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.

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All wells will need to be serviced at some point, either for maintenance or because there’s been a drop in production. To properly service a well, it’s necessary to have a broad understanding of the well’s history, the tools and techniques available, and a range of other information as well. Used well, that information can lead to an extended production life for a well. If wells are not serviced, or not serviced correctly, it can lead to the abandonment of a well that is still capable of producing. Servicing a well may require pulling rods or tubing and running tools downhole.

Servicing

 

Well Records For Servicing

It’s a good idea to take a look at the records for the well before beginning service. These records will provide specific information about the well that will be important when pulling, servicing, and replacing a tubing or rod string, as well as for running tools down the well. Records can also help indicate any problems, as a look over the history of the well will show production levels, changes, and other factors that may have an impact on the well’s behavior.

Information about the well casing should be examined. The casing information sheet will indicate the distance from the wellhead to the perforations, the distance from the perforations to the bottom of the casing, and  specifics about the perforations. The tubing tally sheet will have similar information for the tubing string. It will list elements that make up the tubing string, such as where the joints of pipe are, as well as information about the packer, the seating nipple, and the mud anchor. All of these will be listed in their order in the string from the tubing head to the bottom. It will also list whatever other equipment may be in the hole. The packer or holddown description will also have this information, but will generally include more detail. That record should include enough information to safely pull the piece of equipment if necessary.

A rod tally sheet will also have important information. The length and size of every rod is listed, as well as type of rod. For tapered rods, the number of each type of rod will also be listed.The tally sheet will also have instructions for releasing a safety joint, and any other special instructions. The pump description is useful if the pump has to be pulled, though a more complete record of the pump used should be included with the lease records.

Also we go into more depth on the recording and importance of proper well records here Well Records For Oil & Gas Production.

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Well Servicing Units

Specially equipped servicing units are required to pull rod and tubing string out of the well. This can be a lengthy process where the tubing and rod sections are brought up and disconnected from the string, which clears the way for the next section to be brought up, and so forth. There are three basic types of servicing units: single pole, double pole, and single mast. Some may have one or two wire drums. With a single drum, it’s possible to run only a single wire down into the well so these units are usually able to either pull rods or tubing, or swab the well, but not both. It is possible to do both by switching lines, though that can be complicated. A double drum unit can run two wires, and so is able to do a wider range of tasks. The smaller single or double pole unit may have either one or two drums, while the mast unit will always have 2 drums.

Servicing units are usually large pieces of machinery which are accompanied by at least one other truck. It’s possible that a whole caravan of support equipment may be necessary, depending on the service you’re performing. It’s important to follow some basic safety guidelines when bringing a service unit to the well site, as well as when operating the unit. Make sure everyone is aware of the plan and what’s going to happen. Have drivers discuss routes and potential problems before setting off, and take similar steps to prepare. A little common sense can prevent larger problems down the road.

 

Single Pole

These units have a single mast and a single drum and are used to service shallower wells. With a single pole unit, the rod or tubing sections will have to be laid out on a rack as they are brought to the surface. These units are small enough that it’s possible to run with them just a crew of two, an operator and somehow on the floor. However, an extra hand is usually a good idea, so getting a third crew member is probably wise.

The pole will most often be in two parts, with the higher section telescoping out of the lower section. The pole will also have to be secured with guy wires. The bottom section may have as many as 8 guy wires, while the upper section will most likely have fewer. The servicing unit base will most often also have guy wires to keep it securely on the ground.

Servicing

Figure 1. Correctly securing guy lines. (courtesy of Williamsport Wirerope Works, Inc.)

When setting up the servicing unit, you’ll want to work from the bottom up, securing each section before moving on to the next. The base of the unit should be secured with guy wires before the lower section of the pole is raised. Likewise, the lower section should be secured before the last section is raised.

That upper section can often be raised to one of several different heights, depending on the type of service. Rods are generally around 25 feet long, so the mast only needs to be raised high enough for the rod to be lifted safely. Tubing section are generally longer, so the pole may need to be raised further. Single pole servicing units are popular with companies that have a number of shallow wells, as they can usually afford to buy one of these units themselves, reducing long term costs.

 

Double Pole

Generally more efficient than single pole units, double pole units are generally able to handle a wider range of tasks. Because of the second pole, rods can be setup and hung in doubles (with two rods being lowered at once), though tubing still can only be run in single lengths. These units can also perform some types of work-over. They do require a slightly larger crew than single pole units, needing three of four people to operate safely.

When you pull the pumping rods, they need to be unscrewed from the rod below in order to be removed. When pulling rods in doubles, either end of the rod may come unscrewed. This unscrewing process is referred to as ‘breaking the box,’ with the box being another name for the female side of the screw. Since either end of the rod may be the one that comes unscrewed, it’s important to return rods into the hole in the order they came out. Each rod has a specific place in the string, based on strength, size, and a number of other factors.

Pulling tubing is a similar process with a few differences. The tubing will be supported by a collar on the lower end, so it’s always the upper joint that is broken. Tubing should be run back in the same order as it was taken out, as mixing up tubing sections usually leads to a higher risk of leaks. Thread lubricant should be used, and the correct torque should be applied when tightening joints. The manufacturer or supplier of the rod will usually have some information, on a card or sheet, that lists how tightly the joints should be made up.

A double pole unit is about the same size as a mast servicing unit, but it’s better suited for shallow or medium depth wells. Many operators like these trucks as they can service most wells, and it’s not unusual for companies to own one of these units.

 

Mast Unit

An example of a mast unit is shown in Figure 2. It’s able to pull more at once, taking tubing in doubles and rods in triples. Rods are racked by a crew member on the derrick, allowing the operation to go quite quickly. Mast units are usually required for deeper wells.

Servicing

Figure 2. A mast style well servicing unit.

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Preventing corrosion damage can extend the life of equipment and increase the efficiency of operations. While some corrosion may be inevitable, a whole range of techniques and materials have been developed that can prevent the chemical and electrical reactions that lead to corrosion. Investing in as many of those as possible while the well is freshly flowing, as there will a bigger budget for new equipment and maintenance.

Preventing Corrosion

Many different methods of corrosion prevention will be used together, as most will be targeted at solving one particular type of problem.

 

General Methods Of Corrosion Prevention

There are methods of corrosion prevention that are targeted at specific parts of a pumping operation. As corrosion is a problem throughout all pumping operations, a lot of methods can be used anywhere corrosion is possible.

 

Rust And Oxidation

Rust can be destructive, but in some cases it can be beneficial. Technically known as ferric oxide, rust is the oxidation of iron and metals containing iron. New steel that is left exposed to open air will rust quickly, but as the layer of rust thickens the rate of oxidation slows. The layer of rust scale on metal will eventually act as a protective coating. This idea works best in dry climates like the American Southwest. There, surface lines are often left bare as the rust is never bad enough to cause a leak. Unpainted pipe can be used for decades without a problem.

Oxidation can also be a protective coating on aluminum, copper, and other non-ferrous metals. Aluminum isn’t widely used in oil fields, as it can be easily damaged by acidity.

 

Painting And Coating

Painting is a basic way to prevent oxidation corrosion. Maintaining the coating of paint on tanks, lines, and other equipment is usually a part of regular maintenance. Some materials, such as galvanized steel, stainless steel, and nickel plated pipes don’t need to be painted.

Oil can somewhat protect the inside of lines when the oil isn’t corrosive. Coating on the inside of lines can be used to prevent some types of corrosion, and also occasionally in some tanks. The scale buildup that is the result of minerals in groundwater can actually also act as a lining to protect the inside of lines and tanks.

In the past, it was common to coat the outside of equipment with produced oil if it was going to be stored for a long period. Heavier weight oil with some paraffin can last for a while, and protect almost as well as a coat of paint. Environmental concerns have made it a less popular way to prevent corrosion.

 

Preventing Electrochemical Corrosion

Electrochemical corrosion is caused by a current which pulls electrons from metal in one place and deposits them elsewhere. The loss of electrons eventually leads to weakening of the metal. The current can either be the result of a natural force, like wind producing static, or the result of poor grounding and an electrical leak.

Insulating flanges are widely used to prevent the current flow that leads to electrochemical corrosion. The flanges are added to lines above ground level near the well and the tank battery. The flanges insulated the lines, preventing the flow of electricity.

A sacrificial anode can also be used to protect against electrochemical corrosion. Some types of electrochemical corrosion are caused by a natural battery cell, when two types of metal are immersed in a fluid. Electrons will flow from one piece of metal (called the anode) to a second piece of metal (called a cathode). The anode will be corroded by the loss of the electrons. A sacrificial anode will give up electrons so that the metal of the tank or line are corroded.

Preventing Corrosion

Figure 1. An example of a well used for cathodic protection.

Sometimes electrical current can itself be used to protect against electrochemical corrosion. Shallow wells with sacrificial anodes can be sunk near producing wells. These wells, called cathodic protection wells, allow small amounts of electricity to be sent to to the well and run back up in a circuit to the wellhead.

 

Materials Used For Preventing Corrosion

While steel is the preferred construction material in many cases, there are other materials that are now widely used that are less prone to corrosion.

Fiberglass was once used only as a lining for tanks. Fiberglass tanks are now common, used mostly for water disposal and holding chemicals. They are now also being used as holding tanks for crude oil as well.

Stainless steel fittings and metal plating are commonly used where crude oil is corrosive. Bolts, gaskets and seal rings, and smaller diameter tubing can all be made from stainless steel. Nickel plated fittings are also common. Plastics like polyethylene and polyvinyl chloride are good choices for use in highly corrosive situations.

 

Other Methods Of Preventing Corrosion

Chemicals can be used in some areas where painting, coating, and other methods of prevention corrosion aren’t feasible. These sorts of chemicals are expensive, but effective and constantly improved.

A few simple methods, known as mechanical barriers, can also help to reduce corrosion. Removing wet soil around lines and equipment will greatly reduce oxidation and electrochemical corrosion. Waterproof materials like tarred felt and gravel allow air to flow around lines and vessel. Buried lines can also be tarred and wrapped to keep moisture out.

 

Preventing Corrosion At The Tank Battery

Corrosion prevention at the tank battery is considered to be very important, as oil, water, and other fluids may be sitting in tanks for long periods of time. Before the battery is even constructed, steps can be taken to reduce corrosion problems, for example the ground the tank battery stands on should ideally be higher than the surrounding area, and sloped so that rainwater will run off. Crushed rock is filled under the battery so that air can circulate under the tanks and prevent rust. Tarred roofing felt is then layered over the rock to keep the tanks insulated. Steps to prevent the growth of plants should also be taken, as they can lead to corrosion in a variety of ways. Painting metal is a way to create a basic barrier and reduce corrosion.

Similar steps should also be taken when laying out and installing lines. Standing water and plants should be avoided. However, unlike when placing tanks, lines can’t always be routed to avoid these sorts of hazards. Elevating lines can help protect them somewhat, and coating or wrapping lines can help. Electrochemical corrosion can be reduced by the use of insulated unions, and are available in a range of types.

Preventing Corrosion

Figure 2. An example of a fiberglass wash tank. There is a PVC water leg directly in front of the tank, as well.

Protecting the inside of tanks needs some special materials and techniques. As with the outside, paint is a reliable, basic barrier. For the inside of a tank, you’ll want to use an epoxy paint designed for protecting tank interiors. Fiberglass liners can also be used to protect the inside of tanks, though entire fiberglass tanks are also becoming common.

Preventing Corrosion

Figure 3. This heater-treater has two sacrificial anodes, one to the right of the firebox, and the second directly below it.

There are also some chemicals that can be used to protect the battery against of corrosion, and also protect the whole system. Some chemicals can be injected down into the casing so they can be pumped back to the tank battery. Other general methods of protecting against corrosion, such as sacrificial anodes, can also be used. Sacrificial anodes are particularly useful with heater-treaters; a wire is run from the firebox flange to the anode. Current is sent through the system to the bottom of the heater-treater, which can protect it against pitting.

 

Preventing Corrosion Downhole

Preventing corrosion down the well can be more complicated. There are a few basic steps that can be taken. A ball and seat pump allow gas to escape into the atmosphere, while preventing oxygen from getting downhole and causing corrosion. Other corrosion prevention measures can require more work. However, reducing the impact of corrosion is important. Corrosion can cause holes in the casing that can cause leaks, overflows, and a loss of production.

Simply locating corrosion downhole can be difficult. Temperature surveys should be run on a regular schedule which can help to find leaks. As the fluid escape the casing, it expands and therefore the temperature drops. A casing survey can also help to locate holes in the casing. Gas is injected down into the annular space while the well is shut in, pushing liquids back down to the casing perforations. The gas pressure should remain consistent over a 24 hour period. If the pressure falls, a hole in the casing is allowing the gas to escape. A caliper survey can also help locate corrosion before it results in a hole.

Preventing Corrosion

Figure 4. An example of an insulated flange union used near the well. This particular valve is used to record line pressure.

Other measures include using insulating flanges and sacrificial anodes. These are used in generally the same ways as similar measures in other parts of the system.

Is your appetite for oil & gas operating knowledge insatiable like ours? 😀 If so, check out this related article, The Basics Of Corrosion And Scale For Oil & Gas Production – it will surely pump you up!!!

Scale and corrosion can be a major cause of equipment failure and other problems. Reducing and controlling corrosion is, in many cases, one of the primary ways you’ll be spending your time around an oil and gas lease. It is most often an issue with wells that produce a great deal of water. You can see a few examples of the effects of corrosion and scale buildup in Figures 1 and 3.

Corrosion

 

Scale and Corrosion Basics

Any reaction between a metal and its surrounding that leads to the breakdown of the metal is corrosion. The environment downhole and at the surface is often a perfect place for corrosion to take place. Many things can cause corrosion, but all involve either a chemical or electrochemical reaction. Chemical corrosion involves a reaction that creates a new compound that takes molecules from the metal, eventually breaking it down. A common example of this sort of corrosion is iron oxide, or rust.

Corrosion

Figure 1. Pictured are a few corroded parts, including parts from a downhole pump and a parted rod.

Corrosion

Figure 2. A cross section of tubing showing the scale buildup.

Electrochemical corrosion involves an electrical current which generally is created naturally between two different types of metal. The metal gives up electrons to create the current, which leads to a breakdown of the metal.

A variety of other factors can lead to corrosion. The pH and chemical content of the soil, the type of climate, and many other things can lead to corrosion. Microbiological corrosion, caused by microscopic organisms, can be common in some areas.

 

CO2 Corrosion

Sometimes called sweet corrosion, is common in the southern US and other areas of the world. Carbon dioxide can be found in gas, water, oil, and other fluids produced from a well. Oil that contains a high carbon dioxide content can be difficult to refine, and so special refineries have to be built to handle it. Most of these are located around the Gulf of Mexico. These refineries process most oil with high carbon dioxide content, as they are expensive to build.

Carbon dioxide consists of one carbon atom bonded to two oxygen atoms. When combined with water, carbon dioxide can form carbonic acid. This is a highly corrosive substance that can be dangerous to work with. Carbonic acid will also lead to corrosion, particularly of steel parts. The iron in the tubing, fittings, and other components reacts with the acid to form iron carbonate, which is not as strong as the steel. Components, particularly downhole components, can become pitted or cracked. Corrosion coupons are pieces of metal, ideally of the same type used in the construction of components, that can be inserted in lines. These can be taken out after a certain period of time and analyzed to determine how much they’ve corroded. Using this information, the corrosion damage in the rest of the system can be estimated. Caliper surveys can also be used to measure corrosion. A caliper, a piece of equipment with several metal ‘fingers’, is run along the inside of the tubing to look for pitting and cracks. A variety of chemicals, alloys, and coatings can be used to reduce carbon dioxide corrosion.

 

Hydrogen Sulfide Corrosion

In a little less than half of all wells, hydrogen sulfide is produced from a well along with oil, water, and gas. Generally, the amount of hydrogen sulfide will increase over the production life of the well. When this chemical combines with water, it forms sulfuric acid. This is a highly corrosive and dangerous substance. Corrosion caused by sulfuric acid is often called sour corrosion. This acid forms fairly easily, and can cause a great deal of corrosion below the water level in tanks.

Steps to prevent sour corrosion are similar to those taken to prevent sweet corrosion. Using chemicals, corrosion resistant fittings and components, and linings can reduce damage substantially. Sending chemicals down into the annulus can also be helpful in addressing corrosion downhole.

If the concentration of hydrogen sulfide is too high, it might be necessary to wear a gas mask when gauging and testing oil.

Corrosion

Figure 3. Breathing equipment is necessary when working at this location because of high amounts of hydrogen sulfide.

 

Oxygen Corrosion

Oxidation is the most common form of corrosion. Everyone has encountered it; the rust that you’ll see on metal railings or tools is the oxidation of iron. Oxidation can also happen most metals, including aluminum. Any sort of oxygen corrosion will weaken the metal, making it brittle. When sweet corrosion and oxygen corrosion combine, damage can be accelerated. Keeping oxygen from contacting steel or other metals components is a basic first step in preventing oxygen corrosion; painting metal components is a common way to prevent oxygen corrosion.

Other steps to prevent corrosion include maintaining a blanket of oil over the water, keeping oxygen from contacting it. A system that prevents the open atmosphere from meeting water produced in a well is called a closed system. Conversely, a system that is open to the air is called an open system.  Wells that operate with the casing valve open to the air risk an increase in corrosion. Open systems are sometimes chosen because rust is a common result; a small amount of rust can act as a barrier between metal and air, and help prevent other types of corrosion as well. Water flood operations can also add oxygen to the system, resulting in increased corrosion.

 

Electrochemical Corrosion

In general, there are two types of electrochemical corrosion; one is caused by the leak of an electrical current into the surrounding environment. The other, more common type is the result of a basic and naturally occurring battery cell.

Current in the environment may sometimes be intentional and used to power equipment. More often, it’s the result of an accident or natural force. For example, blowing wind can cause static electricity. Poorly grounded wiring can also lead to current passing through metal pipes.

The second type requires an acidic liquid of some sort, so it occurs downhole or in wet ground. Electrons flow from one metal to the other, from the anode to the cathode. Techniques to prevent this sort of corrosion are called cathodic protection, and usually involve altering electrical flow to protect metal.

 

Scale

Scale is caused by sediment suspended in fluid precipitating out and coating the surface of metal or rock. In the context of drilling, water usually carries minerals in solution as it flows toward the bottom of the well. Scale can actually be a problem in the rock leading up to the wellbore, and not just in the well and other equipment. Scale can actually plug the formation and the perforations in the well. It can also clog tubing and flow lines, and prevent tubing and other equipment from moving up and down the well. It can also collect and form a solid at the bottom of stock tanks. It also can act as a catalyst for electrochemical corrosion, increasing the damage it causes.

Scale can be stopped or at least slowed in the formation. Chemicals can be pumped down into the well to prevent the accumulation of scale. Adjusting the acidity of the well can also help to reduce scale buildup. Fracking methods can also help to open the porosity of the formation.

Corrosion

Figure 4. A wellhead with equipment to prevent scale. The tank for holding chemicals is shown in the background, and to the left of the wellhead is the pump and injection tee.

As with corrosion, there are coatings that can be used to prevent the buildup of scale. There are some varieties that can be applied like paint to equipment used with flowing wells. Pumps would end up damaging the coating, so instead chemicals are circulated down the well that end up coating the pump and other equipment.

An operation may end up having problems with scale for many reasons; sometimes a buildup is inevitable. When this happens, it may be necessary to take the system apart, clean the scale out, and then put everything back together. Chemicals can be used to scour scale out from inside equipment, and it can also be drilled out. This can involve quite a bit of work however, requiring a worker to enter the tank with all the necessary safety requirements.

You can also take some steps to reduce the impact of scale when building the wellhead and tank battery. Hard turns will generally in pipe are more likely to become clogged, while curves with a greater radius have fewer problems.

Is your appetite for oil & gas operating knowledge insatiable like ours? 😀 If so, check out this related article, How To Prevent Corrosion In Oil & Gas Production – it will surely pump you up!!!

The third stage of enhanced recovery from an oil and gas production well begins when after pressure maintenance and water flood operations have already been in place. The addition of a second force for enhancing oil production progresses a well from the second stage of recovery to the third and final stage. While it’s the last stage, it may often be wise to install both second and third stage recovery systems as early as is practical. At that point, the well is most likely still producing at high enough levels to pay for the equipment and can be used to extend the life of the well.

Third Stage Recovery

There can be a wide range of forces used for producing oil, but there are a few that are used commonly. Water and heat can be used together to create steam. Water and CO2 might be injected, or slugged, alternately into the well, as could water and polymer chemicals. Water generally serves as one of the two forces, as it’s easily available and well understood.

The term ‘tertiary recovery’ is an older term that’s not as popular as it once was. As mentioned above, techniques that were once considered part of tertiary recovery may be installed and sued at any point in the well’s life, so the distinction is not as meaningful as it once was.

 

Miscible Displacement

These methods involve injecting a fluid or solvent into the reservoir. Miscibility is the measure of two substances tendency to mix. Water and oil are generally immiscible, meaning they do not mix. Miscible displacement methods use a fluid or chemical solvent that will mix completely with the oil and help release it from the rock formation. A second force, generally water or gas, is injected after the solvent to force it into the formation and to sweep the solvent and oil together to the producing well.

A few of the different solvents, gases, and fluids used for miscible displacement include refined hydrocarbons and hydrocarbon gases, liquefied petroleum gases, CO2, and inert nitrogen gas. Inert gas has become increasingly popular.

 

CO2 Injection

CO2 injection is the most form of miscible displacement. Carbon dioxide is injected into the reservoir and followed up with a slug of water. The CO2 is swept through the formation, and recovered from production wells. The CO2 can be separated from other gases produced from a well and reused. The CO2 will work as a solution gas drive in the reservoir, as it is soluble in both water and oil and will therefore cause the fluids to swell. This increases pressure which results in an increase in production. This is more efficient than natural gas or LPG gas.

While more efficient, using CO2 for miscible displacement does have a few drawbacks. When CO2 and water are used together, the mixture will result in carbonic acid, which is extremely corrosive. When injecting CO2, the wellhead will usually need to be prepared by installing stainless steel bolts, seals, and other fittings. It may also be difficult for CO2 to mix with heavier oil elements, which can reduce the technique’s efficiency.

 

Inert Gas Injection

Injecting inert nitrogen gas is similar to injecting dry natural gas. Inert gas may need a higher pressure than natural gas to best mix with emulsion, but it can be swept through a formation more than once.

 

Thermal Methods

Thermal methods includes different techniques for using heat to increase production.

 

Steam Stimulation

This term refers to injecting steam down a well, and then recovering it directly from the same well. The same general process can also be referred to as huff and puff, steam injection, or steam soak. The steam is injected over a number of days, generally between a week and a month. The well is shut in for a few days, which allows the steam to heat the reservoir. The heat thins the oil, which eases flow of the oil through the reservoir.

After the well is returned to production, the oil is allowed to flow until the rate slows to the point that the process needs to be repeated. At this point, the operation will most likely be changed to steam injection.

 

Hot Water Injection

Steam and hot water flood work essentially the same way as water flood or gas injection; the steam is injected and then sweeps to a second well where it is produced with natural gas and emulsion. As heat spreads through the formation, the oil expands which leads to an increase in production.

Steam and hot water injection make up about ⅕ of enhanced recovery operations. Wells for flooding steam require about 5 acres of land, and the technique can be used with reservoirs from 10 ft to 5,000 ft deep. Hot water can also be used, but is less efficient.

 

In Situ Combustion

In situ combustion is the practice of lighting a fire within a formation, burning the oil and using the heat generated to increase production. Injecting compressed air drives the fire across the reservoir. As the fire moves, the oil’s viscosity drops which allows the oil to expand. That can lead to an increase in production.

In situ combustion can take 2 forms, either forward or reverse. With forward combustion, the fire is ignited near the air injection well and then driven across the formation to the production wells. With reverse combustion, the fire is first driven away from the initial air injection well to producing wells. After a certain point, the direction is reversed and what was initially the injection well becomes a production well.

In situ combustion may not be economical in every case. Variations on this basic process, called wet and partially wet combustion, are being developed to address these issues.

 

Chemical Methods

Methods of tertiary recovery that use chemicals are used in only a few cases. The chemicals are often too expensive too be economical, and the other equipment can also be quite expensive. Using the chemicals also comes with some risk.

 

Surfactant-Polymer Injection

Surfactants are chemicals that breaks down the surface tension between two substances. In this case, the chemicals are used to break down the interfacial tension between water and oil. Surfactants may also be called micro-emulsions, soluble oil, or micellar solution. The surfactants are followed up by a polymer injection, which provides mobility control.

This particular method of enhanced recovery is not as efficient as others, as reservoir rock can absorb the surfactants, and it can also become more difficult to mobilize oil.

 

Polymer Flooding

Polymers have large molecules which can increase the viscosity of water. This can make water flooding operations more efficient. Polymers used in this technique are generally either polyacrylamides or polysaccharides.  Polyacrylamides are used in concentrations from 50 ppm to 1000 ppm. This polymer decreases the permeability of reservoir rock, which can decrease the mobility of injected fluid. Polysaccharides, on the other hand, do little to reduce permeability of rock but increase the viscosity of fluids. Using polymers can increase production over the long term.

 

Alkaline Flooding

Alkaline flooding raises the alkalinity of the water injected into the reservoir, which can improve production. Alkalinity is measured by pH. A pH of 7 is considered neutral. A substance with a lower pH is acidic, while a pH of 7 or higher is considered an alkaline, also called a base. A fluid with a pH of 12-13 is the most you’ll want to use.

The cost of alkaline flooding is fairly low compared to some of the other techniques. The increase in production is not a large as some other tertiary recovery methods, but the cost is low enough that profits are higher.

Is your appetite for oil & gas operating knowledge insatiable like ours? 😀 If so, check out these related articles: Basic Stages Of Recovery In Oil & Gas ProductionFirst Stage Recovery In Oil & Gas Production and, Second Stage Recovery Methods For Oil & Gas Production  – they’ll be sure to pump you up!!!

There are three general stages of recovering oil and gas from a well. The first begins as soon as the well is completed, and can include wells that flow naturally as well as those that use some form of artificial lift. The second stage recovery begins when water or gas is injected into the formation to improve production. It’s in this stage that enhanced recovery operations really begin, with water flood and gas maintenance becoming a big part of driving production.

Second Stage Recovery

When using the term ‘flood’ in this context usually means that a fluid or gas is injected in one well so it can push oil toward another well. The driving gas or fluid is recovered at the production well. Gas maintenance refers to the practice of re-injecting gas into the formation to keep the reservoir’s pressure high.

Water flood and gas maintenance practices can be complex and difficult to control, but ultimately are worth the effort. It’s possible that efficient use of these techniques can double the production volume of a well over its total production life.

 

Gas Injection

Gas injection, also commonly referred to as pressure maintenance, is used with reservoirs that are at least partly gas driven. The gas that is produced from the well is dried, compressed, and injected back into the reservoir to continue to drive oil flow.

Gas separation is a standard part of the tank battery’s function. When using gas injection, the gas should be run through a gas plant or scrubber, which will remove all the distillate and other hydrocarbons. At this point, the gas can be compressed prior to being injected.

A gas injection well is setup along the same lines as a water injection well, which is described in more detail below. The gas injection setup will also include a safety valve high in the tubing string, near the surface. The valve will protect the well if the surface injection line breaks, which could lead to a blow out.

Second Stage Recovery

Figure 1. An example of a gas injection well.

Gas injection is effective but it also faces some problems. The most obvious is that natural gas is very light, and so it tends to rise in the reservoir. In many cases, that may mean that it rises above the level of fluid in the reservoir, and therefore doing only a little to drive production.

The second problem is that oil is much heavier than gas. While the pressure the gas exerts can push oil out of the well, it’s also possible for the gas to push through the oil, breaking into small streams of gas that does a poor job of driving it to the well. Gas also can have a hard time combining with the oil in the formation, which reduces the effectiveness of gas injection; in some cases, it can make the oil heavier and less likely to flow to the well.

 

Water Flood

Water Flood is one of the earliest methods of enhanced recovery, and one that has become very widespread. In addition to providing an additional driving force for oil production, it also provides an easy means of disposing of water produced from the well. Water flood has since been combined with other methods, such as slugging, and water injection will continue on most wells into the third phase of recovery.

Second Stage Recovery

Figure 2. An example of a well used for injecting water back into the reservoir.

There are a few preparations that need to be made before a well can be used for water injection and a water flood operation. The casing should be tested for leaks, and packer fluid should be used to isolate the annulus space. This process will often have to be approved and observed by a regulating agency. Pressure in the casing and tubing should be monitored to check for leaks.

Second Stage Recovery

Figure 3. An example of a wing valve, commonly used in water injection operations. (courtesy of Baker SPD, a Baker Oil Tools company)

The wellhead should also be properly setup for water injection. A full master gate opening will typically need to be installed on the tubing. In Figure 3, you can see an example of a wing assembly. This includes a screen to catch solids, a meter for measuring the water volume, a valve and gauge to regulate pressure, and a check valve.

In order for water flood procedures to be as efficient as possible, the water should move in a solid wall through the formation. However, this rarely, if ever, happens perfectly. The water’s own weight will often pull the leading edge down, missing large amounts of oil that are therefore not pushed toward the producing well. Water may also not move through the formation in an unbroken wall, and instead break into smaller streams.

In some cases, you’ll want to collect the separated water from several wells or tank batteries so that it can all be injected in one well. Wells used for this purpose will often require some specialized equipment, including larger than normal holding tanks, water filters, a pump capable of handling large volumes, choke valves, and more. Some systems use a lower pressure and are simpler to operate.

Oil may sometimes accumulate in lines or tanks used for water injection. When this happens, the solution is fairly straightforward; simply add a skimmer tank ahead of the injector. This is a simplified wash tank, where oil rises and flows out through a higher opening in the tank, while water is drawn from near the bottom to be injected.

Second Stage Recovery

Figure 4. An example of a low pressure water injection setup.

Water injection usually will happen on a set schedule, and if properly setup doesn’t need much watching. That makes it a prime candidate for automation, which can simplify the water injection system dramatically. If the system is small and there’s little chance of it overflowing, you may not even need a backup system.

Second Stage Recovery

Figure 5. An example of an automated water disposal system. The pictured setup includes backup controls as a safety measure.

Is your appetite for oil & gas operating knowledge insatiable like ours? 😀 If so, check out these related articles: Basic Stages Of Recovery In Oil & Gas Production, First Stage Recovery In Oil & Gas Production and, Tertiary Stage Recovery In Oil & Gas Production  – they’ll be sure to pump you up!!!

Wells have three basic stages of production, the first or primary stage, the secondary stage, and the tertiary stage. Each stage is distinguished by the type and variety of recovery methods used. The primary recovery starts as soon as a well is completed and begins to flow, and continues until water flood or gas injections begin.

First Stage Recovery

There are a wide range of methods used to improve production in the first stage recovery. These can include any type of artificial lift, efforts to manage pressure down the borehole, and changes at the well, among others.

 

Altering And Maintaining The Formation

Primary stage recovery methods can include some techniques for monitoring, maintaining, and altering the reservoir formation to improve the flow of oil.

 

Allowables

These are limits on the amounts that can be produced from a well. The limits are usually placed on gas production, with the goal of maintaining pressure in the reservoir the well draws from. Producing too much gas can lead to lower pressure levels in the formation. If the pressure in the formation drops too low, it will no longer be possible to pump oil from the well.

Many wells, and therefore many companies, will draw from the same reservoir. While it’s in the best interest of all parties to maintain reservoir pressure, some operators may still choose to produce large amounts of gas. The allowable limits set by a regulating agency are intended to prevent that sort of over-production.

 

Fracking

The porosity of the formation is one factor that can limit the rate of oil production. A tighter porosity means that it’s more difficult for oil to flow to the wellbore. The porosity of a formation can be improved by by using fracturing, or fracing, techniques.

There are a range of different fracking methods. Sand fracking uses sand to force a formation open. Openings can be widened using acid and chemical fracking. Fracking is a popular technique in areas with low porosity. Heat and pressure are becoming more popular, as is other new technology like adding tracers to track damage to the reservoir.

 

Stabilizing Formations

This technique uses various methods, including chemicals, to keep sand and scale stable in the formation. This props the formation open while allowing oil to flow freely, which can prevent long term problems and allows more oil to be produced. The orientation and location of the casing and tubing perforations should be considered when stabilizing a reservoir formation.

 

Managing Pressure

It’s important to manage the pressure in the reservoir, but there are also a few ways to manage pressure at the wellhead and tank battery that can help improve production.

 

Beam Gas Compressors (compressing gas to reduce backpressure)

Oil will stop flowing from a well once the pressure of the fluid column, from the bottom of the well to the tank battery, equals the pressure from the oil in the formation. You could simply plug the well and move on at that point, but there are a number of other options to get the well flowing once more. One method is to use a beam gas compressor.

First Stage Recovery

Figure 1. An example of a beam gas compressor. (courtesy of Permian Production Equipment, Inc. )

The compressor draws gas from the well casing, compresses it, and then injects it into the flow line after the check valve. The gas reduces the pressure in the fluid column, allowing the oil to flow from the well once more.

First Stage Recovery

Figure 2. A diagram of how a beam gas compressor works. (courtesy of Permian Production Equipment, Inc.)

The compressor can be powered by the pumping unit. Some stripper or lower production wells have increased production many times over, which often can pay the cost of the compressor and other equipment quite quickly.

 

Venting Casing Gas at the Wellhead

Natural gas can be recovered from the well and used for a range of purposes on the lease, or collected for sale. However, when only small amounts of gas are being produced it’s often not economical to recover it.

While the gas may not be worth recovering, it’s still exerting some pressure down the well. By opening the casing so that the gas is vented, that pressure is relieved. At that point, the pressure from the formation may be great enough for the well to begin flowing again.

Opening the casing to the atmosphere will allow air into the casing, which leads to an increased risk of oxygen corrosion. To prevent that, a ball and seat standing valve can be put vertically in the casing opening. That prevents air from entering the casing, but allows gas to escape to the atmosphere. You can set up a hose from the tubing bleeder valve to a swage in the casing valve. That allows you to check the performance of the well. When you send the fluid back into the casing, it’s coated with oil as the fluid falls which helps prevent the oxygen corrosion.

 

Changes In The Well

There are a few changes that can be made to the well or wellhead that can be used to increase production in the primary phase of recovery.

 

Automated Control Of The Well

Automation and computerized control have become very popular for their increased efficiency. Using some specialized equipment, such as an echometer and dynamometer, the behavior of the well and reservoir can be monitored. A computer can use this information to produce from the well in the most effective way while simultaneously lowering costs. These systems can also provide analysis which can help identify problems before they become serious.

 

Moving Casing Perforations

The level of the casing perforations can have a big effect on production levels. The height of the perforations determine the level at which fluid is drawn into the well. The shape of the formation and the forces driving the well’s production. With reservoirs that are water driven, perforations that are too low will produce mostly water. Perforations that are set too high may lead to overproduction of gas, damaging the formation’s long term production potential.

 

Changing Lift Systems

Several different lift systems will be used throughout the course of a well’s production life, each selected to most efficiently produce from the reservoir. A flowing well may only use gas lift, or no artificial lift at all. As pressure drops and the well stops naturally flowing, electrical submersible lift or mechanical lift may follow.

Each lift system should be chosen to match the behavior of the well. An understanding of the reservoir and the forces that drives fluid to the well can help select the right system for each circumstance. No understanding is perfect, however, so it can sometimes be challenging to select the right system. It’s possible that wells are plugged and production ended simply because the correct method of production wasn’t tried; it’s possible for anyone, even experienced operators, to make this mistake.

 

Horizontal Drilling

Horizontal drilling is one of the most important technological advancements of the last few years. Along with a few other associated new techniques and technological advancements, it has revolutionized drilling and oil pumping. After a well has been sunk down to the reservoir, the drill can be turned 90 degrees so that the hole is drilled horizontally through the pay zone. This allows a much larger amount of oil to collect at the wellbore, which can dramatically increase production. Older wells that have been worked over using these new methods now sometimes produce more than when they were first completed. An experienced and knowledgeable specialist and accurate analysis of the lease records can improve production even further.

New methods for orienting and tracking a mud motor, and the development of a drill bit-mud motor assembly with a small bend in the middle. Together, these improvements allow a hole to be drilled down with the drill assembly having only a slight wobble. The mud motor can turn the drill bit while the tubing string is still, allowing the direction that’s being drilled to be changed with control of the assembly’s orientation. The techniques and technology continues to be improved.

 

Perforation Orientation

The location and height of the casing perforations can have a big impact on what you produce from the well, and how much. However, the relative height of the casing and tubing perforations can also end up affecting production.

 

Tubing perforations might be above, below, or at the same height as the casing perforations. There are a number of reasons for each choice, and each operation will most likely have its own reasoning. Depending on this orientation, a fluid or gas blanket can be maintained on the formation, exerting a small amount of pressure. It can also have an impact on paraffin accumulation, and how that affects production.

 

Innovative Methods

Technology in the last few years has advanced at an ever increasing rate. Horizontal drilling, as well as advancements in computer automation, has led to large improvements in production and efficiency for a number of operations.

As our understanding continues to expand, and as technology continues to advance, new methods of improving oil production are likely to become available. An understanding of the science underlying oil production, as well as the latest methods and technology, is often essential for maximizing a well’s production. This is true even with lower production or marginal wells, as small improvements can have a big effect on the bottom-line. With some developments, such as horizontal drilling, a marginal well might be brought back to higher level of production.

When considering new techniques, it’s important to keep a few questions in mind. The answers can be helpful in deciding whether it’s something that might be helpful for your own operation. The type of reservoir and its drive, the flow from the well, and several other factors should be kept in mind. It’s also a good idea to consider the equipment and production methods already in place.

Is your appetite for oil & gas operating knowledge insatiable like ours? 😀 If so, check out these related articles: Basic Stages Of Recovery In Oil & Gas ProductionSecond Stage Recovery Methods For Oil & Gas Production and, Tertiary Stage Recovery In Oil & Gas Production  – they’ll be sure to pump you up!!!

In any oil and gas production operation, the goal is to recover as much oil as possible while keeping operating costs as low as possible. As technology has advanced and the the demand for oil has increased, new techniques have been developed to increase the amount of oil that can be produced from one reservoir.

Basic Stages

In the early years of the US oil industry, the biggest demand was for kerosene that would be burned in lamps. There was little understanding of how reservoir drives worked and how best to recover oil from a reservoir. As a result, wells were produced until the natural pressure in the formation dropped enough that oil wouldn’t flow on its own. At that point the well was considered played out, leaving more than 80% of the oil still in the reservoir.

Time has improved our understanding of geology and the forces that drive an oil reservoir. Using modern methods for oil and gas production, more than half of the oil in a formation may be recovered.

 

Stages Of Recovery

There are three basic stages of recovery operations. A well will move through each stage, first as it is first completed, then as the natural formation pressure falls and the oil has to be helped along through artificial means. These techniques are called enhanced recovery techniques, which is a broad term that covers all of those methods of artificial recovery. Equipment will most likely be replaced and improved as new techniques are used.

Techniques and technology continue to evolve as more is learned and new methods developed. However, it’s likely that an oilfield in the future will most likely look very similar to one today. Newer technology is often expensive and prone to problems, and older and more reliable methods are often a better option for smaller and marginal wells. The basics of producing and treating oil will most likely still depend on gravity and the different densities of water and oil. While it’s important to keep up with new developments, the skills and knowledge developed working any field is going to be useful.

 

Primary Recovery

When a well is completed and begins to flow, it has entered the first, or primary, phase of recovery. It also includes using basic method of artificial lift, such as different types of mechanical, hydraulic, and electrical lift. Basic methods of treating and stimulating well production are also considered part of the primary recovery stage.

 

Secondary Recovery

When an operation begins to use water flood or gas injection to maintain the reservoir’s pressure, the well has entered the secondary recovery stage. Flood techniques refer to the practice of injecting a fluid or gas at one well, pushing oil toward a second well where the fluid or gas is recovered. Water flood is one of the most common methods used. Flooding operations can be complex, as the volumes injected, injection patterns, fluid channeling, and many other factors have to be accounted for.

 

Tertiary Recovery

Third stage recovery is considered to have begun when two or more forces are used to aid in the production of oil from a well. This can include combinations such as CO2 and natural gas, water and and chemical flooding, and the use of heat and water to produce steam. Slugging is commonly used in third stage recovery operations. With that method, two different fluids are injected alternately. This is common when one of the fluids are expensive chemicals used to improve production; water is injected after the chemicals to improve their effectiveness.

Is your appetite for oil & gas operating knowledge insatiable like ours? 😀 If so, check out these related articles: First Stage Recovery In Oil & Gas Production, Second Stage Recovery Methods For Oil & Gas Production and, Tertiary Stage Recovery In Oil & Gas Production  – they’ll be sure to pump you up!!!

Pressure gauges are an essential, if delicate, measuring tool for oil and gas production. Flow lines, separators, and even atmospheric vessels like stock tanks are all under some amount of pressure. Gauges allow you to monitor pressure levels throughout the operation, from the wellhead to the tank battery. Monitoring pressure downhole is also important for extending the production life of the well for as long as possible. If you plan on working in oil and gas production, it’s a good idea to be comfortable using, maintaining, and calibrating pressure gauges.

Pressure Gauges

 

Pressure Gauge Basics

Pressure gauges are used all over a pumping lease, with a range of sizes, costs, and accuracy levels. Some gauges can take more abuse, but generally are less accurate. Others are more precise, but have to be treated more carefully.

Pressure Gauges

Figure 1. A few different example gauges. (courtesy of Helicoid Instruments)

Less expensive gauges can be used for tasks where an approximation is enough, such as monitoring the pressure in a flow line. It’s more important to know the exact pressure at the wellhead and downhole, however, and so a more accurate gauge should be chosen for those uses. An appropriate gauge should be chosen for each task. The life of a gauge that’s measuring pressure down the flow from a triplex pump, or in another situation where pressure fluctuates rapidly, can be extended by using an adjustable vibration dampener to lessen the shock.

One type of gauge uses a spring to measure pressure and move the hand on the gauge’s face. A second, more common type uses something called a Bourdon tube. That’s a thin, flat tube that is curved into a c-shape. As pressure builds in the Bourdon tube, it attempts to straighten from its curved shape. This moves the hand on the gauge’s face, indicating the pressure.

Pressure Gauges

Figure 2. The interior of a Bourdon tube gauge. (courtesy of Helicoid Instruments)

 

Types Of Gauges

In some contexts, it is wise to use a gauge with some built in safety measures, such as a stronger glass face. Some will have a rubber plug in the back of the gauge that can blow out if the pressure grows too great. Otherwise, safety glasses should be worn whenever opening a gauge or when reading a valve on a high pressure line.

Most gauges are gas filled, but some may be filled with liquid instead. Gas filled gauges may become scratched or otherwise difficult to read over time. Liquid filled gauges will remain readable much longer, but may have a bigger problem with corrosion.

 

Well Testing Gauges and Calibrating

Gauges used for testing well pressure work the same as any other gauge, they’re just generally more accurate and can be calibrated.

Pressure Gauges

Figure 3. An example of a gauge and dead weight tester.

A test gauge will have an adjustment screw with which any error from the indicating hand can be corrected. Using a dead weight tester, the gauge can be checked for accuracy. Well testing gauges are generally fairly expensive and should be treated gently. A cam and roller geared gauge is a good option, as they are long lasting and accurate. It’s also usually best to select gauges that have the hand pointing directly up when indicating the middle of the pressure range. Gauges of this sort are more reliable. Occasionally it may be necessary to have a gauge calibrated at a laboratory, or by the factory, in situations when precision is important.

Calibrating a test gauge requires a dead weight tester. To calibrate a gauge using the dead weight tester in Figure 3, the black gauge in the back left (hidden by part of the tester) should be closed. The black valve in the front left should then be opened and the handle cranked up. Hydraulic fluid will be pulled under the crank’s plunger from the center reservoir. Now the two valves’ states are reversed, with the front valve being closed and the back opened. Cranking the handle downward puts pressure on the fluid so that it is pushed to the center pedestal stem. You can fit the gauge onto the tester, and then place the test amount of weight on the pedestal in the center. The left hand screw raises the weights to the correct height, and you can then check the gauge to see if it’s reading accurately. The gauge’s hand can be adjusted with a screw driver.

 

Measuring Pressure Without A Gauge

A dead weight tester can also be used to measure pressure directly when you need a very precise reading. Using a small diameter, high pressure hose, the tester can be connected directly to the wellhead. The tester can then be used to measure pressure.

Is your appetite for oil & gas operating knowledge insatiable like ours? 😀 If so, check out these related articles: How To Test Wells In Oil & Gas ProductionCommon Tests For Oil & Gas Production and, Special Tests for Flowing Wells in Oil and Gas Production  – they’ll be sure to pump you up!!!

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