There are five major systems on a modern rotary drilling rig:
the Power System
the Hoisting System
the Circulation System
the Rotary System
the Well Control System (Blowout Prevention System)
The power system is the system is the system that provides all power to the rig. On a modern rotary rig, this power is generated with the Prime Mover which is an electrical generator that is fueled with either diesel fuel or lease fuel. The electrical power is transmitted to the other systems and sub-systems on the rig by mechanical means (older rigs), direct current (DC), or alternating current (AC).
The hoisting system is the system that does the heavy lifting on the rig. It is responsible for lifting drill pipe during tripping operations; and lifting and suspending the drill pipe during drilling operations, and lifting and installing the casing, tubing strings, and completion equipment into the well. In addition, the braking system on the hoisting system controls the weight-on-bit by taking up some of the load of the drill pipe.
The circulation system of the drilling rig is responsible for circulating the drilling fluid from the mud pit to the drill bit and back. It is a continuous system of pumps, distribution lines, storage tanks, storage pits, and cleansing units that allows the drilling fluid to fulfill its primary objectives (these will be discussed later in this lesson). The main sub-systems of the circulation system are:
the mud pit
the mud pump
the drill string
the solids control system:
the shale shaker
The drilling fluid itself is most often called mud. The drilling fluids discussed in these lesson notes are:
water-based muds (WBM): mixtures of water, bentonite clay, and additives;
oil-based muds (OBM): mixtures of with diesel oil, mineral oil, or synthetic oils as a continuous phase and water as a dispersed phase in an emulsion. In addition, additives such as emulsifiers and gelling agents are also used;
foams: comparable to shaving cream; and
Drilling fluids are critical in modern drilling operations. There are many objectives for using a drilling fluid. These include:
lift drill cuttings from the bottom of the wellbore to the surface;
suspend cuttings to prevent them from falling downhole if circulation is temporarily ceased;
release the cuttings when they are brought to the surface;
stabilize the borehole during drilling operations (exert hydrostatic or hydrodynamic pressure on the borehole to prevent rock caving into the wellbore);
control formation pore pressures to assure desired well control (apply hydrostatic and hydrodynamic pressures in excess of the formation pore pressures to prevent fluids from entering the wellbore);
deposit an impermeable filter cake onto the wellbore walls to further prevent fluids from permeable formations from entering the wellbore;
minimize reservoir damage (assure low skin values) when drilling through the reservoir section of the well;
cool the drill bit during drilling operations;
lubricate the drill bit during drilling operations;
allow for pressure signals from Logging While Drilling (LWD) or Measurement While Drilling (MWD) tools to be transmitted to the surface (LWD and MWD data are transmitted to the surface using pressure pulses in the drilling fluid);
allow for pressure signals to be sent to the bottom of the well to pressure actuate certain downhole equipment;
minimize environmental impact on subsurface natural aquifers.
The rotary system of the drilling rig provides the torque for the drilling process. This torque is provided by the rotary table on a conventional rotatory rig or the top-drive unit on a top-drive rotary rig. This torque is conveyed through the drill pipe and the bottom-hole assembly to the drill bit.
The lesson notes discussed three types of drill bits used on the drilling industry:
milled-tooth tri-cone bit
insert tri-cone bit
The drilling action of the tri-cone bits is due to an explosive gouging, crushing action; while the drilling action of the fixed-cutter bits are due to a scraping action.
In a milled-tooth tri-cone bit, the teeth of the bit are milled from the same steel as the cone. Due to the grade of the steel used in the cones, the milled-tooth bits are typically used to drill through soft rock formations.
In an insert tri-cone bit, the teeth inserts are made from stronger grades of steel than the cone. Typically, tungsten-carbide steel is used to create the teeth in an insert bit. The insert bits are used to drill through moderately hard formations or to extend the bit-life through soft formations.
Fixed-cutter bits are bits that contain no moving parts. The cutters on fixed-cutter bits are typically polycrystalline (synthetic) diamonds which are used to form polycrystalline diamonds compact (PDC) bits. PDC bits are used to drill through hard rock formations.
The Well Control System or the Blowout Prevention System is the system on a drilling rig that prevents the uncontrolled, catastrophic release of high-pressure fluids (oil, gas, or salt water) from subsurface formations. The well control system is comprised of:
the Accumulator: stores compressed gas and compressed hydraulic fluids for the rig’s hydraulic systems;
the Blowout Preventer: large stacked system of high-pressure valves that can be closed around or through drill pipe to isolate the subsurface formations from the rig.
The well control system provides well control by:
mud system: helps prevent kicks by exerting high hydrostatic and hydrodynamic pressures on the formations and depositing an impermeable mud cake across permeable formations;
blowout preventer (BOP): helps to control a kick if one occurs.
A kick is an unwanted but controllable entry of subsurface fluids into the wellbore; while a blowout is a catastrophic (usually) and uncontrollable entry of subsurface fluids into the wellbore. Blowouts can be catastrophic because of the combustible nature of hydrocarbons.
The causes of a kick include:
insufficient mud weight (density): the hydrostatic or hydrodynamic pressure exerted by the mud column is less than the formation pore pressure (the pressure is underbalanced);
improper mud replacement during tripping: while tripping out of the hole mud volumes must be pumped into the wellbore at high enough rates to replace drill pipe being removed from the wellbore;
swabbing: removing drill pipe from the wellbore can create a negative pressure (suction) if the drill pipe is removed too quickly;
cut mud: if gas is entering the wellbore, then it may effectively reduce the wellbore pressure gradient;
lost circulation: as discussed earlier if large volumes of drilling fluid enter the subsurface in (1) high permeability formations, natural fractures, or drilling-induced fractures, then the effect is a shortened height and weight of the mud column.
The indicators/warning signs of a kick include:
increase in the rate of flow of the drilling fluid returns at constant pump rates (primary indicator of a kick);
volume of mud in the mud pit increases when no additional drilling fluids are added to the mud system (primary indicator of a kick);
drilling fluids returns continue to flow when the mud pumps are turned off (primary indicator of a kick);
improper wellbore fill-up/volume-balance on trips (primary indicator of a kick);
pump pressure decrease and pump stroke increase (secondary indicator of a kick);
change in the apparent weight-on-bit (secondary indicator of a kick);
occurrence of a Drill Break or Bit Drop (secondary indicator of a kick);
reduction in the mud weight (secondary indicator of a kick).
The drilling company and operating company will always have a detailed, well-specific procedure in place in the advent of a kick.
All wells are drilled with a set sequence of operations.