Shale shakers Suction line

Bottom hole assembly (BHA)[edit]

The Bottom Hole Assembly (BHA) is made up of: a drill bit, which is used to break up the rock formations; drill collars, which are heavy, thick-walled tubes used to apply weight to the drill bit; and drilling stabilizers, which keep the assembly centered in the hole. The BHA may also contain other components such as a downhole motor and rotary steerable system(RSS), measurement while drilling (MWD), and logging while drilling (LWD) tools. The components are joined together using rugged threaded connections. Short "subs" are used to connect items with dissimilar threads.

Transition pipe[edit]

Heavyweight drill pipe (HWDP) may be used to make the transition between the drill collars and drill pipe. The function of the HWDP is to provide a flexible transition between the drill collars and the drill pipe. This helps to reduce the number of fatigue failures seen directly above the BHA. A secondary use of HWDP is to add additional weight to the drill bit. HWDP is most often used as weight on bit in deviated wells. The HWDP may be directly above the collars in the angled section of the well, or the HWDP may be found before the kick off point in a shallower section of the well.

Drill pipe[edit]

Drill pipe makes up the majority of the drill string back up to the surface. Each drill pipe comprises a long tubular section with a specified outside diameter (e.g. 3 1/2 inch, 4 inch, 5 inch, 5 1/2 inch, 5 7/8 inch, 6 5/8 inch). At each end of the drill pipe tubular, larger-diameter portions called the tool joints are located. One end of the drill pipe has a male ("pin") connection whilst the other has a female ("box") connection. The tool joint connections are threaded which allows for the mating of each drill pipe segment to the next segment.
Stuck drill string[edit]
A stuck drill string can be caused by many situations.

• 
  Packing-off due to cuttings settling back into the wellbore when circulation is stopped.
  
• 
  Differentially when there is a large difference between formation pressure and wellbore pressure. The drill string is pushed against one side of the well bore. The force required to pull the string along the wellbore in this occurrence is a function of the total contact surface area, the pressure difference and the friction factor.
  
• 
  Keyhole sticking occurs mechanically as a result of pulling up into doglegs when tripping.
  
• 
  Adhesion due to not moving it for a significant amount of time.
  

Once the tubular member is stuck, there are many techniques used to extract the pipe. The tools and expertise are normally supplied by an oilfield service company. Two popular tools and techniques are the oilfield jar and the surface resonant vibrator. Below is a history of these tools along with how they operate.



4 Drilling Bits
In the oil and gas industry, a drill bit is a tool designed to produce a generally cylindrical hole (wellbore) in the earth’s crust by the rotary drilling method for the discovery and extraction of hydrocarbons such as crude oil and natural gas. This type of tool is alternately referred to as a rock bit, or simply a bit. The hole diameter produced by drill bits is quite small, from about 3.5 inches (8.9 cm) to 30 inches (76 cm), compared to the depth of the hole, which can range from 1,000 feet (300 m) to more than 30,000 feet (9,100 m). Subsurface formations are broken apart mechanically by cutting elements of the bit by scraping, grinding or localized compressive fracturing. The cuttings produced by the bit are most typically removed from the wellbore and continuously returned to the surface by the method of direct circulation.
Drill bits are broadly classified into two main types according to their primary cutting mechanism. Rolling cutter bits drill largely by fracturing or crushing the formation with "tooth"-shaped cutting elements on two or more cone-shaped elements that roll across the face of the borehole as the bit is rotated. Fixed cutter bits employ a set of blades with very hard cutting elements, most commonly natural or synthetic diamond, to remove material by scraping or grinding action as the bit is rotated.
Modern commercial rolling cutter bits usually employ three cones to contain the cutting elements, although two cone or (rarely) four cone arrangements are sometimes seen. These bits mainly fall into two classes depending on the manufacture of the cutting elements or "teeth". Steel-tooth bits have cones that have wedge-shaped teeth milled directly in the cone steel itself. Extremely hard tungsten carbide material is often applied to the surfaces of the teeth by a welding process to improve durability. Tungsten carbide insert (TCI) bits have shaped teeth of sintered tungsten carbide press-fit into drilled holes in the cones. Some types of steel-tooth bits also have TCI elements in addition to the milled teeth. The cones rotate on roller or journal bearings that are usually sealed from the hostile down-hole drilling fluid environment by different arrangements of o-ring or metal face seals. These bits usually also have pressure compensated grease lubrication systems for the bearings.
The first commercially successful rolling cutter drill bit design was disclosed in U.S. patents granted to Howard R. Hughes, Sr. on August 10, 1909, and which led to the creation of what became the Hughes Tool Company. This bit employed two conical steel rolling elements with milled teeth that engaged the formation, when the device was rotated, to produce the cutting action. This design represented a significant improvement in drilling performance over the so-called "fish tail" scraper type bits commonly used in rotary drilling at the time, and over the next two decades, rotary drilling with rolling cutter bits largely replaced all other drilling methods in the oilfield. The significance of the Hughes Two-Cone Drill Bit was recognized on its 100th anniversary when it was designated a Historic Mechanical Engineering Landmark by the American Society of Mechanical Engineers.
Fixed cutter bits were the first type of drill bit employed in rotary drilling, and they are mechanically much simpler than rolling cutter bits. The cutting elements do not move relative to the bit; there is no need for bearings or lubrication. The most common cutting element in use today is the polycrystalline diamond cutter (PDC), a sintered tungsten carbide cylinder with one flat surface coated with a synthetic diamond material. The cutters are arranged on the blades of the bit in a staggered pattern with the diamond coated cutter surface facing the direction of bit rotation to provide full coverage of the borehole bottom. Other fixed cutter bits may employ natural industrial-grade diamonds or thermal stable polycrystalline diamond (TSP) cutting elements.
There is also currently available, a hybrid type of bit that combines both rolling cutter and fixed cutter elements.