with a ________device to protect downstream piping.
- PSV
- LSH
- LSL
- Recycle Line
Correct Answer

A. PSV

Explanation

API RP-14 C requires positive displacement pumps with discharge pressure greater than the MAWP of the discharge piping to be equipped with a PSV (Pressure Safety Valve) device to protect downstream piping. This valve will automatically open and relieve excess pressure in the system, preventing any potential damage or failure of the piping.

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5
43.

Pumps 2. What device shall be located above each rod packing pump-transferring flammables?
- TSE
- PSH
- Fire Extinguisher
- Flood lights
Correct Answer

A. TSE

Explanation

The correct answer is TSE. TSE stands for "Thermal Safety Element" which is a device that is typically located above each rod packing pump when transferring flammables. It is designed to detect excessive heat and activate a shutdown system to prevent any potential fire or explosion hazards.

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2
44.

Pumps 3. All centrifugal pumps moving hydrocarbons are required to have a SDV on the suction side.
- True
- False
Correct Answer

A. True

Explanation

All centrifugal pumps moving hydrocarbons are required to have a SDV (Suction Discharge Valve) on the suction side. This is because hydrocarbons are often volatile and flammable substances, and having a SDV helps to control the flow and prevent any potential accidents or leaks. The SDV allows for easy shut-off and isolation of the pump, ensuring safety during maintenance or emergencies. Therefore, it is necessary for all centrifugal pumps moving hydrocarbons to have a SDV on the suction side.

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45.

Pumps 4. Centrifugal pumps are designed to;
- Move large amounts of liquids usually at low pressure.
- Pump liquids into high pressure.
- Pump only oil.
Correct Answer

A. Move large amounts of liquids usually at low pressure.

Explanation

Centrifugal pumps are designed to move large amounts of liquids usually at low pressure. This means that they are capable of transferring a significant volume of liquid, but not at a high pressure. They are commonly used in applications such as water supply, irrigation, and wastewater treatment, where a large volume of liquid needs to be moved efficiently. They are not designed specifically for pumping only oil, and they are not intended for pumping liquids into high pressure.

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3
46.

Pumps 5. Positive displacement pumps are designed to;
- Move large amounts of liquid
- Pump liquids into high pressure.
- Pump only H2O.
Correct Answer

A. Pump liquids into high pressure.

Explanation

Positive displacement pumps are designed to pump liquids into high pressure. This means that these types of pumps are specifically designed to increase the pressure of the liquid being pumped. They do not necessarily move large amounts of liquid or pump only H2O. Instead, their main purpose is to increase the pressure of the liquid being pumped, regardless of the volume or type of liquid.

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2
47.

Pumps 6. Centrifugal pumps need a charge pump or to be gravity fed to perform at their maximum efficiency.
- True
- False
Correct Answer

A. True

Explanation

Centrifugal pumps require a charge pump or gravity feed in order to operate at their highest efficiency. This means that without a charge pump or gravity feed, the pump may not function optimally and may not be able to achieve its maximum efficiency. Therefore, the statement "Centrifugal pumps need a charge pump or to be gravity fed to perform at their maximum efficiency" is true.

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2
48.

Pumps 7. All positive displacement pipeline pumps are lubricated by the process fluid and don’t require external oiling devices.
- True
- False
Correct Answer

A. False

Explanation

False. This statement is incorrect because while some positive displacement pipeline pumps may be lubricated by the process fluid, not all of them are. Some positive displacement pumps do require external oiling devices for lubrication.

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1
49.

Pumps8. The component modifier for a pipeline pump as per API 14 C is PAX.
- True
- False
Correct Answer

A. True

Explanation

According to API 14 C, the component modifier for a pipeline pump is PAX. Therefore, the correct answer is True.

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Nov 04, 2010

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Operator Assessment Exam

Downhole Equipment1. As per 30 CFR 250, what is the interval for testing SCSSV’s?

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Downhole Equipment2. A SCSSV has an allowable leakage rate?

Downhole Equipment3. What must be done when pressure is first observed on any of the casing strings?

Downhole Equipment 4. All wells capable of natural flow need to have a ________ or ________installed in the tubing at least 100 feet below the mud line.

Downhole Equipment 5. When a well will no longer flow on it’s own, gas lift gas is the most common source of lift available to continue production offshore.

Downhole Equipment6. Under what conditions may a well be flowed with the SCSSV locked out or the SSCSV removed?

Downhole Equipment 7. As wells age, their flowing characteristics change. When this happens oil and gas rates usually go down and water rates increase. Which of the following explains what causes good wells to become loaded up.

Downhole Equipment 8. Name three noticeable changes that can be seen to warrant an operator to check a positive choke that may be cut out?

Downhole Equipment 9. Problem, a gas lift well has had a history of making C O 2 and now has holes in the tubing. The holes have been sealed with pack-offs. You are unable to maintain gas lift pressure to lift the well, gases around. What do you believe has started to happen to this well?

Downhole Equipment 10. Under what circumstances may the MMS district supervisor grant permission to lock out a SCSSV and install a SSCSV?

Downhole Equipment 12. A gas flow chart recorder is used to measure the volume of gas lift gas and also indicates the performance of the gas lift valves. Describe how the chart can indicate gas lift valve performance.

Downhole Equipment 13. What is the maximum time allowed as per 30 CFR for the SCSSV to close after the ESD has been activated?

Downhole Equipment 14. Gas lift gas is used to do what?

WELLHEADS 1. What is the most probable cause of a well having abnormally high tubing pressure?

WELLHEADS2. The upper master valve, (SSV) is the only safety valve on the tree the MMS requires to close within _______ seconds of ESD activation.

WELLHEADS 3. If you have a wellhead rated for 5,000# and the well flows at 2,500# FTP, and you found 6,000# on the wellhead panel to hold the SCSSV open, it is ok to keep this pressure on the safety valve.

WELLHEADS 4. It is OK to remove the well head after you close the SCSSV and bleed the tubing to zero for a rig job.

WELLHEADS 5. Wellheads are not required to have the OCS lease number on them.

WELLHEADS 6. Problem, you have a well on a satellite structure that can only be viewed during the day, yet it has cut out 2 flow lines and made a slick in the past. What device would you install in the flow line to help prevent the sand from cutting out another flow line in the future?

WELLHEADS 7. When greasing tree valves only that valve manufacture’s recommended grease should be used.

WELLHEADS 8. Flow line-check valves are allowed to leakage rates of 5 standard cubic feet of gas or 200 c.c.’s of liquid per minute.

WELLHEADS 9. The bottom manual master valve should be used to isolate the flow only as a last resort due to any down stream failures.

WELLHEADS 10. What device is required over each well head?

WELLHEADS 11. What is the most probable cause of a well having abnormally Low tubing pressure?

WELLHEADS 12. You have a well that is gas lifted and the client wants to reduce restrictions to the flow, what type of elbow would you recommend to him?

Separators 1. MMS sometimes check to see if the pressure vessels in use in federal waters are certified and are A.S.M.E. coded.

Separators 2. Choke nipples are installed in vessel liquid dump lines to :

Separators 3. As per 14-C all separators need to have a certain number of _____ on them for fire detection.

Separators 4. If you have a separator that requires 2 PSV's; you can temporary remove one and send it in for repair but still be in compliance with the other one.

Separators 5. Name the three types of gauges, which are commonly used on separators to monitor operations.

Separators 6. Referencing API RP-14C; there are two types of production vessels,

Separators 7. O.S.H.A. does require an operator to have a cage around a fixed ladder 20’ or higher.

Separators 8. It is OK to put a lower rated needle valve on a vessel as long as the pressure coming in won’t exceed the needle valve’s rating. (EX: 1440 psi vessel with 1000 psi needle valve)

9. Fluid levels in vessels are controlled by?

Separators 10. Sometimes separators can have the LSL device SAC’ed out with a reference number A4e3, as long as the downstream components can safely handle the maximum gas rates.

Separators 11. It is permissible to permanently bypass and then remove the LSH device on separators without MMS approval.

Separators12. All wells not in service need to have their safety devices checked monthly or else have ________ .

Separators 13. Snap action should be used on a liquid level controller when measuring liquids through a haliburton meter?

Separators 14. An ice plug has formed in the production piping. Explain the procedure to get rid of the ice plug.

Separators 15. The PSV on a vessel with a MAWP of 1440 psig should be set at what pressure?

Pumps 1. API RP-14 C requires positive displacement pumps with discharge pressure > than the MAWP of the discharge piping to be equipped with a ________device to protect downstream piping.

Pumps 2. What device shall be located above each rod packing pump-transferring flammables?

Pumps 3. All centrifugal pumps moving hydrocarbons are required to have a SDV on the suction side.

Pumps 4. Centrifugal pumps are designed to;

Pumps 5. Positive displacement pumps are designed to;

Pumps 6. Centrifugal pumps need a charge pump or to be gravity fed to perform at their maximum efficiency.

Pumps 7. All positive displacement pipeline pumps are lubricated by the process fluid and don’t require external oiling devices.

Pumps8. The component modifier for a pipeline pump as per API 14 C is PAX.

Downhole Equipment 4. All wells capable of natural flow need to have a or installed in the tubing at least 100 feet below the mud line.