CHAPTER 2 BASIC OPERATIONAL ENGINEERING

• Jurisdiction: United States

Basic Oil and Gas Technology for Lawyers and Landmen
(Apr 1979)
CHAPTER 2
BASIC OPERATIONAL ENGINEERING
Jerry R. Bergeson
Jerry R. Bergeson & Associates
Golden, Colorado

DRILLING

The culmination of the surface and subsurface interpretations performed by the geologists and geophysicist is the drilling of a borehole. The only method to test (and if successful produce) potentially hydrocarbon bearing formations is to mechanically drill a hole to the predetermined objective.

A borehole, like other industrial endeavors, undergoes engineering design, logistical planning, and budgeting before the project is begun. The borehole can be considered the product of a mobile manufacturing plant; the plant consisting of the drilling rig and the associated peripheral and support groups.

Through the years, drilling has become an engineering discipline in and unto itself. Current drilling practices are fairly sophisticated but they are all based on simple concepts. This discussion will concern itself with the basic practices utilized while drilling a borehole. As a necessary consequence of this, the various drilling rig components and well bore components will also be discussed.

The drilling rig is the nucleus of the drilling operation. Figure 1 is a schematic drawing of a drilling rig. The drilling rig provides a means for:

1. Raising and lowering of equipment in and out of the wellbore.

2. Applying torsional force to the drill bit.

3. Circulating drilling fluid.

4. Controlling the influx of subsurface fluids.

The various rig components are shown on Figure 1. A description of these components can be found in the glossary which is attached.

Certain items are common to almost all drilling operations. These will be discussed briefly in the ensuing paragraphs.

Surfacehole and Surface Casing: A wellbore is begun by drilling at the surface. Typically a large diameter hole (12 1/4"—36") is drilled to a depth at which surface casing is set. Surface casing is steel pipe that is run into the surface hole and cemented in place. The depth at which surface casing is set is determined by engineering design in conjunction with statuatory requirements. The function of surface casing is basically twofold; first to protect rear surface aquifers from contamination by drilling fluids or produced fluids and, secondly to provide a conductor whose strength is adequate to control pressures induced by the influx of formation fluids encountered while drilling deeper.

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The surface casing is cemented from the bottom to the top of the hole. This simply means that the annular volume between the surface casing and the surface hole is filled with cement. This is accomplished by pumping a cement slurry down through the surface casing and displacing it with water (or mud) up around the surface casing.

Surface casing is the first of potentially several casing strings that may be used in a given wellbore. Because the last casing string that is run dictates the size of all ensuing equipment that can be run into the hole, special attention must be given to casing and hole size design.

Drilling in some areas requires the use of intermediate (protection) casing. This casing string is run and cemented before the deepest objective is reached. Intermediate casing may be used for a variety of reasons some of which are listed below:

1. To provide conductor of greater length and strength than that which is afforded by the surface casing.

2. To eliminate the hole caving in from above.

3. To eliminate "lost circulation".

4. To isolate intervals of different formation pressure gradients.

5. To facilitate changing from one drilling fluid to another (i.e. mud to air, water-base mud to oil-base mud).

A short string of casing that is run only from the bottom of the hole up into the last full string of casing is called a liner. A liner serves the same purpose as a full basing string but is more economical than a full string of casing and is often sufficient to fill the requirements imposed. If the well is capable of commercial production a final string of casing is run which is called production casing. Figure 2 is a drawing which depicts the various casing strings discussed.

As has been mentioned previously, the drilling rig equipment is designed to control the influx of formation fluids. The influx of these fluids while drilling is called a "kick" and if the "kick" is not controlled a "blowout" can result. A blowout preventor (BOP stack is attached to the surface casing or the intermediate casing, if used. The BOP stack is a series of hydraulically controlled valves that are used to shut the hole in at the surface. The BOP stack is typically made up of five major constituents. These are:

1. Blind Rams: A valve which will close and shut the hole in when the drill string is out of the hole.

2. Pipe Rams: A valve which will close around the drill pipe and will shut the well in.

3. Annular BOP a "balloon" that will seal around drill pipe, the kelly or drill collars. The drill string can be moved when this BOP is closed and cannot be when either the pipe rams or blind rams are closed.

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4. Choke and Kill System: Provides a means to control the flow of the "kick" fluid from the wellbore and to kill the kick by pumping down the annulus.

5. Accumulator and Central System: Provides a means hydraulically to operate (i.e. open-close) the BOP stack components as well as operate the choke and kill system.

Figure 3 is a drawing which shows the aforedescribed BOP components.

The only reason formation fluids flow into the wellbore is that the hydrostatic pressure exerted by the drilling fluid is less than the formation fluid pressure. For this reason it is necessary to use a drilling fluid of sufficient density to prohibit the influx of formation fluids in most drilling applications. The control of subsurface pressure is one of several functions of a drilling fluid (mud) system.

Drilling mud is a slurry typically made up of bentonite (gel), barite (Barium Sulfate), chemical additives, and water. Some of the functions of drilling mud are listed below:

1. Remove drill cuttings and sloughed material.

2. Cool and lubricate the bit and drill string.

3. Control subsurface pressure.

4. Stabelize the borehole.

5. Transmit hydraulic horse power from mud pumps to bit for maximum rate of penetration.

6. Minimize corrosion of drill string and other equipment in contact with drilling fluid.

Figure 4 is a drawing which shows the major components of a mud system.

Throughout the previous discussion it has been assumed that the borehole is vertical and therefore the location of the bottom of the hole is directly beneath the surface location. Unfortunately no borehole is perfectly vertical, and if the bottom hole location is the same as the surface location it is in most instances purely coincidental.

For many reasons it is desirable to know what the bottom hole location of a borehole is. Most states have spacing requirements that dictate the allowable distance a well can be located from a lease or spacing unit line. If these spacing rules are violated correlative rights may be construed to be violated. If the bottom hole location of a well is off the lease entirely (or across a spacing unit boundary line) serious consequences would be precipitated.

At times, however, it may be desirable to have the bottom hole location a significant distance from the surface location. One obvious

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example of this is the drilling of several wells from one offshore platform. To accomplish this end, not only must the bottom hole location (location of the bit while drilling) be known at all times but a method to "steer" the bit must be available.

This is the practice of directional drilling. Down hole surveying tools that consist of compasses and plumb-bobs are used to determine the bottom hole location at any point in the borehole. Steering tools that utilize "bent subs", "downhole motors", "stabelizers" and other equipment are used to control the direction and the angle (from vertical) of the hole. It is routinely possible to hit a bottom hole target of less than 50 ft. in diameter and to determine the bottom hole location with an accuracy of 1 ft.

Once the hole is nearing an anticipated productive horizon, the predetermined methods of evaluating this zone must be considered. One method that is used to (in part) evaluate the subject zone is coring and core analysis. A core is nothing more than a continuous sample of the zone in question of sufficient size to permit quantitative laboratory measurements. A core is cut using a bit similar in appearance to the diamond but shown on Figure 5 which depicts the various types of drilling bits used today. Typically core bits or core heads as they are referred to are diamond bits in as much as "roller" core heads do not cut a uniform core sample and jam much easier than diamond core heads. Figure 6 shows a diamond core head. Immediately above the core head is the core barrel in which the core is pushed as it is cut. The core barrel is typically made up of 30 ft. sections and usually 60 ft. (two barrel sections) is the longest core barrel that is used.

The well site geologist identifies the core point (the depth at which the core assembly is run) by the examination of the drill cuttings, monitoring the rate of penetration and by other numerous means. The core point is usually the top of the potentially hydrocarbon bearing zone.

The core assembly is run and a core is cut to the depth at which the core barrel is full or the core barrel jams (or some other extraneous circumstance requires the ceasing of the coring operation). The core assembly is "tripped" out of the hole and the core is laid down. It is measured and its length is reported as compared to the amount of core cut. The core is marked as to depth and a brief description is recorded by...