When operating oil & gas wells, there are a variety of requirements to keep in mind when converting a flowing well to one utilizing a mechanical pumping configuration. For example, in order to extract the downhole packers, a tubing holddown is installed (if/when required) to ensure the correct pumping depth. This is due to the reduced bottom hole pressure; the removal of a packer helps to reduce formation pressure, and aids in promoting fluid flow.
Other requirements can include the need to reconstruct the wellhead in order to meet the particular requirements of a pump. For instance, some pumping units are used to remove water blankets from the matrix section to allow the well to flow properly again.
During these circumstances, a choke valve is typically left in place once the wing valve is utilized to help manage well production. While there are a variety of dedicated downhole pumps you can install to help better production, we will currently focus on the standard pumping configurations.
How to Prepare the Well for Downhole Pumping
During mechanical pumping well preparations, typically workers will remove the packers to help permit gas production throughout the annular space. It is mandatory for some type of holddown during production in order to thwart movements from the lower tubing section. However, it can be unconfined just enough to permit gas to flow adjacent to it and into the hole, if the operator prefers to keep the packer.
If you’d like to know more about holddowns, we go over it here: A Pumper’s Basic Guide to Mechanical Lifts in Oil & Gas Production, here: A Basic Guide to Operating and Servicing Pumping Units in Oil & Gas Production, and here: The Fundamentals of Downhole Pump Designs in Oil and Gas Production.
Pumping Wellheads
The image in Figure 1 is one of many techniques used for attaching the pumping wellhead. In this configuration, they removed the Christmas tree and placed a pumping tee with bonnet (or adapter flange) is installed.
As seen on the tubing header in the picture, a four-way tee includes a mounted pressure safety shut-in for the flow line on top. In the event of a clogged, frozen, or broken flow line; the safety switch shuts down the well until the proper attention is received. Once the well resumes production; the controls will reset.
Figure 1. Example of a Wellhead Design featuring a Casing Connection, a Typical Shut-In Control, and Tubing.
Figure 2. The Most Common Pumping Wellhead Designs include: a Casing Head, Polished Rod, Pumping Tee, Polished Rod Clamp, Rod Lubricator, Polished Rod Liner, Stuffing box, and Tubing Head. (Dandy Specialties and Larkin Products)
Selecting Wellhead Equipment
When determining the appropriate wellhead equipment, workers need to keep several factors in mind. This includes:
Polished Rod. It is very common to procure too short of polished rods when choosing polished rods. If this occurs while working on a troublesome well, it can also cause issues when the crew drops the rod string to tap the bottom and/or to complete other servicing tasks. During each stroke when the horse head is at its peak, an appropriately sized polished rod will be able to allow the polished rod to completely drop to the peak of the stuffing box.
The top of the polished rod should extend throughout the entire bridle carrier bar with enough allotted space to install an appropriate clamp, with enough additional room for the string to drop to the base to tap bottom.
When the horse head is at its peak, and the rod has the highest rod exposure outside the hole; the polished rod should be able to extend far enough beneath the stuffing box to drop the rod liner until it is up alongside the stuffing box.
Polished Rod Clamp. As seen in Figure 3, polished rod clamps are utilized during transportation to reinforce the rod string while the additional weight is carried by the carrier bar and bridle. The polished rod clamp is obtainable anywhere from one bolt up to four or five bolts (depending upon the rod load requirements). In some situations, lease pumpers may utilize two clamps for safety purposes.
Polished rod clamps have also been known to be placed beneath the carrier bar. This widespread practice is often used for wells with a record of polished rod failures (where the rod breaks at the carrier bar). The goal of the additional safety clamp is to help the rod string avoid traveling into the stuffing box. This clamp is often used to prevent a variety of different spills from occurring.
Figure 3. Two-Bolt Polished Rod Clamp Example
Polished Rod Liner. In order to protect the polished rod from wear, a polished rod liner is situated overtop of it. This method is simpler to avoid packing leakage from a stuffing box with a larger liner diameter. To ensure the proper polished rod liner is utilized, it should measure the optimum stroke length with an additional two added feet.
If the polished rod liner isn’t long enough, it is inclined to hang onto the obstacles in the wellhead during the upstroke, or it can even create issues while attempting to tap bottom. Workers should NEVER tighten the polished rod clamp while adjusting the clamp on top of the stuffing box.
If this occurs, each clamp tightening on the liner will create a series of indentations; and with each pumping stroke, a little quantity of compressed gas and oil is released into the atmosphere through the flawed section(s) of the polished rod liner goes through the stuffing box.
As long as the damaged polished rod liner is used, the leak will continue; and at the same time, other issues can (and will) occur as a result of the lost oil continuously running down the stuffing box and wellhead.
Unfortunately, even one slight instant of thoughtlessness can cause liner indentations. Each of these indentations can result in a variety of issues, including: lost time and needless replacement expenses.
Polished Rod Lubricator. In some cases, a free-floating polished rod lubricator with wick-action felt wiper pads is typically equipped to the polished rod. It is generally placed directly over the stuffing box.
This apparatus also provides additional lubrication for the polished rod and lengthens the packing life. During periods when oil is not produced, this additional lubrication helps the polished rod avoid getting too hot and destroying the packing; making this a particularly useful lubricator for erratically producing wells. In most cases, low-priced, non-detergent style oil is sufficient for use.
Rod Rotator. Paraffin is one type of by-product created during oil production. This waxy combination of hydrocarbons can cover the internal rods, surface pipes, tubing, and anything else the valves may come into contact with.
During specific depths, the earth’s natural heat helps keep the paraffin in a fluid-like state. However, once the paraffin elevates up into the hole, it solidifies. This causes the deposit on the rods and tubing.
Figure 4. Example of a rod rotator utilized for eliminating scale and paraffin.
To help prevent paraffin buildup, a common practice is to use a rod rotator (See Figure 4). This device is attached to the walking beam and situated on the wellhead. As the pumping unit pumps, the rotator slightly turns the rods with each stroke. Scrapers are utilized and placed close enough so that as the rods rotate with every stroke, the small over-travel scrapes the paraffin off.
While there are several paraffin-cutting paddle types, the majority of them are either circular or flat. However, these are not the only methods for eliminating paraffin. Other common options include:
- injecting chemicals
- pouring hot oil
- steam (often used on rods and/or tubing once pulled and laid on the racks)
The Stuffing Box. During the early years of the petroleum industry, the majority of stuffing boxes utilized a donut-shaped packing. To help improve the stuffing boxes’ efficiency, it was manufactured with a variety of different additive types (ex. lead or graphite). However, in more recent years the cone-shaped packing has become the more popular option (See Figure 5). While there is a more improved model that is practically leak-proof; for most marginal stripper wells, the costs for these models are not justified.
Figure 5. Example of stuffing box with a cone-style packing (Trico Industries, Inc.)
In most situations, the donut-shaped packing is still highly successful for marginal to shallow depth wells. If workers utilize caution and common sense during both installation and maintenance (including periodically tightening the packing); a packing set can last the lease pumper for several years, and in many cases with practically no leakage.
However, packing can be purchased in various qualities. Therefore, it is vital to keep accurate records and to keep track of all packing costs, in order for the lease pumper to determine the most economical and productive choices for the well. Through it all, the most important action is to keep the pumping unit carrier bar well centered over the hole.
Generally stuffing boxes have a grease fitting located on the side of the box. To prevent serious injuries, this fitting should never point towards the pumping unit. No matter what size pumping unit is utilized, the fitting should always point to the side or outward. Otherwise the edge of the horse head could strike a worker during the downstroke.
Casing, Flow Line Check Valves, and Tubing Issues
Check valves are another common source of issues for wellheads. During times when scale or trash accumulates under the check valve seat, or during internal failure; the check valve can fail to properly seal, allowing the fluid to escape and flow back into the wellbore.
Figure 6 shows two examples of wellheads. The left wellhead has 300-500 pound working pressure, while the right wellhead has a 2,000-pound working pressure. By monitoring the embossed numbers shaped into the forgings, the lease pumper can ascertain the screw connections and the pressure rating of a valve. (Determining fitting pressure ratings by a casual assessment is something each lease pumper should be equipped to do.)
Both wellhead examples contain each of the three wellhead check valves. The first is situated just following the wing valve on the upmost horizontal line. The second valve is situated directly beneath the first, while being properly aligned with the casing. (This second line also contains a wing valve.) Once both lines join, they are pointed towards the tank battery and to the third installed valve and check valve.
Figure 6. Example of two pumping wellheads with the right showcasing a high pressure unite, and the left showing a medium pressure-unit.
Casing Check Valve. This valve is used to permit the gas produced to flow from the casing to the tank battery. This feat is vital for new production to travel from the formation to the wellbore. From there the gas streams into the tank battery and throughout the casing. The fluid is propelled into the tank battery using the tubing. The casing check valve thwarts the fluids from being produced and flowing back into the bottom of the well. Even the slightest check valve leak can cause new production loss and befuddle the worker as to the correct quantity of oil production.
Flow Line Check Valve. The flow line check valve by the wellhead thwarts several issues from occurring if either (or both) wellhead check valves falter. If a tubing leak develops, then the column weight could pull the oil from the flow line back into the well. Flow line check valves also help reduce the produced oil from flowing from the header and into the well. When checked properly, this can correctly illustrate how things are transpiring to the lease pumper.
Tubing Check Valve. During certain productivity tests, it is necessary for the lease pumper to check the downhole pressure applied to the tubing. In order for accurate results, the pressure must be isolated from casing pressures. The check valve located just past the tubing wing valve prevents casing pressures from flowing back through the bleeder valve when the downhole pump action is checked at the bleeder valve.
