150 Aprimerofoilwelldrillinc

During drilling, the operator can run logging while drilling (LWD) tools in the drill stem. These instruments incorporate sophisticated electronic devices that sense, transmit, and record formation characteristics as the bit drills ahead. The LWD tool transmits formation information on a pulse the tool creates in the drilling mud. Much as radio waves transmit sound information through air, mud pulses transmit forma­tion information to computers on the surface. The computers analyze and display the information in readouts that experts on the site can interpret and evaluate.

DRILL STEM TESTING

To further determine the potential of a producing formation, the operator may order a drill stem test, or DST (say "dee-ess-tee"). The DST crew makes up the test tool on the bottom of the drill stem then lowers the tool to the bottom of the hole. The crew applies weight to the tool to expand a hard-rubber sealing element called a packer. The expanded packer seals the hole above the packer. The DST crew then opens ports in the tool that lie below the packer. Opening the ports exposes recorders to pressure. Analysis of the downhole pressures indicates whether the well can produce.

CORING

In some cases, the operator may wish to examine directly a formation sample that is larger than the cuttings. If so, a core sample is ordered. Two coring methods are available. In one, the drilling crew makes up a core barrel and runs it to bottom. When the driller rotates the core barrel, it cuts a cylinder, or core, of rock. The core is often several inches (or millimetres) in diameter and several feet (or metres) long. As the core barrel cuts the core, the core moves into a tube in the barrel. After the desired length of core is cut, the crew trips out the drill string and the core barrel. At the surface, the core is removed and shipped to a laboratory for thorough analysis. The second coring method uses a sidewall sampler. In this method, the crew lowers the sampling device to the desired depth. The driller actuates a switch to make the sampler fire an explosive charge. The explosion rams several small cylinders into the wall of the hole. Wires on the cylinders keep them attached to the sampler. Then when the crew retrieves the sampler, the cylinders, along with bits of the formation, follow the sampler to the surface. Sidewall samplers can obtain up to thirty small samples from any depth.

The operating company carefully considers the data it obtains from the tests. Then it decides whether to set production casing or liner and complete the well or to plug and abandon it. If the company decides to abandon it, the hole is dry. Dry in the sense of an oil or gas well means the well cannot produce oil or gas in commercial quantities. Some oil or gas may be present but not enough to justify the expense of completing the well. If the well is dry, the operator hires a cementing company to place several cement plugs in the well to seal it permanently.

Completing the Well

SETTING PRODUCTION CASING

If the operator decides to set production casing, a supplier brings it to the well. For the final time, the casing and cementing crews run and cement a string of casing in the well. In the case of our model well, the crew could run 5-inch (127-millimetre) casing in the 7%-inch (200-millimetre) hole. Keep in mind that the operator may elect to set a liner string. As you recall, a liner string is the same as a casing string except that a liner does not run all the way to the surface. Instead, the casing crew hangs it inside a previously run casing or liner. Usually, the casing and cementing crews set and cement the production casing or liner through the pay zone. The drilling crew drills the hole so that it goes all the way through the producing horizon and stops a short distance below. Then the casing crew runs the production string almost to the bottom of the hole. (It leaves a little room beneath the guide shoe to allow cement to flow out of the casing.) The produc­tion casing or liner and the cement actually seal off the producing zone. At this point, the drilling rig and crews are finished with their job: they have drilled, cased, and cemented the well to the depth specified by the drilling contract. Their only remaining job is to disassemble the rig (rig down) and move it to the next drilling location.

A PRIMER OF OILWELL DRILLING

PERFORATING

The operator is not through, however. Because the produc­tion string and the cement seal the producing zone, the operator has to provide a way for oil and gas to get from the formation and into the well. Usually, the operator hires the services of a completion rig, which is a relatively small portable rig whose crews perform the final operations re­quired to bring the well into production (fig. 179).

Figure 179. This small rig is a well servicing and workover unit. The operator often employs such units to complete a well.

Completing the Well

Figure 180. Perforations (holes)

One important task is to perforate the well. A special gun shoots several relatively small holes in the casing. It makes them in the side of the casing opposite the producing zone. These holes, or perforations (fig. 180), pierce the casing or liner and the cement around the casing or liner. The perfora­tions go through the casing and the cement and a short distance into the producing formation. Formation fluids, which include oil and gas, flow through these perforations and into the well.

The most common perforating gun uses shaped charges, similar to those used in armor-piercing shells. Several high­speed, high-pressure jets of gas penetrate the steel casing, the cement, and the formation next to the cement. A perforating specialist installs the charges in the special gun and lowers it— usually on wireline, rather than drill pipe—into the well to the desired depth. The depth can be determined by running a collar locator log, which identifies the depth of each casing collar. By comparing the log with the overall number and length of the casing joints, the operator can accurately deter­mine the depth. Once at the desired depth, the perforating specialist fires the gun to set off the charges (fig. 181). After the gun makes the perforations, the perforating specialist retrieves it.

Figure 181. Shaped charges in a perforating gun make petforations.

A PRIMER OF OILWELL DRILLINC

RUNNING TUBING AND INSTALLING THE CHRISTMAS TREE

After the well is perforated, oil and gas can flowinto the casing or liner. Usually, however, the operator does not produce the well by allowing hydrocarbons to flow up the casing or liner. Instead, the completion rig crew places small-diameter pipe called "tubing" inside the cased well. In fact, the operator sometimes runs tubing into the well before perforating it. In such cases, the perforating gun is lowered through the tubing to the required depth.

Tubing that meets API specifications has an outside diameter that ranges from 1.050 inches (26.7 millimetres) to qVi inches (114.3 millimetres). Seven sizes between the two extremes are also available. As it does with casing, the crew commonly uses couplings to join tubing, although an integral-joint tubing is available that allows the crew to make up joints without using couplings.

Manufacturers also supply coiled tubing. Coiled tubing is a continuous length—it does not have joints—of flexible steel pipe that comes rolled on a large reel. Operators have completed wells over 20,000 feet (6,000 metres) deep with coiled tubing. Special equipment placed at the top of the well allows crew members to insert, or inject, the tubing into the well as they unwind it from the reel (fig. 182). The main advantage of coiled tubing is that crew members do not have to connect several single joints of tubing when installing the string. Consequently, coiled tubing takes considerably less time to run.

Figure 182. A coikd-tubing unit runs tubing into the well from a large reel.

Completing the Well

Whether using j ointed or coiled tubing, the operator usually produces a well through a tubing string rather than through the casing for several reasons. For one thing, the crew does not cement a tubing string in the well. Accordingly, when a joint of tubing fails, as it almost inevitably will over the life of a well, the operator can easily replace the failed joint or joints or, in the case of coiled tubing, remove and repair or replace the failed area. Since casing is cemented, it is very difficult to replace.

For another thing, tubing allows the operator to control the well's production by placing special tools and devices in or on the tubing string. These devices allow the operator to produce the well efficiently. In some cases, the operator can produce the well only by using a tubing string. Casing does not provide a place to install any tools or devices that may be required for production. In addition, the operator installs safety valves in the tubing string. These valves automatically stop the flow of fluids from the well if damage occurs at the surface.

Finally, tubing protects the casing from the corrosive and erosive effects of produced fluids. Over the life of a well, reservoir fluids tend to corrode metals with which they are in contact. By producing fluids through the tubing, which the operator can easily replace, the casing, which is not so easy to repair or replace, is preserved.

Crew members usually run tubing into the well with a sealing device called a "packer." They install the packer on the tubing string and place it at a depth slightly above the casing perforations. The end of the tubing is left open or is perforated and extends to a point opposite the perforations in the casing. The packer expands and grips the wall of the production casing or liner. When expanded, the packer seals the annular space between the tubing and the casing above the perforations. The produced fluids flow through the perforations and into the tubing string. The packer prevents them from entering the annular space, where they could eventually corrode the casing.

After the crew runs the tubing string, the operator has a crew install a collection of fittings and valves called a Christ­mas tree (fig. 183) on top of the well. Tubing hangs from the tree so the well's production flows from the tubing and into the tree. Valves on the Christmas tree allow the operator to control the amount of production or to shut in the well completely to stop it from producing. They also allow the operator to direct the flow of production through various surface lines as required. In addition, a special safety valve on the tree automatically shuts in the well if the tree is damaged. This automatic shut-in valve prevents reservoir fluids from flowing onto the surface if damage occurs. Usually, once the crew installs the Christmas tree, the well is complete.

F igure 183. This collection of valves and fittings is a Christmas tree.