Some recordkeeping is required, either by a regulatory body or the lease company. They’re used to monitor production and help to understand the well’s behavior or help determine production allocation. Other records you might keep for yourself, and might include tips for the next time you have to perform a difficult task, or details that you’re likely to forget.

The record might be a notebook in your truck’s glove compartment or oil wells test sheet, but these days it’s more likely to be an app on your phone (like the GreaseBook). In either case, a good record is an important tool, as useful as a wrench or screwdriver.



Why Keep Records?

Daily recordkeeping can often seem like just another chore, more red tape to wade through while doing your job. In reality, accurate and precise recordkeeping is an important part of a lease pumper’s responsibilities. Complete records can be used to spot potential problems, increase efficiency, and predict when expensive maintenance may be required. That all can add up to money saved.

For the folks on the ground doing the work, records can also be of direct, practical help. If there is ever a question about what type of packing material or which sort of oil to use, the answer can be found in well kept records. When ancient or unusual equipment has to be pulled or serviced, the instructions for doing so are usually found in the lease records. A few minutes jotting down notes can save you hours of headache down the line.

You’ll want to keep records of basic information like the size and locations of fuses on the lease, size and type of rod packing, location of spare equipment, and more. Records will also indicate more important information as well, such as production quantities and details about equipment. The value of good recordkeeping shouldn’t be underestimated.



Each pumper should set up his own record book. The needs of each well and tank battery are going to be unique, so it may be helpful to have easy access to a range of information. In some cases, the pumping company may have a mechanic or other specialists on staff who keep records of their own. The pumper’s records may be less.

The record book itself can be as simple as a notebook that has been setup to keep information organized, but it can be helpful to get a little fancier. Using a three ring binder allows you to add, remove, or rearrange pages, and using section dividers or tabs can help to keep different types of records separate. Blank or graph paper is often useful, as it allows you to design an efficient recordkeeping system.

Lease records will usually include pumping and production records, records of communications, maintenance records, and materials records. Materials records are inventories that outline how much of different equipment is held and where.


Your Greasebook

The lease record books tracks monthly testing and production, as well as the general state of equipment and maintenance records. There’s a lot of day-to-day work that doesn’t get recorded in the lease record book, though, that may be helpful to know. Your greasebook is the best place for all that information. It should be updated daily and kept handy for at least a short while. While lease records are great at providing an overall look, some questions can only be answered by detailed information that isn’t kept in the lease records. If you don’t jot it down in personal record, the answer may be gone.

Information that it may be helpful to track in your greasebook includes gauge readings, meter readings, oil well testing, and any maintenance or repairs done for each day. It’s helpful to divide the greasebook so that records for each lease are kept in a separate section. There’s a few shortcuts you can use to save space in your greasebook:

  • Stock tanks are numbered, with higher numbers usually being to the right. The last two letters in the ID number for each tank should be unique. The number and the last two letters are enough to identify a tank, in most cases.
  • A new section can be added for each day. Use as much space as you need for the day, including any measurements, tests, or repairs made.
  • When a greasebook is filled, mark the dates it covers and keep it somewhere accessible.

The greasebook might record information such as the gauging amounts for each day, the amount of oil sold, water or sediment levels, chemical added, and anything else that might be useful to know. Some information in your greasebook may end up in the lease records.

Is your appetite for oil & gas operating knowledge insatiable like ours? 😀 If so, check out these related articles: Well Records For Oil & Gas Production, Operational Records For Oil & Gas Production Wells and, Tracking Inventory In Oil & Gas Production – they’ll be sure to pump you up!!!

Many wells produce some amount of natural gas along with crude oil. Others may produce mostly or only natural gas. Whenever there is enough gas coming from the well to be worth collecting and selling it, additional equipment and vessels need to be added to the tank battery and wellhead. All of the equipment intended for handling gas production together is called the gas system. It begins at the separator, where gas breaks out from liquid well products.

Natural Gas Systems


Gas Pressure

Pressure is an important consideration in any tank battery. It forces fluid and gas through the different vessels, and helps prevents loss through evaporation. Pressure is controlled by valves, both in the gas outlet line and the water and oil outlet lines. The oil and water lines use diaphragm controlled valves to maintain backpressure. The gas line will also use a diaphragm backpressure valve. Diaphragm valves have an arrangement that uses a spring and bolt on the top to adjust the dump pressure.

Natural Gas Systems

Figure 1. A diagram of a tank battery. The gas system is labeled G.

Fluids can only flow from a higher pressure to a lower pressure vessel, so the separator will have the highest pressure of all the vessels in the tank battery, and the stock tanks will have the lowest. This pressure balance is controlled by the gas system.

Natural Gas Systems

Figure 2. The cut-away view of a backpressure valve. (courtesy of Kimray, Inc.)

Wells are usually tested regularly each month. Part of that testing is a measurement of the gas pressure and volume that is being produced. The well will typically be produced through to the tank battery so that measurements can be taken by a meter, like the one shown in Figure 3.

Natural Gas Systems

Figure 3. A meter used for testing gas pressure.


The High Pressure System

A gas system can be divided roughly into a high pressure system and a low pressure system. The high pressure system is not truly at a high pressure, particularly when compared to pressures downhole; the separator may be the only vessel that is part of the high pressure system. However, the separator can have a pressure of between 20 and 50 psi, which is enough to require caution.

In some cases, particularly with marginal wells, the gas produced may be a very small amount. The casing may just be left open to vent whatever gas is produced. Enough gas may remain in the fluid, however, that a separator may still be required. Other vessels that might be considered part of the high pressure system include any heater-treaters or wash tanks that may be under more than a few pounds of pressure.


The Low Pressure System

The low pressure system is largely made up of atmospheric tanks, such as stock tanks. Stock tanks will normally have a few ounces to a few pounds of backpressure, which helps to prevent loss by evaporation. Gas will usually flow out of the tanks’ gas outlets and from there to the vapor recovery unit, with a small amount of pressure held by a valve. Even though the pressure is quite low, a safety release valve is still necessary. A simple option that is popular is to use a length of L shaped pipe. This can be used with a diaphragm valve as a safety valve if pressure should build in the vessel.

Natural Gas Systems

Figure 4. A diagram of a backpressure valve. This one maintains one ounce of backpressure, and is designed for use with atmospheric vessels. (courtesy of Sivalls, Inc.)

The vapor recovery unit is also considered part of the low pressure system. It’s placed between the high pressure vessels and the atmospheric stock tanks, and is used to reclaim liquid hydrocarbons, usually low weight condensates, that have evaporated. These are condensed out of the gas and routed back to holding tanks. Vapor recovery units are most often required when wells are located in populated areas. One may also be useful when a heater-treater is used in a tank battery, as heat can increase loss through evaporation.

Natural Gas Systems

Figure 5. An example vapor recovery unit.

The unit is most often a skid mounted. The basic unit consists of a compressor and some sort of scrubber for removing vapor. Gas is then compressed; it’s important that as much liquid is removed as possible, as the compressor is usually intended for gas only. Liquid in the compressor can end up damaging it. The compressor is necessary as the gas is injected back into the separator; the gas has to be at a higher pressure than the separator. The liquid level in the compressor should be checked regularly. Conversely, these pumps need to be kept lubricated, as dry gas can lead to friction between compressor components.


Gas Sales System

Gas is collected from all of the vessels, including the separator, heater-treater, stock tanks, and any other vessels. Before the gas enters the pipeline, the gas company will measure its volume using a gas meter. There will also be a backpressure valve and check valve to prevent loss of gas.

The pipeline’s pressure will often be set quite low, below the operating pressure of the vessels in the tank battery. That allows gas to flow from the battery to the pipeline. Further down the line, there will be a compressor that pushes pipeline pressure up to 500 psi for long distance transportation.

It’s possible that more gas is produced and sent down the pipeline than the gas company is selling. When that happens, the pressure in the pipeline will grow. The result is that production at the well slows, perhaps quite a bit. Everything is still operating properly, but the pressure is such that new gas production is being sent to the gas flare to be vented, rather than down the pipeline. The only option, in these cases, may be to shut in the well for a short time.

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The system for handing off natural gas production to the purchasing company is a bit different than that required for selling crude oil. Crude oil may be transported by truck, and the tank battery will require a system to allow trucks to be loaded. When selling crude oil by pipeline, an LACT unit and other additional equipment may be needed. 

Selling Natural Gas

Selling gas also usually requires some specialized equipment. The gas needs to be compressed so that it can be transported through a pipeline. It also needs to be measured, and any remaining liquid needs to be removed. However, all that, and the equipment required, may actually be the responsibility of the purchasing company. Gas will often technically belong to the purchasing company once it leaves the production unit. However, since this is equipment that’s at the lease location, and it’s generally wise to understand how you get paid, it can be helpful to know what happens with produced natural gas before it gets sent down the pipeline.


Measurement and Compression

After the gas has had as much liquid removed as possible, it will usually need to be compressed. The pressure is what pushes the gas down the pipeline. If the gas pressure needed for the pipeline is over 500 psi, the gas will need to be compressed. The pressure will fall as gas travels down a pipeline, from the friction between the gas and the interior of the pipeline. Pressure will also fall as pipelines meet and the diameter widens to handle the additional volume. There will usually be compressor stations along the pipeline to keep the pressure high.

The compressor at the lease location will be automated so that production can be handled automatically. It will also have some controls to shut off the compressor in the event of a sudden change in line pressure. Both a large drop or a sudden rise can indicate a problem. A drop in pressure may indicate a leak or break in the pipeline, and so the compressor will be shut off to prevent gas being lost to the atmosphere. A rise in pressure could mean that the line has become blocked. An engine will often be used to provide power to the compressor; when that’s the case, the engine will have it’s own set of safety systems.

Selling Natural Gas

Figure 1. The gas meter is located within the small building to the left.

After the gas is compressed, the amount sold is measured by a gas meter. The meter may be as simple as a chart meter, or it may be a fancier system with solar power. These details are going to largely depend on production volume of the well. That is also going to impact the contract with the purchasing company. That can determine who owns equipment. With some low volume wells, the production company is required to pay the cost of a pipeline connection.

Selling Natural Gas

Figure 2. An example of a solar powered gas meter. Meter readings are reported to the purchasing company automatically over radio.


Testing Wells

The production volume is determined by testing the well.  A shut in test can determine reservoir pressure, and therefore provide some data helpful when trying to predict a well’s production volume over time. To perform this test, the well is shut in, and after a standard time period the pressure at the wellhead is read. Other tests can provide information about water and condensate production. There are a few tests that are required so that regulatory bodies can monitor gas production and set production limits.

Tests usually require a certain amount of preparation, even simple ones like the shut in test. A higher flow for a short time can help to clean the wellbore before a well is shut in. Some wells may need to be shut in for longer periods before they reach maximum pressure and tests can be run.

The procedures and equipment for measuring gas production is largely similar to measuring liquid oil. Gas volumes are usually higher, however. A few abbreviations are standard and helpful to know. Bottomhole pressure is usually written BHP. CF and CFM mean cubic feet and cubic feet per minute.

Some abbreviations will use roman numbering, which can save on space and is less likely to be misread. In roman numbers, M stands for 1,000, and MM is 1,000 x 1,000, or 1 million. 1,000 ft3 can therefore be written as MCF. MSCF is 1,000 standard cubic feet. 1 million ft3 is MMCF. MMCFD is 1 million ft3 per day. Barrels of condensate per million ft3 is abbreviated BCPMM.


Transporting Natural Gas by Pipeline

In natural gas production, a lot of time is spent stripping all the water and liquids out of the gas before sending it down the pipeline. Liquids in the pipeline can become a serious problem, and even small amounts are an issue. When the natural gas from a dozen wells meets in the pipeline, the small amount of liquid from each well can be enough to be problematic.

Liquid vapor will condense as it moves through a pipeline. The condensate will need to be pushed along by the gas pressure, or it will cause back pressure or blockages. Condensed water can also combine with liquid hydrocarbons and other elements precipitated out of the gas to create a compound called a hydrate, a gel-like substance that will also block the line.

Water will also freeze in colder weather, leading to more blockages. The water may freeze and thaw several times throughout the year, leading to cycles of blockages and flow. Methanol may be injected in the line to act as an anti-freeze.

Selling Natural Gas

Figure 3. An example of a gas compressor with a chemical injector for anti-freeze.

It may be inevitable that some liquid gets into the pipeline and condenses. This condensate is most often known as drip, and is usually removed from the pipeline and collected in containers known as drip pots. Drip is volatile and it should be handled carefully. If it mixes with oxygen and is ignited by a spark, it will explode.

Selling Natural Gas

Figure 4. Shown here are drain lines leading to drip pots.

Natural gas is collected at processing plants, where all liquids, condensates, and other contaminants are removed. It can then be sent where it will be used, often long distances across the country.

Selling Natural Gas

Figure 5. A processing plant for natural gas.

Natural gas has a number of different uses. As it is clean burning, it is used to provide steam to generate electricity. Compressed natural gas (CNG) can be used to power cars and short distance transportation. If it is compressed further it will become liquefied natural gas (LNG), which can also be used to fuel cars and other transportation.

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When it comes out the ground, natural gas will be mixed up with other liquid or vapor hydrocarbons and water vapor. A great deal of the vapor and liquid that is caught up in the natural gas will be removed by high pressure separators. Separators are designed primarily to separate liquid from gas, though three-phase separators will also isolate liquid hydrocarbons from water. Once the natural gas has passed through a separator, however, it may still be fairly wet gas, also known as rich gas. This is gas that still contains vapor, both water and a form of liquid hydrocarbon called distillate, that needs to be removed before it can be sent to the pipeline.

Dehydrating Natural Gas


Dehydration Units

A dehydration unit will often be used to dry natural gas enough for it to be sold. The gas may still contain some vapor, but it will be conditioned so that its dewpoint, the temperature at which condensation forms, is lower. Some types of dehydration units may be referred to as a thermo or stack pack.

Dehydrating Natural Gas

Figure 1. A diagram outlining the operation of a glycol dehydration unit.

The gas is treated with a chemical that is hygroscopic, meaning it will absorb the water vapor in the gas. The dry gas is then measured and stored or sold. That chemical is usually either tri-ethylene glycol or ethylene glycol, with tri-ethylene glycol being more common. The dehydration unit will usually be with the separator, located together before the tank battery.

Dehydrating Natural Gas

Figure 2. Pictured together are a separator and a dehydration unit with knee tub. In the background are tanks for handling water and distillate.

A dehydration unit may consist of several different vessels. The first is the inlet scrubber, a two phase vessel which separates liquid from gas. The gas passes over a divertor plate so that it flows in a circular direction. It then passes up through a mesh mist extractor, and then on to the next vessel in the unit, the contact tower.

The gas enters the bottom of the contact tower and flows up through a series of trays. The first is called a chimney tray, and is simply a tray that is sealed on the bottom and that has a short length of pipe leading up. This allows the chimney tray to catch glycol as it falls from above. All the trays above the chimney tray will usually be bubble cap trays, each with a layer of glycol that drops down from above and flows out through the downcomers. The trays are metal sheets with dozens of holes in them. Each hole will have a small cap above a riser, so that as gas flows up it is broken up into small bubbles. This increases the surface area that is exposed to the glycol, improving the efficiency of the chemical as it draws liquid vapor from the gas. The gas then passes up out of the top of the tower.

Dehydrating Natural Gas

Figure 3. A close up of a dehydration unit.

The gas then is piped through a downcomer line and passes through the glycol-gas heat exchanger. Glycol that is entering the contact tower is usually hot after water has been boiled out; the gas is used to cool the glycol. The gas is then sent on to be measured and compressed.

Glycol is pushed through the system by a pump, and is cycled through to be used multiple times. A dual action pump pushes glycol to the top of the contact tower, so that it can flow to the bottom and absorb liquid along the way. The wet glycol collected at the bottom of the tower is pushed through a high pressure strainer and into a surge tank. It is then pushed into a separator designed to remove any gas that may have been brought along, as well as liquid hydrocarbons like condensate. The glycol, still laden with water, is next pumped to the reboiler. The gas reclaimed from the dehydration unit’s separator can be used to power the reboiler.

Glycol has a higher boiling point than water, so the glycol can be heated to boil the water off. Boiling temperature will rise or fall depending on pressure and contaminants, but reboilers generally operate at about 350 degrees Fahrenheit. This is significantly higher than water’s boiling point of 212 degrees, but just below glycol’s boiling temperature.

Dehydrating Natural Gas

Figure 4. An example of a reboiler.

Water vapor rises from the glycol and is sent through a stripping still and condenser, after which it flows down an angled pipe to a small container called a foot tub. The angled pipe will most likely need to be insulated, as the water in it can freeze in cold weather and cause a blockage.

Dehydrating Natural Gas

Figure 5. A foot tub from collecting water.

Vacuum trucks are used to empty the foot tubs so that they don’t overflow. This is a task that may be performed by the gas purchasing company.


Tank Batteries For Gas Wells

The tank batteries for natural gas wells are usually fairly simple. The liquid that is produced is usually made up of low weight hydrocarbons and water, which flash separate without requiring any heat or pressure. As a result, not much equipment is needed; heater-treaters, wash barrels, and other vessels a crude oil tank battery would require can be left out.

Tank batteries for gas wells do have a few special considerations. In particular, the liquid hydrocarbons that are produced will have a high API gravity, and can act as a penetrating fluid. Fittings that are even a bit loose can lead to seeping leaks. Leaking fluids will stain equipment and the installation, leading to a generally run down appearance. Keeping an installation clean is also about more than just an attractive appearance; when equipment is clean and well maintained it’s much easier to spot problems before they become serious.

Dehydrating Natural Gas

Figure 6. This is an example of a tank battery designed to serve a gas well.

Each well produces a slightly different mix of gas and liquids, so each tank battery will be different to meet specific needs. Beyond the three phase separator and dehydration unit, other vessels will usually include a tank for storing liquid hydrocarbons and a holding tank for the water disposal system.

Dehydrating Natural Gas

Figure 7. This tank is used to hold condensate produced from a gas well.

The tank used for holding liquid hydrocarbons, like condensate, may need to be more than just a simple stock tank. The liquid hydrocarbons can be extremely volatile, meaning that they will evaporate very easily. Loss through evaporation can be a significant problem, and so a higher back pressure may need to be held to reduce the evaporation. A careful record will usually show any losses.

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Before any product from a well can be sold, it has to be separated from all the impurities and contaminants that are also brought up from the well. When the well is primarily producing natural gas, the major concern is scrubbing liquid vapor from the saleable gas. Gas purchasing companies will usually have requirements for the gas’ dryness before they will accept it. Other valuable hydrocarbons may also be produced alongside natural gas, which when separated out can be sold.

Natural Gas

As with crude oil producing wells, most of the separation happens in the tank battery. The majority of the equipment in the tank battery for a gas well will be used to remove liquid from the natural gas. Three phase separators are pretty common choices for gas producing wells; the ‘three phase’ part means that the vessel separates gas from fluid, and also separates the fluid into water and any liquid hydrocarbons. Unlike separators used with crude oil wells, these separators are usually under high pressure.


High Pressure Separators

A separator used for separating oil from gas is usually under, at most, 100 pounds of pressure. By comparison the separators used for gas wells are under at least 1,000 pounds of pressure, and may have a max test pressure of about 2,000 psi. To contain such a high pressure, separators chosen for a gas well are usually small, with a diameter of 2 ft or less. The construction of the separator is also usually much heavier, including thicker walls and tougher gauges and valves. As a general rule, whenever a piece of equipment is visibly stronger and more rugged it is likely to be designed to handle high pressures.


Vertical Separator

A common type of separator used for gas wells is a vertical separator. An example of one can be seen in Figure 1. Three phase separators are chosen frequently, as they both separate liquid from gas, but also separate water from liquid hydrocarbons.

Natural Gas

Figure 1. An example of a three phase separator that operates under high pressure.

In the example in Figure 1, the inlet line can be seen on the center-left of the separator. The gas flows up to the gas outlet at the top, where it is sent on to a scrubber, seen at the bottom right. The scrubber is shop made, and is used to remove any remaining vapor. At the upper right are safety devices, such as safety valves and rupture discs.

Liquids fall to the bottom of the separator. Liquid levels are controlled by a pair of floats, with the exterior parts of the floats being visible at the center-right of the separator. The top one is an indiscriminate float, meaning that it will float on both oil and water. It therefore controls the level of condensate, a form of lightweight, liquid hydrocarbon. When the condensate level is high enough, the diaphragm valve (the lowest line on the left) will open and allow fluid to flow to stock tanks.

The lower float is designed to float on water but fall through oil, and therefore is used to control the water level in the separator. These sorts of floats are called discriminate floats. This float controls another diaphragm valve, which when opened allows flow into the water disposal system. Figure 2 shows a closeup of these components where each is easier to see.

Natural Gas

Figure 2. A close up look at the separator and its valves from Figure 2. At left is a gas scrubber custom made in a shop.

For smaller wells that have lower production volumes, the tank battery will often be much simpler. A single separator, a tank for holding waste water, and a meter for measuring gas production may be all that is needed.

Natural Gas

Figure 3. A low production gas well.


Indirect Heating

Gas wells may have a pressure two or three times the operating pressure of a separator. This can cause problems when water vapor is produced from the well along with natural gas. As the gas expands in the relatively lower pressure of the separator, it will cool extremely quick. The drop in temperature will freeze the water, creating a block in the lines, usually at the choke valve of the wellhead. This will often cause production to cease. With no production and no gas expanding to lower the temperature, the ice melts. Eventually, the well begins to produce again, until ice forms once more and the cycle is repeated.

Obviously this is an inefficient way to run a well. To address the problem, a few solutions have been developed. The most common is a separator that uses the water bath that is shown in Figure 4. Gas from the well flows back and forth through a pipe surrounded by hot water. The water heats the gas, which keeps ice from forming at the choke valve. Gas then gets piped to the three stage separator, which functions much like any other separator. Gas breaks out from the fluid and is piped up the gas outlet. Water falls out to the bottom of the separator, and is drained out to the water disposal system. Any oil floats on the water and flows out to a holding tank.

Natural Gas

Figure 4. This separator uses heated water to keep ice from forming.

The heated water in the bath will need to be topped up occasionally, as it will gradually evaporate away. Distillate, a liquid hydrocarbon that is one of the possible products of a gas well, may be difficult to separate from the gas. A smaller, lower pressure separator may be added to the tank battery. The added vessel will scrub out any remaining vapor from the gas, which may lead to a rise in distillate production.

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Natural gas is often a secondary consideration when a well is first drilled and completed; the focus is more often on crude oil and other liquid hydrocarbons. However, there are wells that only or primarily produce natural gas. While gas wells may not require as many vessels or as much equipment, they do have some unique problems and there are important considerations to keep in mind.

Gas Wells


Gas Well Basics

While natural gas is obviously the primary product of gas wells, liquid hydrocarbons and water may be produced as well. Water will often be suspended in the gas and have to be scrubbed out. The liquid hydrocarbons usually take the form of condensates or distillates.

Condensate starts as a vapor, produced up through the well with the gas. The vapor condenses into a liquid at some point; this might happen as it’s being sent up the well, during processing, or perhaps even after the gas has been sold and sent through a pipeline. If the vapor condenses as it is leaving the well, the fluid will often fall back into the reservoir, with a negative impact on production. Condensate can be as clear as water.

Distillate is actually a low weight liquid hydrocarbon that is evaporated into vapor and then condensed back into liquid. This process is called distillation, and it is a process for purifying hydrocarbons which is fairly common. Distillation usually produces a casing head gasoline or crude, but does not yield any heavier oil.


Safety Valves And Other Devices

Gas wells can be dangerous and difficult to control. As a result, they often have some specific and important safety measures in place. Wells with a higher gas production will usually have a wider range of safety devices; with marginal or low production gas wells, there may not be enough gas coming from the well to warrant that additional layer of safety.

One of the more important safety measures are the well gates. Wellhead valves are sometimes referred to as gate valves, or simply gates. The name may refer to a style of valve that’s commonly used for this purpose, which uses a gate-like wedge or slab to cut off flow. A well will usually have two master gates. The upper master gate is used to shut in the well for testing or maintenance. A lower master gate is used as a backup if the upper master gate fails; the well can still be shut in while the upper gate is replaced or repaired.

Gas Wells

Figure 1. An example of a gas well christmas tree. Shown are the two master gates, the wing gate and a safety valve, and a variable choke.

There are two other common safety valves that can be used to shut in a well in the event of a problem. The first is at the surface, usually near the high pressure separator. This valve will shut in the well if the pressure rises too high, or if it falls too low. Low pressure may mean a break or leak in a line, which leads to gas being vented to the air. High and rising pressure may mean that water vapor has condensed out of the gas and frozen, blocking the line. A safety valve is visible in both Figure 2 and 3.

Gas Wells

Figure 2. A lower production gas well. In the background a separator and a compressor are visible.

Gas Wells

Figure 3. This is a gas well that produces a higher volume, and so has a wider range of safety devices.

The second safety valve is downhole, and is called the tubing safety valve. This valve will shut in the well if the line breaks and gas is being released into the atmosphere. It’s rarely needed, but should be checked on a regular schedule to make sure it’s functioning. Most often, a contracted wireline company will set and retrieve these valves, and services them when needed. The tubing safety valve is most often seen with high production wells. With lower production wells, a valve that is hydraulically opened can be installed. If the pressure falls, the well is automatically shut in without needing the tubing valve. That’s a system that’s more common in offshore wells.

In some cases, the additional safety measures aren’t built into the christmas tree, as the production volume is too low to require them.

Gas Wells

Figure 4. This is a gas well that produces small amounts, with a simpler wellhead.

Gas Production

All wells have a unique personality, with a different production volume and profile. Gas wells may produce small amounts, less than 100,000 ft, 3 in a day, or much larger volumes of millions of cubic feet a day. The amounts and ratios of water, condensate, distillate and other products will also vary from well to well. That means that the equipment needed to produce the well is also going to vary to meet the specific needs of each well.

The gas will be accepted by the purchasing company and usually sent through a pipeline. The purchasing company may not always accept produced gas. If there isn’t a market for gas at that moment, they will be reluctant to pay for new production. The purchasing company may send a representative around to shut in the well if they’re not buying gas or if there’s an emergency. The gas company may not buy gas for a longer period, meaning the well is shut in and not earning for that whole length of time. This is much less likely when the well is also producing crude oil, so producing both when possible is usually a more stable, and therefore preferable, option.

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Problems like parted rods and leaking tubing, while they may require a servicing unit and crew, are part of standard maintenance operations for a well. There are larger problems that may require a full workover. Workovers can be expensive, as they not only require heavy equipment and a crew, but also may require that a well be killed and production totally stopped for a period of time.



Beginning Workover Operations

Before a workover can begin, the well usually has to be killed. This means that the pressure of the formation has to be equaled by pressure from above, usually by injecting treated water, oil, or formation water into the well. This brings the flow of formation fluid to a temporary halt. The fluid that is injected will eventually dissipate, allowing the well to flow once more. Swabbing the well can help hurry that process along. If more fluid is injected, the well will be killed for a longer period. The precise moment the well will begin flowing again can’t be predicted, so the workover should be completed in a time efficient way. If water is used as the fluid, potassium chloride can be mixed in to prevent the formation from being over hydrated.


Figure 1. Some equipment used for workovers. Shown is a water holding tank, a mud pit, and mud pump.

Blowout preventers may be installed as part of a workover. This is a valve at the top of the tubing string that can be shut to cut off flow from the well. Most are made up of two parts. In the upper part are rams that will enclose the pipe when closed. The lower part has several blind rams which are closed when the pipe is not in the hole. That means the flow can be contained if it begins at any point. There will need to be a quick switch between the christmas tree and blowout preventer.


Why Workover A Well?

A workover is an expensive operation, and it’s usually worth it only if there’s a serious problem or it could lead to a genuine increase in production. The majority of workovers are used to address problems downhole.


Stuck Pipe

Tubing or other pipe may become stuck when you attempt to pull it from the well. A workover may be required to free the stuck pipe so maintenance can be carried out and flow restored. Stuck pipes are usually caused by a few common problems.

Salt bridges are one of the more common problems that can lead to a stuck pipe. Salt bridges are created when the well is pumped in several daily cycles and the formation holds very salty water. The water will collect in the annulus space until pumping begins, when it will drain out. The water leaves behind a salt residue. When the process is repeated many hundreds of times over months of pumping, the residue can build up into bridges that block the annular space. Production can be reduced or even stopped altogether by the salt bridges that form. Fresh water can be dropped in the annular space, dissolving the salt. Salt bridges may still occur, however.

Scale can have a similar effect when it builds up over time. More scale will break out of the water as the temperature and pressure drop. Scale buildup can be drilled out, though there are chemicals and coatings that can be used to reduce scale.

Sand may also migrate to the bottom of the hole, and gravel may also become packed so that pipe or other equipment becomes stuck. Adding screens to perforated joints can help keep sand out of the well.


Stripping Wells

When both the tubing and rod string are removed from a well at the same time, it’s called stripping the well. The rod string can be broken out if the pump clutch is engaged and the rods turned counterclockwise. When the rods are turned enough, the rod will break. The upper part can be pulled, and then the tubing is also pulled so that the loose rod string comes to the surface. That’s repeated until both the entire tube and rod strings have been pulled from the well.

A notch or clutch is placed on the bottom of most downhole pumps, which is what allows the rod string to be broken from the surface. At the bottom of the pump is the clutch, and the string is lowered until the clutch engages and the rod string can be broken. A clutch is also placed at the top of some pumps, allow the string to be raised until the clutch engages. The placement of the clutch should be noted in the records, but the string can also be lowered or raised until the clutch engages. Safety joints can make it easier to separate the string so it’s easier to pull. Using a safety joint presents its own problems, however.

When stripping a well, there’s a risk of spilling oil. Lighter oils may also begin flowing up in the well, and potentially even lead to a blow out. All of these are time consuming and expensive to clean up. These problems can be prevented by using some special equipment, swabbing, and some other basic safety procedures.


Fishing Parted Tubing

Removing parted tubing from a well can be a pain, particularly when it’s difficult to catch and latch on to the loose, broken end downhole. To make fishing the tubing easier, a custom tool may be designed and made in a shop. Before that tool can be made, however, one or more impression blocks need to be run.

An impression block is a flat tool that is run downhole. The bottom face is made of some soft material which can be dropped onto the parted tubing so an impression could be made. A standard impression block is made of soft lead. In some cases, a softer block shop-made of tar may be used, or a harder block may also be used. The block is attached to the tubing and allowed to string and allowed to drop down the hole.

A variety of tools are available for rent and can be used to catch different types of parted tubing. An overshot with a milling surface is helpful when trying to catch a rounder fish and a spear is a tool best suited for fishing a jagged opening. The tubing string may fall to one side of the casing. When that happens, an offset finger can be constructed in the shop. This is a tool that wraps around the string when turned. The company that rents the tools may also have specialist that can help with difficult operations.


Fracturing Operations

Fracturing operations, better known as fracking, are done as a way of increasing the porosity of a formation, allowing a higher flow and an increase in production. There’s a wide range of fracking techniques and technology available.

The fracking process includes applying hydraulic pressure to split rock open. Sand is then injected into the fractures. The sand is much more porous than the rock, and allows for an increased flow through the formation. A few different fluids can be used to apply hydraulic pressure. Treated water, water produced from the well, and crude oil are the most common fluids used. A few other fluids made from petroleum products are also in use. Water soluble rock salt or oil soluble moth balls are added to the fluid so that it will penetrate further into the reservoir and create a deeper fracture.

Another sort of fracking uses high pressure acid to etch new passages and widen existing flow paths. A chemical called a neutralizer will make the acid safe after a period so that it can be produced back up to the wellhead after fracking has finished.

There are a few other more specialized forms of fracking, such as explosive heat fracking. That’s a method that is best used in shallow wells where denser products like paraffin are common.


Other Reasons

A well workover may be done for several other reasons. In some cases, it may be necessary to drill scale out of the bottom of the hole to bring production rates back up to expected levels. In these cases, the tubing can be used as a drill pipe by adding a rotating head and a power swivel.


Figure 2. This rig for working over a well has a double blowout stack so it can continue to be produced while the workover is in progress.

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Moving tools and equipment up and down the casing is important for locating and repairing problems in the well, as well as monitoring conditions downhole. When tools need to be run in the well, or the tubing or other equipment pulled out of it, it will be done using a wire line. Wire lines might be used to pull tubing or rods, cut paraffin, swab fluids, conduct surveys, and a number of other things.

Wire Lines

Wire line is available in a few different types, each with their own advantages and disadvantages. They might be laid up wire, solid wire, or wire that can conduct an electrical current into the well.


The Basics Of Wire Rope

As mentioned above, wire lines may be of a few different types. The style most often encountered is wire rope, which consists of smaller, solid strands of wire that are woven together, more technically referred to as laid up. This is similar to twine or fiber rope. Wire rope might have a central core around which the individual, smaller stands are braided. Figure 2 shows the different parts of the rope.

Wire Lines

Figure 1. Shapes of wire rope. (courtesy of Williamsport Wirerope Works, Inc.)

Wire Lines

Figure 2. A diagram of a basic wire rope. (courtesy of Williamsport Wirerope Works, Inc.)

The rope can be laid up in different ways, usually left or right hand lay. This has some implications for how the wire line should be handled and possibly some other considerations. In Figure 3, you can see several different styles of laid up wire rope. Right hand lay is much more common.

Wire Lines

Figure 3. Examples of wire rope. (courtesy of Williamsport Wirerope Works, Inc.)

It’s important to measure rope using the correct method, so that you can identify the correct tool and equipment size to use with that wire. Always measure the rope across it’s widest dimension, as it’s the total diameter of the rope that’s important.

Wire Lines

Figure 4. Correct and incorrect ways to measure wire rope diameter. (courtesy of Williamsport Wirerope Works, Inc.)

While wire rope is fairly sturdy stuff, it can be damaged if handled or used incorrectly. Damage is essentially permanent and will have a long term impact on the rope’s strength and use. Wire rope, wherever it is used, should be protected and inspected before each use.

Wire Lines

Figure 5. Examples of damaged wire rope. (courtesy of Williamsport Wirerope Works, Inc.)


Types of Wire Line

Wire can be used for a few different purposes. Some uses will require a specific type of wire line, while some types of line are multi-purpose.


Line From Drum To Blocks

These lines will run from a reel drum on a servicing unit or derrick to the blocks. The blocks are the pulleys used with that equipment to provide mechanical advantage. The wire rope used with a servicing unit, is different from that used with a drilling rig in a few important respects.

Wire line used with a servicing unit will be resistant to rotation so that elevators don’t turn on their way up through the derrick. This is a particular consideration when only using a single line. This line is also designed to be used on the surface only, and don’t have the same protection against corrosion and other downhole problems.

This line will need to be at least 500 feet long, though it will usually need to be quite a bit longer. The wire is run back and forth between the blocks many times, and it’s important that there is enough wire to lower the traveling block all the way to the floor. There should be some reserve on the drum when that’s done. Also, a length of the worn line should be cut off according to the ton mile schedule. There should be enough reserve line that the blocks can be re-threaded, which will extend the useful life of the line.


Sand Lines

While wire lines may be used in various places around the lease, the lines that are run down into the well are going to get most of your attention. The sand line is a wire line with a high tensile strength and which is used to run tools and equipment down into the well. The line is placed on the second drum of the pulling or servicing unit, or on the drum closer to the cab. This line should be long enough to reach the bottom of the hole.

Sand lines are basically utility lines that can be used for a wide range of purposes, depending on the tool or piece of equipment that is being run on it. For example, by using the sand line with a swab, fluid can be lifted out of the hole. This might be done for a variety of reasons, but it is usually done to clean up the wellbore and matrix area. It may also be done to remove pressure from the tubing so that fluid can flow into the lines and tanks.

The sand line can also be used for bailing sand. Sand may migrate to the bottom of the hole during pumping operations, carried by the flow of fluid through the formation. When the tubing is pulled for service, this sand can be bailed out. The sand line can also be used to cut paraffin and remove scale. In Figure 6, you can see an example of a paraffin cutting tool.

Wire Lines

Figure 6. An example of a paraffin cutter.

When a rod parts, it needs to be fished out of the hole so it can be replaced. Unfortunately, because the rod parted it may be difficult to fish it using standard equipment. When a loose rod string is troublesome to fish, an impression block or tool can be sent down into the hole. This is a flat bottom tool made of soft lead. When run down onto the parted rod, the end of the rod will leave an impression in the block. A custom tool designed to hook that rod can then be made.

The sand line may also be used to pull a standing valve out of the tubing. Standing valves may be dropped into the tubing for a few reasons, primarily to check for leaks. The valve is dropped into the string. Once the valve is in place, the tubing string is filled with water and then pulled. The water will drain from the leak, so that the level of water in the tubing will show where the leak is. When this point is reached, the standing valve can be retrieved without having to pull the entire rest of the string.


Solid Wire

As the name implies, solid wire lines are a single strand of solid wire. It’s used in special circumstances, generally for running tests, placing valves, or dropping a pressure measurement device called a bomb. Some of the common tests and uses that may require a solid line include:

  • Temperature surveys. These are used to detect leaks in the tubing string. Gas will often escape through leaks and expand, causing a detectable drop in temperature. These surveys are usually run a regular basis, as frequently as every 6 months or as infrequently as once a year.
  • Pressure surveys. These are also run on a regular schedule, usually once a year. These surveys measure the pressure at the bottom of the hole. By comparing these readings to previous years’ measurements, the drop in reservoir pressure can be determined. This is useful information that can help to determine things like the amount of fluid remaining in the reservoir and gauging the effectiveness of pressure maintenance operations. It’s also possible to predict when a naturally flowing well will need to add artificial lift.
  • Directional surveys. When drilling a well, a direction survey may be run on a solid wire line. A clock is set within the survey bomb before it’s lowered into the hole. When the timer runs out, the bomb takes a 180 degree impression.
  • Other uses. Solid wire can be used to place valves, scrape paraffin and scale, and a few other specialized uses.


Electric Lines

Electric lines are used for many tasks that require powered tools or equipment be lowered into the well. A well that is being drilled will need open hole survey logs to determine whether the well is worth completing. Cased hole logs may be required once casing has been run into the well, and will be followed by the cement bond log after the casing has been cemented. Electrical lines will also be used to create perforations, for measuring depth and other surveys, and for a variety of other reasons.


Guy Lines

Guy lines are essentially structural supports. Unlike most of the other wire line described here, guy lines do not run down into the well. They are instead wire lines that run from a tall structure, like a derrick or servicing unit, to the ground to provide stability. Guy lines are most often the standard right hand lay. Wire used for this purpose will usually have a smaller diameter than wire on the drum. You should be sure that the correct size line with the correct strength is used, as it’s possible that guy lines may be put under a fair strain.

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Fluid is pushed up out of the formation and to the wellhead by a number of possible sources; the pressure from the formation may be enough to do it, or artificial lift may need to be used. Whatever provides the force, the fluid’s route to the surface is the tubing string. This tubing run down into the well within the casing. Tubing joints are threaded together into a long string, which is then perforated near the bottom to allow fluid from the formation to flow into the tubing. The tubing string is an integral part of the well, and so it should be well understood.

Tubing String


Tubing String Basics

There’s a range of different tubing options with different wall thicknesses and of varying metal quality. The tubing is a seamless pipe that is sold in a range of irregular lengths from 28 to 40 feet. By selecting and assembling tubing joints of the right mix of lengths, a tubing string of any length can be put together. Shorter joints are called pup joints, which are available in lengths from 2 to 12 ft long, in 2 foot increments.

The outside of the tubing will be stamped with a mark showing its quality. While there are a whole range of options, and it’s a good idea to investigate options that might be tailored to specific situations, there are some types that are more common. These can include:

  • H-40: Designed for shallower wells, this is an economical option.
  • J-55: Designed for use up to 7,000 feet deep, it’s the most common tubing for medium depth wells.
  • C-75: An upgrade from J-55, this tubing is used in similar wells but is less common.
  • N-80: Pipe designed for wells that are 12,000 ft in depth or more.
  • P-105: This is a heavier duty pipe that is intended for deep wells, or for formations with high gas pressure.

Joints are threaded so that they can be assembled into a tubing string. The threads may be v-shaped or round, referring to the cross section of the threading. V-shaped threading will have a cross section that comes to a point, similar to a wood screw. Round threading has a rounder cross section, similar to some types of bolts. Round threads are more common these days, though v-thread is common with older equipment. The round threads are hot rolled onto the metal of the tubing, and are therefore much stronger.

Tubing String

Figure 1. Shown here is the end of a tubing joint, with the upset end and tubing collar visible.


Measuring Pipe Diameter

There’s no general standard when it comes to measuring the diameter of pipe and tubing used on an oil lease. Depending on what the pipe is being used for, the diameter listed for pipe or tubing might be the inside diameter (measuring the empty space inside the tube), or it might be the outside diameter (the total width of the pipe). Since tubing and line piping can sometimes be interchangeable, this can lead to confusion. However, one general rule can clear up most confusion. If the pipe is being used for line pipe, the inside diameter is measured, as the volume of production the pipe can handle is of more important. For pipe that is going to be used as tubing downhole, the outside diameter is the more important measurement. That is because it is the measurement needed to select tools for fitting and assembling the tubing string.

As an example, line pipe might be listed as 2 inches in diameter in lease records. If the same pipe is used for tubing, however, it would be listed as 2 ⅜ inch in diameter, as that includes the total width of the pipe. The two types of pipe can usually also be distinguished by length, with line pipe usually coming in 25 ft lengths and standard tubing sizes being longer and less regular.


Perforation Placement

The casing and tubing are both perforated to allow fluid to be pumped up to the surface. The relative placement of these perforations can have an impact both on production and maintenance needs. The tubing perforations can either be placed above or below the casing perforations, with implications for pressure, the accumulation of scale, and other issues.

Tubing String

Figure 2. Tubing, casing, and downhole pump diagram. (courtesy of Harbison Fischer)

Moving the tubing perforations can have a range of effects, and it’s not always clear what those effects will be. In some situations, the tubing is placed above the casing perforations so that less scale breaks out in the tubing and lines. If the tubing perforations are not placed too high, production can be kept at desired levels.

Other wells keep the tubing perforations below or even with the casing perforations. The goal is reducing reservoir pressure to improve production. While the lower placement may lead to an increase in maintenance problems, the production increase is enough to pay for the maintenance and still show an increase in profits. Tubing perforations may be lowered even if that doesn’t leave much room for a mud anchor. A joint of tubing about 2 feet long is custom made, closed on the bottom and with several dozen ½ holes drilled into it. It can be screwed to the seating nipple with a collar, reducing the length of the mud anchor to under 1 foot. The standard arrangement is to have the tubing perforations several feet above the casing perforations. The intent with this choice is to keep a slight back pressure on the formation rather than pumping the bottom of the hole dry.


Running and Pulling A Tubing String

It’s important that tubing strings are made up to the correct specifications. A loose joint can lead to a leak, which can be expensive and difficult to fix. If the joint is made up too tight, the threads of the coupling will be damaged. In most cases, hydraulic tubing tongs are used to makeup and break down the tubing string. Hydraulic tongs are generally superior to hand tools, as the correct torque can be set without the danger of damaging threading. Tubing should also be handled carefully when it is standing in the derrick and before it’s run into the well.

Before tubing is run into the well, a rabbit will usually be dropped through the joint. A rabbit, more technically known as a drift diameter gauge, is a length of pipe of a particular outside diameter. If the joint is not truly vertical, the rabbit will get hung up inside the tubing. The rabbit will also get hung up on scale buildups and other issues that will affect flow up to the wellhead.


Tubing String Components

The tubing string will have a few different components. While different operations may need additional equipment to address specific problems, most tubing strings will include a few basic parts. Each component should be recorded in the order it is run into the well.

The mud anchor is mentioned above as being the first joint lowered into the hole. It consists of a full joint of tubing with a bull plug, a solid plug, on the bottom. The mud anchor will usually hold a few feet of mud and sediment when it’s pulled from the well. The mud anchor will also protect the gas anchor on the pump.

The tubing string will primarily be made up of joints of tubing. Tubing joints come in odd lengths, so by combining different lengths of tubing joints a tubing string of any length can be created. The spacing of joints can be important as well. For example, wells using gas lift will need lift valves at specific heights. Pup joints can be used to make up specific lengths. Whether you use collars or couplings, they should be of equal or higher quality as the tubing used in the string.

When recording details of the tubing string, it should be indicated if the threading was included in the joints’ measured length. Over 100 joints, the method of measurement can change the length by as much as 15 feet. The most accurate method of measuring the length is from the top of one collar to the next with the slips removed, when it is hanging from an elevator.

A nipple is any short length of tubing or piping that has threading on both ends, usually with male threads. A perforated nipple may be used, which is a length of tubing that has rows of 1/2 inch holes drilled into it. It is also possible to have a combination perforated-mud anchor custom made in a shop.

A seating nipple is used to seal the pump to the tubing while allowing fluid to be produced to the surface. It’s a short length of tubing with upset ends that have tapered openings. A cup type seating pump will need a seating pump less than one foot long. Longer nipples can be reversed if the nipple becomes damaged. Some mechanical seating nipples may not be reversible.

Other components added to the string may include safety joints, packers, and holddowns. These should be included when recording the makeup of the tubing string. Specifics including brand, model, and any instructions for handling should also be included in the record. Some tools may remain downhole for years, and the instructions listed may be the only record of how to set or remove them. Wellhead hangers are added to the top of the string, and you may need to pull tension on the tubing string.


Troubleshooting Tubing String Problems

Most problems regarding the tubing string involve leaking joints, which can lead to a loss of production and can be difficult to locate. Leaks are usually caused by holes corroded into the tubing, or split tubing or collars.

Tubing String

Figure 3. An example of a few damaged tubing components. Shown are a split collar, a brass pump part that has been damaged, a corroded part, and two sucker rod boxes that have been damaged by wear.

Leaks may lead to no fluid being produced at all, though the bleeder valve shows acceptable pressure. A leak can often be confirmed by using a pressure gauge at the bleeder valve and then closing the wing valve. By pumping against a closed in system, a leak can be detected. One person should be monitoring the pressure gauge while another standing at the switch or clutch. Going through the same process can also clear trash from a pump valve.

A split collar or hole in the tubing is usually pretty straightforward to identify, as they result in no production at the bleeder valve. Aluminium paint or another tracer can be mixed into oil and then poured into tubing. The tubing string is then pulled and watched for signs of aluminum paint on the outside of the tubing, which will point to the leak. The leaking joint can then be replaced and production resumed. It’s unusual to find more than one hole at a time.

Leaks can sometimes be more difficult to find. When that’s the case, a standing valve can be dropped down the tubing, to the pump seating nipple. The tubing is filled with fluid and then pressurized before the tubing is pulled. The fluid will drain to the level of the hole, which can then be easily found. The standing line can then be retrieved from the tubing string using the sand line and an overshot. The standing valve may allow you to release the fluid in the string, and therefore release the pressure, before it is unseated.

Tubing String

Figure 4. An example of a 3 cup standing valve. This particular one was manufactured by Harbison Fischer.

When tubing splits, it can be difficult to identify the problem and locate the split. With split tubing, oil may still be produced to the tank battery. In some cases, the bleeder valve may show acceptable pressure while no production is sent to the battery. Comparing the flow line pressure to past pressures may indicate a split tubing joint; a drop in the pressure will confirm that there is an issue.

If the leak is particularly sneaky and difficult to find, hydrotesting can be used to find the problem. With this process, the tubing string is pulled. As it is run back into the hole, two joints of tubing at a time can be tested under high pressure. Hydrotesting requires special equipment and a trained crew. Sucker rods are used to place the hydrotesting tool, which is 75 feet long. The tool is pulled up just below the slips for the test. It should not be pulled any higher, as that can be unsafe.

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Wells may flow naturally when they are first completed, but at some point a pump will be added to aid in production. That pump can be of a few different types, but the most common variety is going to be mechanical lift. The majority of wells produce small amounts and use mechanical lift as an economical and reliable way to increase production. There are three general parts to a mechanical lift: the prime mover at the wellhead, the pump downhole, and the rod string that connects the two. As the name implies, this component of the pump consists of a long string of sucker rods that are threaded together. The prime mover at the wellhead moves up and down and the rod string runs through the tubing, communicating that motion to the pump and producing oil.

Rod Strings


Rod String Basics

Rod strings have to be matched to the pump they’re powering and the depth of the well. It’s important to remember that the rods themselves can be heavy, making the total weight of the rod string high. In addition to that, the rod string will undergo a strain while the pump is in operation. The string may actually stretch as it lifts fluid, and then compressed as the string is forced back down.

To handle that weight and strain, rods of several different sizes and strengths may be used. Choosing the correct rod arrangement involves balancing the weight of the rod against its strength. Understanding how rods are rated is an essential part of assembling a rod string.


Rod String Ratings And Sizes

Rods are rated using a system developed by the American Petroleum Institute (API). This system uses letters to indicate a general range of tensile strength. The different ratings have specific strength ranges, but in general rods rated C are for light to medium strength uses and D rated rods are for medium to heavy uses. Other rods may have similar strength ranges, but have other advantages. For example, K rods are made with a nickel alloy, and so may have a greater corrosion resistance. For many shallow wells, anything 2,000 feet deep or less, equipment rated for downhole use will be strong enough.

The letter can be used in the records to indicate the varying strength of each rod in the string. These letters are also stamped on the rod itself, on the flat side of the pin.

Rod Strings

Figure 1. An example of a Class D Rod, showing the rating stamp. (courtesy of Trico Industries, Inc.)

Rods will wear out, eventually, and need to be replaced. Rod strings will begin to break and other problems will become more common as the rod string reaches the end of its useful life. When the string is pulled, there may be many lengths of rod that are still intact and may be used again. It’s important to note that these rods will most likely no longer meet the standards for the strength rating stamped on them. These rods may be downgraded one step in rating and used elsewhere. For example, what was a Class D rod when it was manufactured will become a Class C rod. Obviously, rods that are damaged or otherwise not fit for service shouldn’t be downgraded and reused. The records should show any downgrade, and generally the recorded strength rating should be trusted over the rating stamped on the rod.

Rod Strings

Figure 2. An example of a tubing and rod record. A record like this should be maintained for every well.

The size of a rod is also important. As the rod string must travel up and down the inside of the tubing string, it’s important that the correct diameter of rod is chosen. Another system is used to denote the rod’s diameter. This system gives each rod a number, which lists the diameter in ⅛ inch increments. For example, a rod that is ½ inch in diameter contains 4 ⅛ inch segments, so it is a #4 rod. A #5 rod is ⅝ inch in diameter, a #6 rod is 6/8 inch or ¾, and so forth. Rods generally range from a #4 (½ inch diameter) to a #10 (10/8 inches, or 1 ¼ inch diameter).

Rod Strings

Figure 3. This sign lists the rod quality to be used with at this well.


Tapered Rod Strings

A rod string may not all be of a single uniform size. In some cases, the string will use larger rods with a higher strength near the top of the string, where the most weight is being supported. Further down the rod string, however, a narrower rod may be acceptable. The rods themselves aren’t tapered; instead, rods of different diameters are used, with different sizes of rods being connected with a changeover coupling. Usually, only 2 or 3 sizes of rod will be used. Each changeover step will only change the diameter by 1 step. So, a #5 rod could be connected to a #4 rod or #6 rod, but not a #7.

Using that system, it’s possible to list the diameters of all the rods in a string with just a couple of numbers. A rod string that’s listed as 5, for example, will use all ⅝ inch rods. A string that’s listed as 75 will use #7 rods, #5 rods, and also #6 rods between them. A string that’s listed as 107 will have #10 rods, as well as #9, #8, and #7 rods.

Tapered strings offer a few advantages. The total weight of the string is reduced, and a smaller pumping unit can also be used. Less horsepower is needed for a tapered string, as well. Tapered strings are more complex to put together, and it’s a good idea to get a qualified expert to consult when considering one.


Fiberglass Rods

In the past, fiberglass wasn’t considered a good material for sucker rods. However, the manufacture and quality of rods made from that material has greatly improved. A rod string using fiberglass does require a few steel rods. These are at the bottom of the string, connecting it to the pump. The steel rods help prevent the compression of the fiberglass rods. The travel length of the pump will be increased with fiberglass, while the overall weight of the string will decrease.

Fiberglass rods generally only weigh about ⅓ of their steel equivalents. That decrease in weight means that a smaller pump or gearbox can be used. Fiberglass rods are also generally somewhat longer than steel rods, measuring about 35 ft long. That means that when you do pull the rod string, it will only be possible to pull them in doubles, rather than triples as is usually possible with steel rods.

Fiberglass rods can generally be handled in the same way as steel rods, though there are some special considerations. The manufacturer or supplier of the rods will usually have instructions that detail how the rods should be handled and maintained.

As this is a material that can be damaged by exposure to the sun, fiberglass rods should always be stored in a warehouse or otherwise protected from direct sunlight. Fiberglass that is left in the sun may suffer from fiber bloom. It’s made from thin strands of glass spun into fiber, which are embedded in an epoxy. That epoxy can be broken down by sunlight, leading to the exposure of the glass fibers in a white ‘rash’, which is known as fiber bloom.

Rod Strings

Figure 4. Tap and die tool that has two different sizes.

As with all rods, fiberglass rods should be handled carefully. They can be more fragile than steel rods in some ways. When performing service that requires pulling the rod string, the rods should always be tailed in, and never thrown or dragged on the ground. Any damage, even what may seem like a minor nick, is permanent and can potentially cause the rod to be taken out of service. Occasionally these rods are cross threaded; this can be fixed by using a tap and die and then lubricating the threads. It should be possible to screw the join back together correctly after that fix.


Rod String Components

While rod strings are primarily composed of rods threaded together, there are a few other components and specific types of rods that may be included, and which are important to note. When running a rod string into the well, for example, each part should be recorded in the order in which it went down.

The first thing into the well, making it the bottom of the rod string, is the gas anchor. A gas anchor is similar to a downhole separator, in that it controls the amount of gas that is allowed into the tubing string. It’s usually mounted below the downhole pump. Many people recommend that a gas anchor be large enough to hold 1 ½ the volume capacity of the pump. The size of the gas anchor will usually depend on the bottom hole space, however, with some smaller gas anchors being only six inches long.

Next down the well is the downhole pump. It’s possible that you’ll be running a rod string back into the well after replacing a worn out pump. It’s important to be aware that the new pump may result in a slightly different rod string length. The new pump and old pump should be laid out next to each other and the no-go sections lined up. If the new pump is longer, the polished rod at the top of the string will need to be adjusted to make up the difference. If the difference is great enough, a pony rod may need to be added to or subtracted from the string. The new pump length should be noted, and a full description of the pump added to the records.

A pony rod is a shorter than the standard rod length. Custom lengths are available, but they most often come in 2 foot increments from 2 to 12 feet long. Pony rods may need to be fitted between the pump and the rod string. They may also need to be installed between the rod string and the polished rod at the top of the string.

The rods themselves will obviously make up the majority of the rod string. When the string is run into the well, the number of rods, their rating, and their size should be recorded. It’s important to record the rods in the order they went into the well. This is particularly important for tapered rod strings, where the precise count of each type of rod can be critical. While a length for each rod should be recorded, the rods may be stretched several feet longer after some use.

At the very top of the rod string is the polished rod, which allows a good seal at the wellhead. A lift pony rod may be used, though if it is not, a coupling should be used to protect the threads on the end of the polished rod.

Rod Strings

Figure 5. An example of different sized polished rod threading. Shown from right to left are 1 inch rod, ⅞, ¾, and ⅝ inch rods.

A polished rod liner may also sometimes be used. It is placed over the polished rod, but needs to be at least 3 ft longer than the stroke length. The additional length keeps the liner from being pulled out of the stuffing box with each stroke, and also allows you to add a lubricator. It’s also usually a good idea to leave extra length to the liner in case the stroke length is changed.

The record of the rod string should be sent to the company’s office, but before it’s sent a copy should be made with the rods listed in a reverse order. In other words, the rods are listed starting at the top and going down, which is handy the next time the rod string has to be pulled.

Once the rod string is put back into service, it should be monitored closely. Tension on packing may need to be fine tuned, and the wellhead and lines should be checked for leaks. The battery and lines should also be inspected and made ready to handle the new production.


Pulling Rod Strings

Pulling and servicing rod strings may be the job of a specialist, but for many companies it’s a duty assigned to the pumper assisted by a crew. When pulling rod strings, it’s important to lay them out and handle them so that they can be run back into the well in correct order. Rods should also be handled carefully to prevent them from being damaged. A rod elevator can be very helpful. An example of one can be seen in Figure 6.

Rod Strings

Figure 6. An example of a rod elevator. (courtesy of Trico Industries)

Rod elevators can be used to lift rods when the box is allowed to break on either side (meaning that either end of the rod may come unscrewed). A rod elevator can be used to lift the rods in that case.

When making up rods, the correct procedures should be used to make sure the rods are not damaged. Special tools will need to be used, such as the special hand wrenches shown in Figure 7. Both over tightening and under tightening a rod can lead to damage. Makeup charts are available and should be consulted. Some companies prefer to use power rod tongs, which are powered tools that can be used to apply torque to rod string components. These are usually pneumatic or hydraulically powered.

Rod Strings

Figure 7. Hand wrenches that are used for assembling rod strings. (courtesy of Trico Industries)

As mentioned above, rods should always be handled carefully so that they’re not damaged. The downhole pump should also be handled carefully, and it may be necessary to use a support bridle to move it safely.

Rod Strings

Figure 8. An example of a rod hook. (courtesy of Trico Industries)


Fishing Parted Rods

Rods that are excessively corroded may break, parting either when the pump is in operation or when it’s being pulled. Most breaks occur on the shank of the rod, but you may find them anywhere. The process of regaining control of a parted rod string is called ‘fishing’ the string. To fish a parted string, an additional rod and a tool used to catch the loose rod string are added. The string is then run back into the well, and the loose string is caught. The fishing tool should be matched to the rod box being used, as several different types are in use.

Rod Strings

Figure 9. An example of a tool used for fishing parted rod strings. (courtesy of Trico Industries)

If the pump unseats when the parted string is caught, the servicing unit brake should be applied to prevent jarring. Too much jarring may trigger the overshot release, dropping the fished rods and potentially parting the tubing. Pulling tubing while a rod string is loose is difficult and can be time consuming. The tubing might be stripped over the dropped string, leaving it loose in the casing.


Downhole Pumps

Rod strings may have to be pulled when pump components downhole wear out. Pumps will fail on a fairly predictable schedule, and it’s possible to roughly estimate when a pump will need to be replaced. Studying the records can also give clues as to why pumps failed, allowing you to avoid or mitigate those problems. When a pump is serviced, it will often be sent off to a repair shop. The shop should know how to repair the specific pump and use the correct parts. Incorrect repairs can have an impact on production, and incorrect parts can shorten the pump’s life.

Pumps may sometimes get stuck down the well. It’s rare that this happens, but occasionally rods bind or a pump will catch in the tubing. While uncommon, this can be a serious problem. New rods of the same type will all be the same length; when hung from the derrick, the ends will line up. Rods will stretch as they are used, though, and trying to pull a stuck pump from the well can stretch them further. If pulled too far, the rods don’t rebound when pulled; that stretch has become permanent. At that point, the rods may no longer be fit for service, so it’s important that the rods not be pulled beyond the weight indicator’s recommended maximum. Rather than pulling the pump up with the rod string and potentially damaging it, another option is to begin a stripping operation. That’s an expensive alternative, however. In operations where stuck pumps are common, there may be some additional options.

Is your appetite for oil & gas operating knowledge insatiable like ours? 😀 If so, check out these related articles below – they’ll be sure to pump you up!!!

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