Drilling the well and cementing the casing are only the first steps to completing the well. Once complete, the rig crew will install tubing to bring the oil and/or gas from the reservoir back to the surface. This tubing is connected to a wellhead with some sort of control valve system (like a Christmas tree) to provide the workers control over the direction and speed of the product flow from the reservoir to the surface.
The Final String of Casing
The number of strings of casing used for a well depends upon how deep the well is. In some cases, the well may only have two strings of casing to reach from the bottom of the reservoir to the surface; the surface pipe and the final string of casing (also known as the long string or oil string). However, in deeper wells the final string may require more tensile strength or the lower joints may be created with extra support in the event of a collapse. In the event the lower joints are heavier than the rest of the joints on the long string, a similar joint is installed at the top (referred to as the gauge joint). The gauge joint provides the crew with a reference, letting the crew know that any tool going through the first joint will be able to go through all of them.
To determine what type of completion will be done, an analysis is done on the cutting samples received as the bit drills through the ground and into the reservoir containing the hydrocarbons. In most cases, the wells are completed by installing the casing all the way through the reservoir. Then enough cement is pumped down through the inside of the casing, and back up between the casing and the rock formation to cement the string into place. This is completed all the way through to the producing zone, and to a specific distance located above the impermeable cap.
Not all wells have the casing passed through the reservoir. In some cases, the well is drilled to just above the oil producing well. As with the cased hole completion, the casing is then run and cemented into place. Once set, the well is then drilled in (a procedure involving the reservoir to be drilled into and left open); creating what is commonly known as an open-hole completion.
Perforating and Completing
Once the final string of casing for the hole is completed (and the cement has set), it is time to perforate the casing. Over the years, this has been completed in multiple ways:
- setting off a charge of nitroglycerine in the bottom of the well, creating fissures and cracks in the reservoir formation,
- using a bullet perforated gun,
- and the current method of using a jet gun (which can perforate the wall of the casing, the cement, and even multiple inches into the rock formation.
In order to perforate the casing, it is essential for the crew to know what the bottom hole pressure is inside the pipe, as well as to anticipate the inside pressure of the formation. If the pressure is miscalculated and is greater in the formation than what is inside of the casing; the instant the perforations are created through the pipe, the fluids will rush into the casing (forced by the bottom hole pressure) and blow the perforated gun up the hole. It will go up the hole at such a tremendous speed that it will wad up the electrical line and create numerous problems.
In order to increase the strength, and reduce the possibility of production loss; tubing should be seamless, and not a welded pipe. While at one point the tubing was produced with IO-pitch V-threads, this method has since been replaced by a superior tubing option using 8-pitch round threads (commonly referred to as an 8 round). This tubing method is not only stronger; but it is also easier to make, and has with less risk of cross threading.
The tubing used is normally classified based on two things: the quality of metal used to make it, and the wall thickness. What type of tubing used is determined by the installation (and it must match). This includes how deep the well is, how high the gas pressure is, and various other factors.
Generally the tubing is designated by both a letter and a number. For instance, a cost-effective tubing option used for shallow wells is H-40, while J-55 is a common choice for wells around 7,000 feet. However, deep wells often use the heavy-duty pipe P-105.
Since the tubing has to reach a specific depth within the well, and be placed without being cut or threaded; tubing is usually available in a wide range or random lengths, typically ranging from 28-32 feet (with shorter lengths referred to as pup-joints). Pup joints (see Figure 1) are added to the top of the tubing string, and are used for final spacing (also, click here if you’d like to know more about Tubing String basics, Perforation Placement, Measuring Pipe Diameter, Running and Pulling a Tubing String, and basic troubleshooting of the Tubing String!)
Figure 1 . In most cases, tubing pup joints are offered in two foot lengths. (courtesy Dover Corporation, Norris Division)
The Tubing String
Once the tubing is placed, set with cement, and the crew has the reservoir opened to the wellbore; the tubing string is run. In most cases, the tubing string will comprise of the following items:
- Mud anchor
- Perforated subs
- Pup joint (optional)
- Packer or holddown (optional)
- Pup joints (as needed)
- Safety joint (optional)
- Seating nipple
- Spacer pup joints
- Tubing hanger or slips and seal
The Mud Anchor
The mud anchor is a full joint of tubing placed at the bottom of the string that may be cut off to a certain length. It is generally between 16-24 feet, and used for:
- collecting fine silt or mud (materials removed when the tubing string is pulled),
- providing a shelter for the pump gas anchor when the pump is in the hole, and
- allowing the tubing string to sit at the well bottom without plugging up the rod pump intake or damaging the string.
Depending upon the company, they will either use a tubing cap and a bull plug, or a collar and a bull plug to close off the bottom end of the tubing. There are also some companies who cut off the bottom section and weld the opening closed to avoid external protrusions from getting stuck or collecting scale; while others will often slice the bottom into for sections, and then heat them closed by folding each of the four sections over using a large steel hammer.
In order for the oil and/or water to enter the tubing string located in the reservoir, it has to be perforated. While there are a number of ways to accomplish this task, the most common options include:
- Installing a perforated pup joint over the mud anchor with a collar in between the two pieces. While the typical length is usually between 3 or 4 feet, perforated pup joints (see Figure 2) can be as small as 2 feet or as large as 12 feet. These holes in the tubing are around 1 inch in diameter and are placed a few inches apart on all sides. The purpose of these small holes is to prevent large objects from entering into the tube.
- Using a short joint or leaving the bottom of the pipe open just below the seating nipple. (Typically very few operators will use this method. This is due to the risk of large objects entering the pump and causing it to stop functioning.)
- Using a perforated mud anchor with an electric drill, or by cutting holes using an oxyacetylene torch. Generally these holes are 3-6 inches apart, and are placed no farther than 6 inches below the upset on each of the four sides (extending anywhere from 2-4 feet).
Figure 2. Perforated pup joint example (courtesy Dover Corporation, Norris Division)
Seating nipples are used to seal the pump to the tubing, while providing a connection for the pump. This allows the fluid produced to flow up through the seating nipple, and to be pumped back to the surface. In most cases, the seating nipples will either be:
- Cup-Type Seating Nipples
Cup-type seating nipples use a no-go ring of metal above the cups to prevent the pump from sliding through the seating nipple. The nipples use a seating distance of around six inches, with three or four cups on the pump. This type is reversible, with the reversible seating nipple between 12-16 inches long. The benefit to this type is it can be reversed to provide a new seating surface when scoring or any other type of damage causing the seat to leak.
- Mechanical-Type Seating Nipples
Mechanical-type seating nipples are not reversible and are around 8-10 inches in length. The top of the seat is usually tapered to allow a metal-to-metal seat; with the seat made of a metal that will slightly give to ensure the seating nipple seals properly.
Wells can be completed with or without a packer; and is used to provide a seal downhole to block the fluid flow from between the tubing and the casing or wellbore wall. The packer is placed near the bottom of the tubing string, and installed just above the casing perforations. Often times, you can increase the flow velocity by using a packer to help reduce the cross-sectional area of the well flow opening.
If a well does not have gas pressure in the annulus (aka annular space between the casing and tubing), then the wells with low bottom hole pressure will bleed into the tubing perforations as the casing empties the liquid. The packer can reduce this unpredictable change in pressure, and acts as a flow cushion while the liquid accumulates again in the well.
Holddowns are similar to packers in the sense it fastens the tubing to the casing just above the casing perforation near the bottom of the well; and are installed into deep pumping wells as a preventative measure for breathing – the up and down motions at the bottom of the tubing created by each stroke of the rods (click here if you’d like to go into more detail about breathing, the change in the length of the rod and tubing strings, and the computation of these changes required to adjust your surface stroke!). However, unlike packers, the holddown does not create a seal between the tubing and the casing in the annular space. Due to this, fluids are able to freely pass through in either direction without any restrictions.
One of the most important duties while installing the tubing into the hole is placing the casing perforations in the best desired depth away from the surface. Where these are placed will affect the overall performance of the well, how many barrels of fluid are produced, how much gas is preserved in the formation, and the amount of gas or oil produced. Since there are multiple options correlating perforations, it is up to the operators to decide which option is best for the correlating perforations (including how to reach the production goals).
Along with each string of casing run into the well, a correlating wellhead section must be installed. Figure 3 demonstrates a typical two section wellhead with a Christmas tree for a flowing well. While there are a variety of configurations you can use, the below Christmas tree provides a great example of the casing head (labeled A) and the intermediate head (labeled B).
Figure 3. Christmas tree for a two section wellhead
The Casing Head
The casing head is usually welded directly to the casing, and can have external threads, a slip-on collar, or internal threads. The welding installation permits the tubing string to be situated at a specific level, and is especially important for a proper pumping unit installation. A 2-inch bleeder valve is installed on one side, with a ball valve, gate valve or plug can be installed on the other. The type of valve installed is always left open to prevent developing pressure from threatening any fresh water zones. In most cases, the wellhead will use one of three (gate, globe, or needle) multiple round opening style gate valves (commonly referred to as a gate).
Figure 4. Example of a casing hanger with hanger locking devices
The Intermediate Head with Casing Hanger
As a rule, the final string of casing is frequently hung from the intermediate head; with the casing hanger secured to the top of the casing head. The casing hanger will usually have some form of a metal ring seal, and at least 12 studs (with nuts). However, several casing hangers offer some way to connect the tubing string to the casing hanger (see Figure 4). When the casing hanger and final string are attached, there will be two openings (one that is available and the other connected to the flow line of the tank battery) on the sides with valves fastened into them.
The Tubing Hanger
Installing the tubing hanger is the final step in the running tubing; and should be properly cleaned and covered in lubricant (or a thread compound) prior to being lowered into the hole. The locking devices (known as dogs) should run snugly in order to hold the top tapered edge firmly in place to allow for safe removal of the Christmas tree with pressure still on the casing.
Figure 5. The tubing hanger is commonly referred to as the donut.
Is your appetite for oil & gas operating knowledge insatiable like ours? 😀 If so, check out these related articles, Where is Crude Oil Found? The Structure of Oil-Bearing Formations… and, A Basic Guide to Oil and Gas Drilling Operations – they’ll be sure to pump you up!!!