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Wednesday, June 30, 2010

Rotary Drilling

Rotary drilling uses a sharp, rotating drill bit to dig down through the Earth's crust. Much like a common hand held drill, the spinning of the drill bit allows for penetration of even the hardest rock. The idea of using a rotary drill bit is not new. In fact, archeological records show that as early as 3000 B.C., the Egyptians may have been using a similar technique. Leonardo Da Vinci, as early as 1500, developed a design for a rotary drilling mechanism that bears much resemblance to technology used today. Despite these precursors, rotary drilling did not rise in use or popularity until the early 1900's. Although rotary drilling techniques had been patented as early as 1833, most of these early attempts at rotary drilling consisted of little more than a mule, attached to a drilling device, walking in a circle! It was the success of the efforts of Captain Anthony Lucas and Patillo Higgins in drilling their 1901 'Spindletop' well in Texas that catapulted rotary drilling to the forefront of petroleum drilling technology.
While the concept for rotary drilling - using a sharp, spinning drill bit to delve into rock - is quite simple, the actual mechanics of modern rigs are quite complicated. In addition, technology advances so rapidly that new innovations are being introduced constantly. The basic rotary drilling system consists of four groups of components. The prime movers, hoisting equipment, rotating equipment, and circulating equipment all combine to make rotary drilling possible.
Prime Movers
The prime movers in a rotary drilling rig are those pieces of equipment that provide the power to the entire rig. Up until World War II, rotary rigs were traditionally powered by steam engines. Diesel engines became the norm after the war. Recently, while diesel engines still compose the majority of power sources on rotary rigs, other types of engines are also in use. Natural gas or gasoline engines are commonly used, as are natural gas or gasoline powered reciprocating turbines, which generate electricity on site. The resulting electricity is used to power the rig itself. Other rotary rigs may use electricity directly from power lines. Most rotary rigs these days require 1,000 to 3,000 horsepower, while shallow drilling rigs may require as little as 500 horsepower. Rotary rigs designed to drill in excess of 20,000 feet below surface may require much more than 3,000 horsepower. The energy from these prime movers is used to power the rotary equipment, the hoisting equipment, and the circulating equipment, as well as incidental lighting, water, and compression requirements not associated directly with drilling.
Working on an Onshore Drilling Rig
Source: Anadarko Petroleum Corporation
Hoisting Equipment
The hoisting equipment on a rotary rig consists of the tools used to raise and lower whatever other equipment may go into or come out of the well. The most visible part of the hoisting equipment is the derrick, the tall tower-like structure that extends vertically from the well hole. This structure serves as a support for the cables (drilling lines) and pulleys (draw works) that serve to lower or raise the equipment in the well. For instance, in rotary drilling, the wells are dug with long strings of pipe (drillpipe) extending from the surface down to the drill bit. If a drill bit needs to be changed, either due to wear and tear or a change in the subsurface rock, the whole string of pipe must be raised to the surface. In deep wells, the combined weight of the drillpipe, drill bit, and drill collars (thicker drillpipe located just above the bit) may be in excess of thousands of pounds. The hoisting equipment is used to raise all of this equipment to the surface so that the drill bit may be replaced, at which point the entire chain of drillpipe is lowered back into the well.
Positioning the Hoisting Equipment
Source: Anadarko Petroleum Corporation
The height of a rigs derrick can often be a clue as to the depth of the well being dug. Drillpipe traditionally comes in 30ft sections, which are joined together as the well is dug deeper and deeper. This means that even if a well is 20,000 feet deep, the drill string must still be taken out in 30 foot sections. However, if the derrick is tall enough, multiple joints of drillpipe may be removed at once, speeding up the process a great deal. Rotating Equipment
The rotating equipment on a rotary drilling rig consists of the components that actually serve to rotate the drill bit, which in turn digs the hole deeper and deeper into the ground. The rotating equipment consists of a number of different parts, all of which contribute to transferring power from the prime mover to the drill bit itself. The prime mover supplies power to the rotary, which is the device that turns the drillpipe, which in turn is attached to the drill bit. A component called the swivel, which is attached to the hoisting equipment, carries the entire weight of the drillstring, but allows it to rotate freely.
The drillpipe (which, when joined together, forms the drillstring) consists of 30ft sections of heavy steel pipe. The pipes are threaded so that they can interlock together. Drillpipe is manufactured to meet specifications laid out by the American Petroleum Institute (API), which allows for a certain degree of homogeneity for drillpipes across the industry. The drillpipe is a very heavy, strong pipe, but can be quite flexible when used in slant or horizontal drilling applications.
Below the drillpipe are drill collars, which are heavier, thicker, and stronger than normal drillpipe. The drill collars help to add weight to the drillstring, right above the bit, to ensure there is enough downward pressure to allow the bit to drill through hard rock. The number and nature of the drill collars on any particular rotary rig can be altered depending on the down hole conditions experienced while drilling.
Diamond Studded Drill Bits
Source: Sandia National Laboratory (left), DOE - National Energy Technology Laboratory
The drill bit is located at the bottom end of the drillstring, and is responsible for actually making contact with the subsurface layers, and drilling through them. The drill bit is responsible for breaking up and dislodging rock, sediment, and anything else that may be encountered while drilling. There are dozens of different drill bit types, each designed for different subsurface drilling conditions. Different rock layers experienced during drilling may require the use of different drill bits to achieve maximum drilling efficiency. It can be a long process to change bits, due to the fact that the whole drill string must be removed; but using the correct drill bit, or replacing a worn bit, can save a great deal of time during drilling. Drill bits are chosen given the underground formations expected to be encountered, the type of drilling used, whether or not directional drilling is needed, the expected temperatures underneath the Earth, and whether or not cores (for logging purposes) are required. There are four main types of drill bits, each suited for particular conditions.
  • Steel Tooth Rotary Bits are the most basic type of drill bit used today.
  • Insert Bits are steel tooth bits with tungsten carbide inserts.
  • Polycrystalline Diamond Compact Bits have polycrystalline diamond inserts attached to the carbide inserts found in Insert Bits.
  • Diamond Bits have industrial diamonds implanted in them, to drill through extremely hard rock formations. Diamond bits are forty to fifty times harder than traditional steel bits, and can thus be used to drill through extremely hard rock without dulling overly quickly.
In addition to these main types of drill bits, hybrid bits, combining the features of various types of bits, can be used. If core samples are required for logging purposes, core bits are designed to drill and obtain these samples. There are a great number of different designs for drill bits, including tricone roller bits, button bits, tapered bits, fishtail bits, and mill bits. Each of these bits has specifically designed drilling traits. The fishtail bit, for instance, is designed to enlarge the drill hole above the drill bit, and the mill bit is designed to mill away metal scraps or objects found in the well. The drill bit, in addition to being very useful, is also very expensive. It is thus up to the drilling engineer to ensure that the correct bit is used at the correct time, to allow for maximum drilling efficiency, with minimum wear and tear on the valuable bit.
Lowering the Bit and Drill Collar into the Well Hole
Source: NGSA
Circulating System
The final component of rotary drilling consists of the circulating system. There are a number of main objectives of this system, including cooling and lubricating the drill bit, controlling well pressure, removing debris and cuttings, and coating the walls of the well with a mud type-cake. The circulating system consists of drilling fluid, which is circulated down through the well hole throughout the drilling process.
Typically, liquid drilling fluids are used. The most common liquid drilling fluid, known as 'mud', may contain clay, chemicals, weighting materials, water, oil, or gases. 'Air drilling' is the practice of using gasses as the drilling fluid, rather than a liquid. Gases used include natural gas, air, or engine exhaust. Air drilling can significantly cut down on drilling time, as well as drilling fluid costs. The drilling fluid, much like the bit, is custom designed and chosen depending on what type of subsurface conditions are expected or experienced. For example, if drilling is occurring through underground salt formations, freshwater would not be used, as this would risk dissolving the subsurface salt. Similarly, if drilling near sources of fresh water, salt water would not be used for fear of contaminating the fresh water.
The drilling fluid chosen must have a number of properties to allow it to accomplish its tasks. It must be light and thin enough to circulate through the drill bit, cooling the bit as it drills as well as lubricating the moving parts. The fluid must be heavy enough to carry drill cuttings away from the bit and back to the surface, as well as control upward pressure that may be experienced in the well to prevent blowouts. The drilling fluid engineer ensures that the weight of the drilling fluid is greater than the upward pressure of escaping gas that may be encountered while drilling. In addition, the drilling fluid must be thick enough to coat the wellbore with a cake, which serves to temporarily seal the walls of the well until casing can be installed.
The circulating system consists of a starting point, the mud pit, where the drilling fluid ingredients are stored. Mixing takes place at the mud mixing hopper, from which the fluid is forced through pumps up to the swivel and down all the way through the drill pipe, emerging through the drill bit itself. From there, the drilling fluid circulates through the bit, picking up debris and drill cuttings, to be circulated back up the well, traveling between the drill string and the walls of the well (also called the 'annular space'). Once reaching the surface, the drilling fluid is filtered to recover the reusable fluid.
An Onshore Drilling Rig
Source: DOE - EREN
In addition to the fluid itself regulating downhole pressures encountered while drilling, a device known as the 'blowout preventer' is situated on the well casing below the deck of the rig. A blowout can occur when uncontrolled underground oil or gas pressure exerts more upward pressure than the drilling fluid itself can offset. The blowout preventer can consist of hydraulically powered devices that can seal off the well quickly and completely, preventing any potential for a well blowout should extreme downhole pressures be encountered. Pressure release systems are also installed to relieve the great pressure that can be experienced in a blowout situation.












Source

NaturalGas.org

1 comment:

  1. Indian feat in oil exploration:
    “‘Dig boy, dig’, shouted the Canadian engineer, Mr W L Lake, at his men as they watched elephants emerging out of the dense forest with oil stains on their feet”.[2] This is possibly the most distilled – though fanciful – version of the legend explaining the siting and naming of Digboi. Two events separated by seven years have become fused, but although neither is likely to be provable, such evidence that does exist appears sufficiently detailed to be credible.
    Various web sites offer variations on the elephant’s foot story, a consensus of which would be that engineers extending the Dibru-Sadiya railway line to Ledo for the Assam Railways and Trading Company (AR&TC) in 1882 were using elephants for haulage and noticed that the mud on one pachyderm’s feet smelled of oil. Retracing the trail of footprints, they found oil seeping to the surface. One of the engineers, the Englishman (not Canadian) William Lake (aka "Willie Leova" Lake), was an ‘oil enthusiast’ and persuaded the company to drill a well.
    Oil India Ltd makes no reference to elephants’ feet in its company history,[3] although on its previous web site the company noted that Lake had noticed “the oil seepages around Borbhil”. Once the project had been approved, Lake assembled equipment, boilers, and local labour, and engaged elephants to haul the machinery to the site. The first well was started in September 1889, but an encouraging first strike at 178 feet turned out to be a small pocket, and drilling recommenced. This continued until November 1890 when the well was completed at a total depth of 662 feet, and it was during this extended period of drilling that Oil India's old web site placed the legend of Lake exhorting one or more of his labourers to “Dig, boy!”

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