Differential-pressure pipe sticking occurs when a portion of the drillstring becomes embedded in a mudcake (an impermeable film of fine solids) that forms on the wall of a permeable formation during drilling. If the mud pressure, pm, which acts on the outside wall of the pipe, is greater than the formation-fluid pressure, pff, which generally is the case (with the exception of underbalanced drilling), then the pipe is said to be differentially stuck (see Figure 1). The pull force, Fp, required to free the stuck pipe is a function of the differential pressure, Δp; the coefficient of friction, f; and the area of contact, Ac, between the pipe and mudcake surfaces. In this formula, Lep is the length of the permeable zone, Dop is the outside diameter of the pipe, Dh is the diameter of the hole, and hmc is the mudcake thickness. The dimensionless coefficient of friction, f, can vary from less than 0.04 for oil-based mud to as much as 0.35 for weighted water-based mud with no added lubricants.

The causes of mechanical pipe sticking are inadequate removal of drilled cuttings from the annulus; borehole instabilities, such as hole caving, sloughing, or collapse; plastic shale or salt sections squeezing (creeping); and key seating. Excessive drilled-cuttings accumulation in the annular space caused by improper cleaning of the hole can cause mechanical pipe sticking, particularly in directional-well drilling. The settling of a large amount of suspended cuttings to the bottom when the pump is shut down, or the downward sliding of a stationary-formed cuttings bed on the low side of a directional well can pack a bottomhole assembly (BHA), which causes pipe sticking. In directional-well drilling, a stationary cuttings bed may form on the low side of the borehole (see Figure 1). If this condition exists while tripping out, it is very likely that pipe sticking will occur.

During drilling operations, a pipe is considered stuck if it cannot be freed from the hole without damaging the pipe, and without exceeding the drilling rig's maximum allowed hook load. Pipe sticking can be classified under two categories: differential pressure pipe sticking and mechanical pipe sticking. Complications related to stuck pipe can account for nearly half of total well cost, making stuck pipe one of the most expensive problems that can occur during a drilling operation.[1] Stuck pipe often is associated with well-control and lost-circulation events--the two other costly disruptions to drilling operations--and is a significant risk in high-angle and horizontal wells. Drilling through depleted zones, where the pressure in the annulus exceeds that in the formation, might cause the drillstring to be pulled against the wall and embedded in the filter cake deposited there (Figure 1[2]).

Pressure-Differential Sticking of Drillpipe and How It Can Be Avoided or Relieved.

Casing and tubing strings are the main parts of the well construction. All wells drilled for the purpose of oil/gas production (or injecting materials into underground formations) must be cased with material with sufficient strength and functionality. Therefore, this chapter provides the basic knowledge for practical casing and tubing strength evaluation and design. Casing is the major structural component of a well. Casing is needed to maintain borehole stability, prevent contamination of water sands, isolate water from producing formations, and control well pressures during drilling, production, and workover operations. Casing provides locations for the installation of blowout preventers, wellhead equipment, production packers, and production tubing. The cost of casing is a major part of the overall well cost, so selection of casing size, grade, connectors, and setting depth is a primary engineering and economic consideration. Tubing is the conduit through which oil and gas are ...

The first design task in preparing the well plan is selecting depths that the casing will be run and cemented. The program results should allow the well to be drilled safely without the necessity of building "a steel monument" of casing strings. Unfortunately, many well plans give significant considerations to the actual pipe design, yet give only cursory attention to the pipe setting depth. The importance of selecting proper depths for setting casing cannot be overemphasized. Many wells have been engineering or economic failures because the casing program specified setting depths too shallow or deep. Applying a few basic drilling principles combined with a basic knowledge of the geological conditions in an area can help determine where casing strings should be set to ensure that drilling can proceed with minimum difficulty. Drilling environments often require several casing strings to reach the total desired depth. Figure 1 shows the relationship of some of these strings.

Well planning is perhaps the most demanding aspect of drilling engineering. It requires the integration of engineering principles, corporate or personal philosophies, and experience factors. Although well planning methods and practices may vary within the drilling industry, the end result should be a safely drilled, minimum-cost hole that satisfies the reservoir engineer '

When one or more warning signs of kicks are observed, steps should be taken to shut in the well. If there is any doubt that the well is flowing, shut it in and check the pressures. It is important to remember that there is no difference between a small-flow well and a full-flowing well, because both can very quickly turn into a big blowout. In the past, there has been some hesitation to close in a flowing well because of the possibility of sticking the pipe. It can be proven that, for common types of pipe sticking (e.g., differential pressure, heaving, or sloughing shale), it is better to close in the well quickly, reduce the kick influx, and, thereby, reduce the chances of pipe sticking.

The latitude/longitude mapping system is widely used worldwide, except in the United States. This approach is more orderly and easily allows the wells to be located in relation to other known wells or landmarks. The "lat/long" system is now being introduced in the United States in conjunction with the township/range scheme. Selecting offset wells to be used in data collection is important. Using Figure 1 as an example, assume that a 13,000-ft prospect is to be drilled in the northeast corner of Section 30, T18S, R15E. The best candidates for offset analyses are shown in Table 1. Although these wells were selected for control analysis, available data from any well in the area should be analyzed.

Coiled-tubing drilling (CTD) can be very effective in certain situations. Its application is growing as experience defines what it takes to be successful. Coiled-tubing drilling (CTD) has a rather extensive history and received a large amount of press and hype from the 1990s to date, a significant amount being less than positive. There have been numerous highly successful applications of CTD technology in such regions as Alaska and the United Arab Emirates, yet CTD is still considered an immature new technology. One example of exaggerated expectations is CTD's reputation for offering certain advantages, including small footprint, high mobility, and quick operations. However, when more complex CTD services are planned, including directional drilling and cased completions, these advantages may no longer apply. These materials are typically not required for conventional CT services. When including the additional separators and nitrogen-pumping equipment required for underbalanced drilling (UBD), the advantages related to small footprint and high mobility may no longer be the case. Numerous truckloads of equipment can take days to rig up in preparation to drill with CT. Figure 1 shows a purpose-built CTD rig working in Oman.