Rotary Drilling General Method and Equipment

5.1 Introduction and Basic Operations

The rotary drilling method is comparatively new, having first been practiced by Leschot, a French civil engineer, in 1863. United States patents on rotary equipment were issued as early as 1866 but, as was the case with cable tools, the early application was for water well drilling. It was not until approximately 1900 that two water well drilling contractors, M. C. and C. E. Baker, moved their rotary equipment from South Dakota to Corsicana, Texas where it found use in the soft rock drilling of that area.1 In Texas in 1901 Captain Lucas drilled the Spindletop discovery well with rotary tools. This spectacular discovery is credited with initiating both the Southwest's oil industry and the widespread use of the rotary method. The inherent advantages of this method in the soft rock areas of Texas and California insured its acceptance, and it was in general use by the early 1920's. It is interesting to note that in the 1914-18 period, cable tools drilled 90% of all U.S. wells. At the present time these figures are approximately reversed.

In the rotary method, the hole is drilled by a rotating bit to which a downward force is applied. The bit is fastened to, and rotated by, a drill string, composed of high quality drill pipe and drill collars, with new sections or joints being added as drilling progresses. The cuttings are lifted from the hole by the drilling fluid which is continuously circulated down the inside of the drill string through water courses or nozzles in the bit, and upward in the annular space between the drill pipe and the bore hole. At the surface, the returning fluid (mud) is diverted through a series of tanks or pits which afford a sufficient quiescent period to allow cutting separation and any necessary treating. In the last of these pits the mud is picked up by the pump suction and repeats the cycle. Figure 5.1 shows the basic components of a rotary drilling rig.

Making a connection, the process of adding a new joint of pipe to the drill string is shown in Figure 5.2. Periodically the pipe must be removed from the hole in order to replace the bit. This operation is illustrated in Figure 5.3. Here the pipe is pulled in stands of four joints each. Only two or three joints per stand will be pulled when using shorter derricks or masts.

The truck mounted rig shown in Figure 5.4 serves to illustrate the high degree of portability which has been attained by equipment manufacturers. This particular rig is designed for slim hole drilling to depths of 10,000 feet. "Slim hole drilling" refers to operations in which the hole size is smaller than usual.

5.2 Basic Rig Components

Rotary drilling equipment is complex and any detailed discussion would of necessity involve intricate mechanical design problems. Since petroleum engineers, for whom this book is designed, are normally neither required nor qualified to solve these problems, this chapter will stress the jobs to be performed rather than the equipment itself. To do this we will consider only the basic rig components in the following order:

  1. Derricks, masts, and substructures
  2. Draw works
  3. Mud pumps
  4. Prime movers

Bit, Rock

(1)

Hook, Rotary

(14)

Block, Crown

(2)

Hose, Rotary

(15)

Block, Traveling

(3)

Kelly

(16)

Boiler

(4)

Line, Drilling

(17)

Bushing, Drive

(5)

Mud Pit

(18)

Cathead

(6)

Platform, Engine

(19)

Derrick

(7)

Pump, Slush

(20)

Draw works

(8)

Rotary Table

(21)

Drill CoUar

(9)

Shale Shaker

(22)

Drill Pipe

(10)

Stand Pipe

(23)

Elevators

(11)

Stop Cock, Kelly

(24)

Engine

(12)

Substructure

(25)

Flow Line, Mud

(13)

Swivel

(26)

Tongs

(27)

Drill String And Bit

Fig. 5.1. Basic components of a rotary drilling rig. Courtesy API.

Standard Derricks

5. The drill string

6. Bits

  1. Drilling line
  2. Miscellaneous and auxiliary equipment 5.21 Derricks, Masts, and Substructures

The function of a derrick is to provide the vertical clearance necessary to the raising and lowering of the drill string into and out of the hole during the drilling operations. It must be of sufficient height and strength to perform these duties in a safe and expedient manner. Derricks are of two general types, standard and portable.

Fig. 5.1. Basic components of a rotary drilling rig. Courtesy API.

Standard Derricks

A standard derrick cannot be raised to a working position as a unit, i.e., it is of bolted construction and must be assembled part by part. Likewise, it must be disassembled if it is to be transported. Exceptions to this are those relatively short moves in which the entire rig is skidded to a nearby location. Detailed specifications for the nine API standard derricks may be found in the API Std. ^A.2

Derricks are rated according to their ability to withstand two types of loading:

  • 1) Compressive loads
  • 2) Wind loads
Block And Tackle Drawwork

Fig. 5.2. Sequence of events during "mouse hole connections." Courtesy The Ohio Oil

Company.

Fig. 5.2. Sequence of events during "mouse hole connections." Courtesy The Ohio Oil

Company.

The allowable compressive load of a derrick is computed as the sum of the strengths of the four legs. In these calculations, each leg is treated as a separate column and its strength computed at the weakest section. This load, (excluding the weight of the derrick) with its safety factor of 2, is the API safe load capacity. Capacities for reinforced derricks are computed in a similar manner by the formulae of API Std. 4B. Derricks with load capacities from approximately 86,000 to 1,400,000 lb, depending on steel grade and leg size, are available.

Allowable wind loads for API derricks are specified in two ways, with or without pipe setback. For the drill pipe to stand vertically stable during a trip, the tops of the stands must lean outward against the fingers at the pipe racking platform. This results in an overturning moment applied to the derrick at that point. If the wind is blowing perpendicular to the setback, which is essentially a pipe wall, a further overturning moment is applied. This is the worst possible condition, i.e., wind and setback loads acting in the same direction. The minimum allowable wind loads for 136 ft and shorter derricks is 11.76 lbs/ft2 (54 mph) with pipe setback. Minimum wind loads for taller derricks are 22.50 lbs/ft2 (75 mph) with setback and 52.90 lbs/ft2 (115 mph)

without setback. Wind loads are calculated by the formula:

where p = wind load, lb/ft2

V = wind velocity, mph

Calculation of Derrick Loads

The block and tackle arrangement for a rotary rig is shown schematically in Figure 5.5. If we assume the system as frictionless, the following relationships are apparent:

where Fd = total compressive load on the derrick n = number of lines through the travelling block (those supporting W)

Hence it is seen that the derrick load is always greater than the hook load by the factor (n + 2)/n due to the two additional lines (drawworks and anchor) exerting downward pull. Further it may be noted that during hoisting:

Block Tackle Calculations
+1 0

Responses

  • kristian
    Why is rotary drilling is of widespread?
    2 years ago

Post a comment