All posts by Greg Archbald

The Basics of Setting Up an Oil & Gas Production Tank Battery

The tank battery is the arrangement of storage and processing tanks, flow lines, and other equipment necessary to operate a well. Some tank batteries are connected to just one well, while others receive and process fluids from several different wells. When a single tank battery receives from a few different wells, those wells will usually all be close together which means they are all producing similar amounts and types of fluids. The different vessels and equipment that make up the tank battery will be chosen to store and treat the products from those type of wells. For example, wells in one area may be using hydraulic lift while wells in another use gas lift to up production. A tank battery will need to be equipped to handle the different requirements in each case.

As the equipment chosen for a tank battery depends largely on what is being produced, it’s important to keep a number of things in mind when designing a tank battery for a particular operation. Obviously, it’s important to understand what each vessel does and how it does it. Understanding the interior layout of a vessel, as well as its place in the overall tank battery, is also vital. Most of all, you’ll need to be able to spot and solve problems you encounter, as a tank battery will most likely evolve over the course of its use.

 

Assembling a Tank Battery

The composition of a tank battery will change and evolve over the life of the well. As the nature of production changes, different equipment will need to be brought in to meet different needs. Older equipment will be removed to make room. For example, a well may have sufficient natural pressure at first to produce a satisfactory flow. That pressure will fall, however, and eventually you may want to install a gas lift system, which requires specific, specialized equipment. Later, you may move to hydraulic lift, and have to add all of the equipment necessary for that. By the end of a well’s life, several different methods of production will probably have been used.

There are a few basic things that most tank batteries will have. As each tank battery has to be tailored to the needs of the well and operation, it’s important to understand how each of the basic components works.

Tank Battery

Figure 1. A picture of a tank battery that includes water tanks (painted black), a wash tank, and two stock tanks for oil (painted gray).

 

Essential Vessels

Vessel is essentially a fancy name for the tanks and similar equipment that receive the produced fluid. These are mostly used either to simply store fluid until it can be treated or sold, or to separate oil from water and gas.

A stock tank is used for storing oil prior to treating or selling it. There’s also usually a tank for holding produced, separated water, as amounts have to be measured and recorded. These tanks are usually not under pressure. Tanks can be either round or rectangular.

Rectangular tanks usually don’t have a roof. This makes it easy to access the stored fluid for measuring and testing. A ladder may come with the tank. However, as with all things when lease pumping, a bit of ingenuity may be required; you may have to put together a simple one to access the fluid. A hoop at the top of the ladder allows you to use both hands to test and measure fluid. A safety belt is another option.

You’ll also need a separator, both a regular and a test one. This is usually the produced fluid’s first stop after leaving the well. Most often these are two phase separator, meaning the vessel will only separate gas from oil and water. They can sometimes be three phase separators, meaning that it also separates the oil and water. Unlike stock tanks, separators are usually under pressure.

Several vessels actually are involved in various steps of separating oil from other produced fluids and impurities. The heater-treater is another example, which is a three phase separator that uses heat. Heater-treaters can be either pressurized or at atmospheric pressure. A wash tank, sometimes known as a gun barrel, also separates oil from water and gas, making it another three phase separator.

Just about every tank battery will need some sort of circulation pump. It can be one of a bunch of different kinds, and is used to move fluids from one vessel in the tank battery to another.

Most tank batteries will require some sort of dike or firewall. These are required around vessels that are not pressurized, with fluids that are stored at atmospheric pressure. The firewall contains fluids in the case of leaks or other emergencies where oil may end up outside of a stock tank or other vessel. There’s some specific requirements regarding the size of the dike that you should check out. Usually, the dike has to be able to contain 1 ½ times as much fluid as can be stored in the tank.

 

Flow Lines

Lines can be simply be upset steel pipe like what’s used downhole. It can also be synthetic, like plastic or fiberglass. They can be joined however steel seems best for your operation. Steel lines can be threaded pipe and use appropriate fittings, or might use collars or grooved clamps.

Synthetic lines are used frequently in situations where steel would corrode too quickly. Polyethylene lines are also popular for their low cost and ease of use. However, polyethylene lines are best used with low pressure wells.

Tank Battery

Figure 2. An example header.

Head lines flow from the wellhead to the tank battery. When a tank battery receives fluid from several wells, you’ll need to put together a header. This is an assembly of lines and valves that allows you to control the flow from each well to the tank battery, as well as to other equipment such as a meter.

In the example pictured, each well has it’s own set of flow lines and valves. Flow enters from lines on the bottom right. It then heads through a valve and then a check valve. Oil is then sent to different parts of the tank battery, either the production or test separator. All valves are quarter round valves, so it’s easy to see at a glance which valves are open, closed, and which wells have been shut in. Valves and lines are also clearly labeled. This sort of clarity is important to the efficient running of a lease.

Tank Battery

Figure 3. A drilling rig where a drill stem test is being performed. Gas is being flared off on the left.

Initial Production

The very first oil drawn from a well will almost always be through the drill stem, and used for testing purposes. Rather than having a full tank battery for such a small flow, a smaller test tank is usually used. If the test shows that the well may produce a profit, a large bore pipe will be set in place to serve as casing and then perforated. At the same time, the tank battery should be assembled so that production can start as soon as the well is prepared.

Some wells have sufficient bottom pressure to that flow will start as soon as the correct valve is opened. Other wells will require some further work. Many wells will have a column of water on the surface of the oil. The water will need to be swabbed out to so that the pressure in the tubing column is less that the bottomhole pressure. A column of oil can also be swabbed out to start flow.

The first flow will often be measure by the drilling company, but it will ultimately become the responsibility of the operator to keep track of what’s produced from the well.

Tank Battery

Figure 4. The Natural Product Curve.

When a new well is opened for production, the pressure throughout the reservoir will be more or less equal. As fluid is drawn from the reservoir, the pressure around the wellbore will naturally drop. The oil in the reservoir will filter through the formation to the wellbore. However, oil will most likely be drawn much more quickly than it can flow through the formation, which leads to the drop in pressure. Over time, the production will fall according to the natural production curve. If no lift system is used, the production rate will follow this curve over time. Many different factors will determine the actual numbers.

 

What Are You Pumping?

Obviously, you’re most interested in the oil and natural gas that is produced from the well. However, you’ll be handling a few other products, some of which can also be sold to petroleum companies. Asphalt is used in road construction. Natural gas can be used in several industries. Paraffin and petroleum are also valuable byproducts.

BS&W, or basic sediment and water, is going to be the biggest byproduct by volume. Water can be used for some pumping operations, but there’s a number of byproducts which can be difficult to deal with, if not dangerous. Sulfur is often found in wells, which, when combined with produced water, can lead to the formation of acids that cause corrosion. Hydrogen sulfide can be particularly dangerous, and proper safety procedures should always be followed. For lease pumpers, specifically, those procedures should never be ignored, as you’ll often be working the lease solo.

Tank Battery

Figure 5. An example tank chart.

 

Recording

You’ll be required to keep precise records about the well’s production, breaking down the volumes of natural gas and oil, as well as water. These records are required by a variety of regulations, and are reviewed by regulatory agencies. For any given well, the very first production will be recorded, as will all production up to the end of the well’s production lift. A yearly, weekly, and daily report is usually required.

These records are actually useful for the lease pumper as well, as they can be a guide to the amount and type of equipment needed to fully exploit a well. That decision will also be affected by many other factors, such as the volume of oil coming from the well, the lease size, and financial considerations. Fluid volumes should be measured frequently throughout the day when the well first is flowing.

Record keeping usually begins at the wellhead, and a basic meter is usually installed there. More detailed records can be taken from the various tanks that make up the tank battery. The use of a gauge line paste will help in determining the ratio of oil to water. While gas is usually vented to the air or lit to form a flare, the amount is still needed to be measured and recorded.

Using Side Pocket Mandrels in Oil & Gas Production

When using a gas lift system, mandrels are an integral part of the pumping system. Valves are installed in these pieces of hardware, which are an important part of regulating the flow of gas. Conventional mandrels are straightforward to use, but they have a significant downside. When one mandrel fails or needs maintenance, the entire tubing string has to be pulled.

Side pocket mandrels are an alternative that addresses this issue. Rather than pulling the entire tube string, side pocket mandrels can be pulled separately from the tubing string using a wireline machine. You won’t need a pulling unit and a whole crew, and wireline machines are useful to have around for a lot of reasons. Side pocket mandrels are particularly good choices for offshore rigs, having lesser requirements for crew and equipment.

Side Pocket Mandrels

Figure 1. A few different types of side pocket mandrels. (courtesy of CAMCO Products and Services Company)

Wireline Machines and Safety

Wireline machines can do more than simply pull side pocket mandrels. The tools used with a wireline machine can be used to do a variety of things, from removing sand to cleaning up scale. Paraffin can precipitate, for example, blocking tubing and slowing the flow of production oil. A wireline can cut through the paraffin and reduce the buildup.

Other types of maintenance are also possible with a wireline machine. Safety valves and other safety equipment could also be serviced and maintained. A wireline machine is useful for many reasons on an offshore well. One of the most important is that it allows the running of a second string of tubing into the well, in case of an emergency.

While it’s possible to add some safety equipment using a wireline machine, the machine itself can be dangerous. Fast moving wire cables are dangerous, and you should never approach or attempt to handle the wire while the machine is on.

Continuously Producing

Gas lift usually works best when the well is going to be continuously flowing. This is because the unloading sequence that is required to get a gas lift system flowing is complex and can be time consuming. For smaller wells, where the unloading sequence is easier to manage, running the well only intermittently could be prudent.

Side Pocket Mandrels

Figure 2. An example chart showing production from a gas lift system producing continuously. (courtesy of McMurry-Macco)

Side Pocket Mandrels

Figure 3. An example chart from a well producing intermittently using gas lift. (courtesy of McMurry-Macco)

Gas Lift Using The Annular Space

For most operations, the gas is injected through the annular space so that oil is produced up through the tubing. That’s the optimal arrangement for most wells, from those only producing a few dozen barrels a day to operations producing tens of thousands of barrels.

For high production wells, the standard system is actually reversed, with the gas being injected through the tubing and fluid produced through the casing. In that case, no packing is necessary in the casing, as it would be with the standard system. This is more common with wells producing more than 20,000 barrels daily. This is a particularly efficient in operations dependent on waterflood, as the amount of water pumped to the surface will tend to increase over time.

Mandrels and Gas Lift Valves in Oil & Gas Production

A gas lift system normally requires valves in the production tubing down the well.  These valves open in sequence, injecting the gas that forces fluid in the tubing to the surface. The hardware that connects the valve to the tubing is called a mandrel. There’s two general categories of mandrels, and whichever you choose can have an impact on how your well operates and is maintained. The first variety of mandrel is the conventional mandrel.

 

Conventional Gas Lifts and Mandrels

Valves are attached to the outside of the mandrels, which are then inserted into the tubing string at regular intervals. The entire assembly of tubing, mandrel, and the attached valves are all run into the well together. That means that when a valve needs maintenance or to be replaced, the entire thing needs to be pulled, which requires a crew of workers.

Another component to be aware of with a conventional gas lift system is the packer above the tubing perforations, which seals the annular space. That space is closed at the bottom as well, so that gas that is fed into that area from the compressor on the surface will activate the system.

Mandrel Gas Lift Valves

Figure 1. Four different conventional mandrels. (courtesy of Camco Products and Services Company)

 

Installing Mandrel and Valves

The valves will need to be installed at a specific, regular interval along the tubing. It’s best to measure the intervals and assemble the mandrel and valve before transporting the tubing to the well. The first lengths of tubing to be lowered down are all loaded together and marked with a 1. The second group is marked 2 and also loaded together, and so forth. Each mandrel is similarly assembled and marked for the order it’s going to be installed. When the tubing reaches the well location, it can be assembled with the mandrels in order.

When the tubing has to be pulled for servicing, the same ordering and numbering can be used. It’s vital that each valve be used only in its correct place in sequence, as otherwise the lifting system will not work correctly.

Mandrel Gas Lift Valves

Figure 2. A few different gas lift valves. (courtesy of Camco)

The Basics of the Gas Lift Valve

A valve will automatically open under a specific pressure, the opening operated by a bellows that is gas operated or occasionally through a spring loaded mechanism. The gas lift valve is divided into several different chambers.

The top most chamber is filled with a pressurized neutral gas. It has a fill valve that’s similar to one you’d find on a tire. The fill valve is set to a specific pressure and then it’s sealed up.

The second chamber is a bellows, one end of which is round. The bellows is forced up against its seat by the internal pressure.

The lower chamber of the valve is exposed to the annular pressure at the bottom of the well. The difference in pressure in the annular space opens the valve so that the gas is injected into the fluid.

Gas enters the tubing from the uppermost valve first. That valve then closes, and the one below it opens. This sequence continues until the entire column has been injected with gas and the fluid begins to flow. As long as gas continues to enter the tubing, fluid will continue to flow.

The Basics of Gas Lift Pumping in Oil & Gas Production

Gas Lift

Figure 1. A basic gas lift system. (courtesy of McMurry-Macco Lift Systems)

The production of any well is going to eventually drop. Even with a well that at first naturally flows rather than requiring pumping, the volume of oil produced will drop at some point. Production may drop to the point that the number of barrels produced each day falls a significant amount.

One of the methods you can use to bring production back up is gas lift, which involves pumping gas into the tube line below the surface of the liquid in the well. The gas forces the fluid through the tubing and to the surface. It’s a method that’s used commonly, particularly in wells that have lower production volumes, as gas lift can add a few barrels a day to production and still be cost effective. It’s also used offshore commonly, where space is at a premium. Gas lifts don’t take up much room, and it’s possible to use it with a few wells drilled close together. Additionally, no gas is lost in the pumping process.

Gas lift systems are also commonly used for a number of other situations. As mentioned above, it’s a good choice when a well needs a little additional force to produce satisfactorily. It can also be used with wells that have a head of water; the gas lift clears the water, allowing the well to flow as it had previously. In the same vein, it can be used to pump water for use in waterflood operations. Gas lifts are useful in a number of different contexts, and can also be used for injecting chemicals and other additives.

 

Gas Lift Basics

Gas lift uses gas pressure to, in effect, make the fluid weigh less. This reduces the pressure required to push fluid out of the well system to the point that bottomhole pressure is enough. Gas lift can be used to coax a natural flow, or increase an already existing flow. As long as the bottomhole pressure combined with the gas lift is enough to push fluid to the surface, production will continue.

When using gas lift, there will be a number of valves on the tubing lowered below the fluid level. These valves open automatically at certain predetermined gas pressures, which happens as part of the sequence for unloading the well. Each of the tubing valves is opened in sequence, so that a column of fluid is injected with gas. The fluid is lifted to the surface, and the next valve in the sequence is opened, sending the next column up. More columns are injected and lifted until the total weight of the fluid column, from the bottom of the well to the surface, has been reduced to the point that the well begins flowing.

 

When Should You Use Gas Lift?

It’s obvious that gas lifts can be used in a wide variety of contexts, but they can also be used in wells producing a wide range of volumes as well, from tens of barrels a day to tens of thousands of barrels a day, making it a very flexible system. Maintenance and installation costs are also usually lower, and it’s generally easy to service. It’s also useful in contexts where sand might clog or damage other types of lifts. It’s particularly useful when a well is deviated, and the wear on rods may be a concern.

 

How To Get Started With A Gas Lift

A gas lifting system has three primary parts. The inlet provides a supply of high pressure gas. This leads downhole, the second part, to the system in place there. The outlet is where the produced volume is sent and the gas recaptured.

The best option for gas lift is a large supply of high pressure, dry natural gas. Ideally, produced natural gas, which will mostly likely be wet, is sent to a processing plant to strip way fluids. The dry gas can then be sent back to the lease for pumping; usually a central gas distribution system supplies all of the wells which can be placed near the processing plant.

It is possible to use wet gas to power a gas lift system. However, you’ll spend a great deal of time in maintenance, and you’ll need to install some additional equipment. You’ll need to install some sort of scrubber to strip out all the fluids from the gas. You’ll also need to install a compressor to put the gas under enough pressure to be useful. Under the higher pressure conditions of the flow line, water may separate from the fluids. Drop pits are required to keep the condensation contained.
The gas is sent to the well through a control valve that is usually near where a pipe from the compressor meets the wellhead. A choke valve is also installed at the wellhead to vary the amount of gas that is injected into the well. You’ll want to set the choke valve so that you’re using gas as efficiently as possible. Near the bottom of the tubing string, a packer is used to seal off the annular space below the casing perforations from the space above.

Gas Lift

Figure 2. A two pin pressure recorder at the wellhead. (courtesy of McMurry-Macco Lift Systems)

As with other types of lifting systems, a simple recording device at the wellhead can be very helpful when it comes to diagnosing problems. For a gas lift system, a two pin pressure recorder is a reliable way to keep track of the pressures used in the gas lift valves during operation, and to keep track of the lifting system’s overall efficiency. Using the information the recorder provides, you can monitor how much gas is being injected, and adjust that amount so you’re hitting the production amounts you need, as well as diagnose a variety of problems.

It is important to consider the what changes or improvements you’ll need to make to your tank battery to use gas lift. Using gas lift can have an impact on the equipment needed for handling natural gas, water produced from the well, and crude oil, and you should plan for a higher level of production for all three.

Using Hydraulic Systems to Power Multiple Wells in Oil & Gas Production

Hydraulic Systems

Figure 1: An example of a central power system.

Using one central hydraulic system to power multiple wells is a popular setup. A single triplex pump, depending on the amount of power oil needed, could supply power oil to up to eight wells. The advantage of using such a system is that you only need to obtain and maintain a single hydraulic power system. The downside is that when that system is down for repairs or maintenance, all of the wells that depend on it stop producing.

 

Power Oil Tanks

Crude oil is the most common source of hydraulic power for lease pumping. This oil is stored in the power oil tank in the tank battery. The power oil tank is the last tank in the oil processing system and is located just before the crude oil stock or sales tanks. The power oil tank is usually taller than the sales tanks. This allows the supply from the power tank to be located about two feet below where the excess production equalizes over into the sales tanks.

In addition, two feet below the standard supply line, there is an emergency supply line controlled by a separate valve. The valve can be opened to supply additional power oil in the case of an emergency. When everything goes back to normal, you can just shut that valve to stop the additional flow of power oil. It’s usually straightforward to pump oil in the sales tanks back to the power oil tank if it runs low.

 

Power Oil Lines

The other major component of using a central power oil system are the power oil lines. The hydraulic system should be placed near the tank battery. Once the header has been installed, a separate power oil supply line is run to each oil well; usually a 1-inch line is enough to do the job. A return flow line is then run from the well bank to the tank battery. Each well will have both of lines to link it to the overall system.

Hydraulic Systems

Figure 2. Power oil lines running from the central power system to each well. (courtesy of Trico Industries, Inc.)

 

Using Produced Water

It’s possible to use water produced from a well in place of crude oil. It’s not possible in every case, as the water has to be free of scale and corrosive compounds that damage equipment and are hard to eliminate.

However, in areas where it’s possible, it can be a wise choice. Water is easier to control than oil, and easier to neutralize. A special fitting can be added to the heater/treater that draws water from the system. Alternatively, it’s possible to tap directly into the produced water disposal system. That means that when using produced water, you don’t need to add a power oil tank to your tank battery.

 

Using A Closer Power Oil System

The power oil can be pumped and reused through its own system by adding a third line from the surface to the hydraulic pump. This sort of system would also require a special power oil tank be installed, as well as the additional line to the pump. However, it’s a good option when the produced fluids are too corrosive to be used for power.

 

Spotting Problems With Multiple Wells

When you’re using a single pump for a single well, problems are usually fairly straightforward to spot. When production starts to fall suddenly, you only have one set of equipment to check for issues.

If you’re operating multiple wells off a single power source, however, that multiplies the amount of work you have to do. It’s helpful to be able to narrow down the problem to a single well and its associated systems. To do that, you’ll have to put together a distribution manifold.

A standard layout is shown on the diagram. It controls five wells, each with a riser and set of valves, while the sixth valve is used in testing. It’s possible to test an individual well’s flow by opening (in this diagram) the first, lower valve on the right, which is the automatic bypass. By opening the second header from the right, which is the individual well test line, it’s possible to send the power oil through a meter which tracks the number of barrels that have gone through in a given period. After the oil goes through the back line and comes forward again to the selected well header, that valve is opened and the front valve is closed so that the test can begin. Returning the valves to their original settings will return the system to normal operation.

It’s possible to modify the manifold header depending on your needs. For example, it’s often helpful to add openings so you can add solubles or chemicals if you need to.

Hydraulic Systems

Figure 3. An example of a distribution manifold for five wells, including a system for testing individual wells using an automatic bypass. (courtesy of Trico Industries, Inc.)

Single Well Hydraulic Systems in Oil & Gas Production

Single Well Hydraulic Systems

Figure 1. A unidraulic system for a single well. (courtesy of Trico Industries, Inc.)

Hydraulic Systems For A Single Well

Hydraulic systems can be used to pump a single well, or as a central power system for several wells. When using it with a single well, the hydraulic triplex system is placed on the edge of the location. The power line is run from the hydraulic unit to the wellhead. Fluid that has been produced from the well, including the power oil, is returned to the hydraulic system vessel.

The produced fluid is separated by the vessel in three stages. The water falls to the bottom, and by line height automation is duped into the flow line. The water and the produced gas are sent to the tank battery, where the gas comes off the top of the vessel.

The oil in the vessel is first utilized to operate the hydraulic lift system through a special line from the vessel to the triplex pump. The pump places the oil under high pressure, and it is piped to the wellhead and then downhole to operate the pump. Downhole pumps lift oil on both the upstroke and downstroke to pull fluid from the formation, combining it with the power oil before the fluid is pumped back to the hydraulic system vessel. Any oil above the amount needed to operate the pump automatically flows out and is commingled with the produced gas and water in the flow line, returning to the tank battery.

Operating a hydraulic system requires that enough oil be transported from the tank battery to the well to fill the tubing with oil, operate the system until it is full of fluid, and send the produced oil to the tank battery. A small truck can haul enough to oil to activate the system. It can be worth it, however, to install manifold bypass systems at that tank battery and at the well to make the transport unnecessary.

After the system is initially activated, the produced gas and excess liquid are separated, with the excess liquid being dumped into the flow line. The vessel retains enough liquid in the vessel to allow the system to operate for a short time without running out of liquid. That’s a measure that’s intended to reduce the need for pumping or hauling more power oil from the tank battery.

 

Should You Use A Single Well Hydraulic System?

When problems occur with a triplex pump on a single well, only that well has to be shut in. Other wells on the lease are independent and continue as usual. Additionally, the length of the power oil line is reduced from the distance to the tank battery, just the distance across the location, and the triplex equipment in general is smaller.

However, using a triplex pump for each well is not always the best choice. It means that a pump has to be installed at each location, and also requires either an electrical or mechanical prime mover for every pump. If it’s electric, a power line must be run to each location. It also requires the purchasing and maintenance of many pieces of identical equipment that will require maintenance and repairs.

Different Types of Hydraulic Lift Pumps in Oil & Gas Production

Basics of Hydraulic Lift

Hydraulic systems uses fluid pressure to power a pump. That is done by pumping fluids downhole using a triplex pump designed for extremely high pressure, usually between approximately 2,000 and 5,000 psi. Hydraulic lifts are flexible, and are useful for wells that are producing any volume, from low to high. In general, hydraulic lifts have higher production volumes than mechanical lift pumps.

Hydraulic Lift Pumps

Figure l. A central triplex, high pressure pump.(courtesy of Trico Industries, Inc.)

The hydraulic, reciprocating pump is at the bottom of the well. New oil is pulled from the annulus by the pump. The newly produced oil and power oil are combined, then pumped back to the surface and then to the operation’s tank battery.

Hydraulic Lift Pumps

Figure 2. A hydraulic pump’s up and downstroke. (courtesy of Trico Industries, Inc.)

Fluid is recycled to operate the wells. For a rough guideline, for every three barrels pumped into the well as power oil, you can expect to see five barrels pumped back to the surface. The extra two barrels is new production. The pump will produce oil on the triplex pump’s upstroke and on its downstroke, and its speed can be adjusted using a valve.

 

Hydraulic Lift Pumps

There are a few different options when using hydraulic lift pumps. Among the different options are:

  • Fixed casing.
  • Free casing.
  • Fixed insert.
  • Free parallel.
  • Jet pump.
  • Closed power fluid.
  • Commingled power fluids.

Some of the options are more complex. We’re going to take a look at some of the simpler options, free parallel and fixed insert pumps, as well as giving a brief overview of what a jet pump looks like.

When you decide to put a hydraulic lift on your lease, you’ll have to choose between a free parallel or a fixed insert system. The pump is similar with both options, but the choice between fixed insert and free parallel can make a big difference on which wellhead you choose, and how you decide to install the moveable pipe.

 

The Free Parallel Pump

The free parallel pump using two strings of tubing, one of which is a smaller string that is strapped to the outside of the larger tubing string. Once you’ve lowered the tubing down into the well and installed the wellhead, you can simply drop the pump into the tubing.

You can then open the hydraulic valve so that the power oil or water flows down into the well, carrying the pump with it to the bottom. When the pump hits the bottom and seats properly, it will begin to function as lower as a power fluid is being pumped.

That power fluid will flow over with the produced oil and be pumped up to the surface through the smaller tube on the outside of the string. As with any pumping well, natural gas that is produced will mix with the produced oil and power fluid, and travel back to the tank battery.

An important advantage with this sort of pump is that it’s much easier to replace the pump when there’s a problem. The system is designed to allow a single person to bring the pump to the surface by turning a valve on the wellhead. The pump can be retrieved once it’s reached the surface with a few simple pieces of equipment.

Free parallel pumps can sometimes become knocked out of the proper position by solid objects, known as trash. The same valve that brings it to the surface to change can also be used to hop the pump up briefly, which will clear the trash. Returning the valve to its original position allows the pump to reseat. This is just as common with free parallel pumps as with insert pumps.

 

The Insert Pump

The insert pump is inserted (hence the clever name) into larger diameter tubing, usually. around 2 ⅜ inch. Attached to the top of the pump is a smaller diameter string of tubing, which is also inside the larger tube. The bottom of the pumps seats against the the tubing seating nipple. The pump is designed to use it’s own weight to hold it seated and in place. There’s a packer, so gas is returned to the surface up through the annular space, as with a mechanical pumping well. It’s then combined with the produced fluid from the wellhead, where everything enters the flow line. A pulling unit is required to retrieve the smaller tubing string and change the hydraulic pump.

Hydraulic Lift Pumps

Figure 3. Four different hydraulic pump designs. The fixed insert design is shown at the far left, and the free parallel design is shown third from the left. (courtesy of Trico Industries, Inc.)

As with the free parallel pump, trash can collect under the pump seating, causing production to fall or stop altogether. This can cause the column of fluid inside the larger diameter tubing to fall back into the well. A lift piston can be placed at the top of the wellhead so that power oil can be pumped under the piston. That allows the insert pump to use the same ‘hop’ technique as with a free parallel pump to clear trash and reseat the pump. This will remove the trash, and the pump will begin to operate normally again. You’ll most likely have to do this regularly while this pump is in use.

The valve on a pumping wellhead is designed so that a quarter turn of the valve handle opens the valves the correct amount to get the pump to hop up. Returning the valve to its standard setting will allow the pump and smaller diameter tubing to fall back to the bottom and where the pump will reseat.

 

The Jet Pump

Jet pumps are more complex. The jet action is produced using a venturi tube, which has a particular cone shape intended to narrow the flow path. The shape creates an area of low pressure by increasing flow rate. Fluid is drawn into that low pressure area.
There are a few contexts where a jet pump is going to work well. It’s common in wells offshore, where space is tight, as a single triplex unit can power several wells at once. Jet pumps can also be used with continuous coiled tubing and in horizontal completions.

Hydraulic Lift Pumps

Figure 4. A jet pump’s basic components. (courtesy of Trico Industries, Inc.)

Should You Use A Hydraulic Lift?

Hydraulic lifts have a few advantages compared to other high volume production systems, but no production system is perfect.

A key advantage of using hydraulic production systems is that it’s easy to adjust the volume of the power fluid pumped. Hydraulic pumps can also handle a high daily production volume. Free pumps, in particular, can be replaced by one or two workers without needing a whole crew.

There are some chronic problems with hydraulic lifts systems, however. Keeping enough clean oil or water to use for power fluid can be difficult in some areas. When equipment fails, it can be time consuming to repair, with one or more wells shut in for long periods. There is also simply more equipment to monitor and maintain, as you’ll need both an additional tank for power fluid, and several tube strings in addition to power fluid lines for the hydraulic systems.

Submersible Electrical Pumps for Oil & Gas Pumping: Automatic Controls

Well Operation and Automatic Controls

You may choose to operate your well continuously, or only run the submersible pump for part of the day. The well capacity and the amount of fluid you need to produce in a day will determine which is best for your operation.

In the past, pump controls were fairly simple and standardized. Computer controls have become much more popular, and allow for greater automation. New versions and control designs are common, however, it’s important to understand how your specific setup works.

Submersible Electrical Pumps

Fig. 1: The wellhead of an electrical submersible pump. It includes a check valve, pressure gauge, union, ball valve, and a hose for monitoring production.

One of the more important parts of the wellhead is the check valve, which must hold when the electrical submersible pump is in operation. If the check valve leaks, the liquid can drain back into the formation. This can cause the pump to freewheel and turn counterclockwise while the well is shut in. If the power is turned on while the pump is spinning in reverse, the sudden torque can cause shaft failure. In order to repair the pump after that sort of failure, you’d need to pull the entire pump. To prevent problems keep an eye on the wellhead gauge, which will usually indicate if a problem is developing.

 

Well Installation and Controls

Deeper wells and wells that have higher production volumes will have more elaborate controls, as well more complex equipment. In Figure 1, you can see an electrical submersible pump that’s about as simple as it can be. It has everything such a well needs to operate, but on a marginally producing well, it would have a minor impact on the lease income in the event of problems. With a higher producing well, it’s usually worth it to invest in more complex systems. The more information you have, the easier it will be to recognize and analyze production problems and reduce downtime.

 

Running a Pump Full Time

To monitor a well’s production, you’ll want to install a chart at the wellhead. When the pump is operating continuously, the chart will have two steady lines on it. One indicates the casing pressure while the pump is running, and the other indicates the tube pressure in the flow line. You’ll want to keep an eye on the chart even when the well is operating normally. You’ll then have a set of baselines you can use to diagnose problems. Without the record that a chart provides, analyzing performance to identify problems is more difficult.

Submersible Electrical Pumps

Figure 2. This chart shows a typical record of a pump in continuous operation. (courtesy of Reda Pump Company)

 

Running a Pump Part Time

There are some particular things to look out for if you’re only going to be running your submersible pump part of the time. When the pump isn’t in operation, the casing pressure will increase and the tubing pressure will be lower. When the pump is on, the reverse will be true, with the casing pressure dropping as the liquid level in the casing falls. Likewise, the line pressure in the tub will increase when the pump is operating. There are sets of diagrams that demonstrate what the chart will show if the pump is not operating normally.

Submersible Electrical Pumps

Figure 3. A chart showing a typical chart record of a pump running only part time.(courtesy of Reda Pump Company)

Fixing Problems

When you do run into problems with a submersible pump, you’ll most likely need some special equipment. It’s also a good idea to have an experienced technician on site who can offer advice and weigh in on decisions.

When you pull the tubing, the cable clamps and bands should be removed, and the electrical line should be spooled onto a special trailer that has been brought to the lease for the workover. After servicing, the electrical line can be re-clamped to the outside of the tubing as it’s run back into the hole.

Using Submersible Pumps for Lease Pumping in Oil & Gas Production

When a well’s production starts to fall due to decreased hole pressure, there’s a few techniques you can use to bring its output back to former levels. Mechanical lift can be one method, but once production begins to fall further, a lift may no longer be effective.

It is possible to extend the usefulness of a mechanical lift and change the lift system in order to make up for the fall in production. You could try adjusting the lift system by increasing the stroke rate, or install a pump with a lighter counterweights and a longer stroke. As you begin to pump more water and less crude oil, another method to try is a waterflood, which uses water pumped in at a reservoir to push oil to wells being pumped.

Eventually, however, production will fall to the point that you’re pumping constantly through the day due to the increase of water production. At that point, you’re going to have to put in a system that can make up for that fall in production. An electrical pump is a good option, particularly in waterflood operations with a high volume.

 

Why Should You Use An Electrical Submersible Pump Lift?

An electrical pump lift is able to pump large volumes at medium and shallow depths, with casing size not having much of an impact on the production volumes. When waterflood increases, it’s not uncommon to pump a few thousand barrels a day. This system can easily use automation to have the system pump only for a certain amount of time each day, or to have it pump continuously. Electric submersible pumps have a relatively low get-started investment for shallower wells.

With that said, there are some potential problems when using an electrical submersible lift. Build up of scale or gyp sometimes reduce the fluid pumped by submersible pumps. High electrical costs can be another downside, particularly if you’re in a remote area. A submersible pump isn’t as flexible in some situations, and if there’s a problem the whole system has to be pulled.

 

How Does A Submersible Pump Work?

There are two primary parts of a submersible pump:  the pump itself and the electric motor that powers it. Generally, the pump is above the motor. An electrical cord is attached to the pump tubing, usually protected somehow, and is used to provide power to the motor.

The whole thing is dropped into the well with both the motor and pump submerged. The pump works by rotating a series of disks or cups, driven by the motor. To pump from deeper wells you’ll need to add more cups, which allow the pump to push liquid further up to the surface.

 

On The Surface

There’s a few things to keep in mind about the surface needs of a submersible pump, you may have to be flexible and innovative. A common suggestion is to run a joint of pipe from the well to the control panel, which will provide a conduit through which to run the power cable. The pipe will protect the cable from being damaged by equipment or weather. You may also want to leave the power cable a little long, and hang it by the control panel. You’ll be able to lower the pump without having to splice additional cable into the electrical cord.

Pump Basics

Submersible Pumps

Figure 1. A pump and motor.

Surface Components:

Control Box: As you might have guessed, this controls the pump motor. It can be set to allow the well to operate continuously, for set periods, or to be shut off. It can also protect the pump motor from electrical surges or other electrical problems.

Transformers: These transform the power received from the electrical grid to the correct specifications for the pump. These are usually placed at the edge of the lease site.

Electrical Supply: The power grid that supplies your transformers. The highest voltage you can get usually produces the best result.

Tubing Head: This component supports the tube and also provides a seal for the electrical cord to pass into the tubing. The seal is commonly designed for at least 3,000 psi.

Chart Meter: A chart meter isn’t required for operation, but it can be worthwhile. It measures the well’s production, providing information that can help identify problems.

Submersible Pumps

Figure 2: Surface components necessary for an Electrical pump.

Submersible Components:

Cable: The cable leads from the surface, down the outside of every joint of tubing. It is strapped to the side of the pump, and leads directly to the motor. It consists of a flat three strand wire where it enters the motor, but is a round cable for most of its length. It may have a metal shield to protect it.

Motor: At the bottom of the pump, it is lowered into the well first. Use the correctly sized motor for your estimated production.

Protector: This is attached to the top of the pump, and seals the motor to allow a drive shaft to drive the pump.

Pump: The pump itself, designed to carry a fluid load. Usually, the shaft is made of an alloy called Monel, with the stages being made of a corrosion and wear resistant material. Most pumps of this type have a rotary centrifugal action.

A Pumper’s Basic Guide to Mechanical Lifts in Oil & Gas Production

Throughout the life of a flowing well, a variety of systems can (and often will) be used. Sometimes these mechanical lifts are used in sequence, on more than one occasion, or even in conjunction with one another. In most oil field cases, there are four common artificial lift types used; these include:

  • Electric Submersible Pump – a pump located at the base of the well, and powered by electricity from the surface.
  • Gas Lift– a type of artificial lift where natural gas is injected into the tubing at specific intervals to help lighten the weight of the fluid, and thus progress upward towards the surface.
  • Hydraulic Lift – contains a hydraulic pump powered by oil or water that is pumped down into the well.
  • Mechanical Lift– a lift operated by an engine or motor located on the surface.

While all four systems have their own distinct advantages and disadvantages; lease pumpers tend to use mechanical lifts more often than other options. To understand a little more about the pump operations of this device, make sure you grasp these important areas.

 

The Basics of Mechanical Lifts

Mechanical pumping units use the same operating principles as a water well (that contains a standing and traveling ball at the bottom, a string of sucker rods, a power source at the top/surface) or windmill to function. These systems are sometimes referred to as rod pumping units, and utilize an up and down reciprocating motion.

Mechanical Lifts

Figure 1. Example of a Conventional Pumping Unit (beam-style)

The pumping unit crank uses a circular motion created by the rotation of the sheaves/pulleys, belts, and gearbox; driven by the prime mover, the gearbox typically uses an electric motor or gas-powered engine. The pitman arms are attached to the walking beam, and the circular action is altered into a responding power to the walking beam and horse head. To offset the weight of the string of rods (usually extend through the tubing all the way to the base of the well) , and the weight of the fluid within the tubing; counterweights are used. In most cases, lease pumpers will utilize a ball and seat standing and traveling valves design to pump the liquid from the bottom of the well, through the line, and into the tank battery.

When the pumping unit begins, the pumping unit head moves upward, raising the pump’s sucker rod string and plunger. As it moves upward, the traveling ball or ball closes, preventing the oil from traveling through the plunger. This movement lifts the fluid up to the surface, while decreasing the pressure below the plunger. The standing valve at the base of the pump opens as a result of the reduced pressure, thus allowing the additional liquid to flow into the bottom of the pump.

Once the rod string moves downward, the pressure increases above causing the standing valve to close. This impedes the oil entering the pump barrel from flowing back into the formation, and allows the pressure between the valves to build up. Once the pressure is greater than the weight of the liquid within the tubing, the traveling valve will open and the plunger will pass down through the liquid and into the pump barrel during an upstroke. At the top, the plunger will get trapped causing the traveling valve to close at the start of the next upstroke; with the cycle continuing as production continues. The specific cycle time (referred to as SPM, or strokes per minute) is determined by a number of factors, including:

  • the pumping unit configuration
  • ratio of gearbox gears
  • size of sheaves/pulleys
  • speed of the prime mover

Mechanical Lifts

Figure 2. Example of a ball and seat valve. This design is a typical design found in the standing and traveling valves of mechanical lift systems.

A mechanical pumping action description illustrates how the unit raises the fluids to the surface during the upstroke; while hydraulic lift pumps raise the fluid on both the upstroke and the downstroke. Since no rods are moving in hydraulic pumps, this allows it to move more rapidly than pumps with rods. Hydraulic pumps are also capable of lifting higher volumes of liquids.

Both gas lift and electric submersible pump systems lift continuously during operation, allowing all three of these artificial lift systems the capability to lift higher production volumes each day than mechanical lift options. However, the majority of wells are not continuously run. Therefore, whether an artificial lift can be used during the whole operation, or during only part of the cycle, is not typically a deciding factor.

Many changes occur downhole during the pumping cycle as the rod string moves up and down, such as:  

  • As the rod string proceeds upward, the oil within the tubing is shifted from the standing valve to the traveling valve.
  • The rod string length grows longer as the plunger attempts to lift the weight of the fluids up and aims to overcome both the oil and tubing friction and surface tension.
  • As the weight within the column is raised, there is less weight placed onto the tubing, and thus the tubing string length shortens (or the tubing string travels the short distance up the hole).
  • The friction caused by the upward motion of the oil causes a small lifting force to the tubing.
  • As the plungers travels downward, the weight of the oil within the tubing is transported from the traveling valve back to the standing valve.
  • As the freshly gathered liquid pushes back against the rod string, the rod string decreases in length.
  • Once the traveling valve opens, the weight from the liquid is placed on standing valve and against the tubing string, causing the tubing string to lengthen and the load to increase. Depending on the column fluid weight, the depth of the well, and the size of the tubing; the bottom of the tubing string will move downward anywhere from a few inches to several feet.
  • The downward motion of the tubing causes the pump to overtravel, meaning the pump is traveling away from the surface during the downstroke and gathering additional liquid.

The cyclic load factor is the reaction from the tubing and rods responding to these changing forces, while breathing refers to the up and down motion from the tubing in the hole. Changes to the rod and tubing string length can be determined to calculate the proper adjustments required for the surface stroke length.

 

Implementing Mechanical Pumping Systems

One of the most productive ways to date for producing artificial lift wells is to utilize a mechanical pumping unit; and is also a great method for marginally producing wells. Mechanical pumps are a great system for low production wells because the equipment requires very little monitoring.

Once the installation is made, it is not only very economical to maintain, but it is ideal for continuous or intermittent production, due to its easy automation. However, the exact lift method chosen is based on what is most appropriate for the exact situation at hand. For instance, other lift options may be chosen to allot for higher production rates; while shallow offshore wells may choose a mechanical lift for a variety of application purposes.

Cyclic Load Factor Issues

The breathing action of the rod and tubing strings and the cyclic loading can cause a variety of issues. These can include:

  • Liquid leaking back into the tubing (caused by collars and tubing wearing where it falls back to the bottom of the hole); and in severe cases, can cause the tubing string to separate.
  • Holes worn into the casing string (eventually causing the casing to leak)
  • Malformations of the rods and tubing (ex. rod stretching or tube shortening) – This causes a decrease in overall pumping efficiency and production; and as a result, the lease pumper will have to pump the well longer to overcome the pump stroke loss.

To help reduce the up and down motion at the base of the string, a tubing holddown (similar to a packer except it lacks the rubber seal) can be placed at the base of the tubing string allowing fluids to move freely. This helps to prevent motion in the upper area of the tubing string. However, it may require several thousand pounds of tension. For example, if a 10,000 foot well used a 2 7/8 inch tubing, it could require a 25,000 pound tension weight to pull on it above the weight of the string; and is a common type of installation in deeper wells.

Operating at Incorrect Speeds

The cyclic load factor can create many issues, which can be further complicated by the unit pumping at incorrect speeds. For instance, medium to deep wells may experience issues with the top rod moving downward toward the surface while the pump traveling valve is still moving upward (or vice versa). This problem can be magnified when the pumping operations are not carefully arranged in advance. Otherwise, the RPM, sheave diameter, SPM, and/or various other factors may not match the specifics of the well for the best production and longevity.

In cases where the cyclic load factor is large, there is a greater chance for stretch in the rod and tubing strings, and for their relative travel to one another to get out of sync. In these situations, increasing the number of strokes per minute can actually decrease the stroke length at the bottom of the well. However, it is important to keep in mind that although the strokes per minute has increased, the amount of fluid produced will have decreased.
The majority of pump companies provide some type of service where they will determine the proper pump component plans based on your pumping conditions (ex. depth of the well, size of rods, strokes per minute, etc.). By planning ahead with the proper well characteristics, the lease pumper can help confirm if a mechanical lift is appropriate for the lease.