In this lesson, we will continue discussing the drilling of oil and gas wells. In particular, we will discusst the major systems and sub-systems of modern rotary drilling rigs including their roles in the drilling process.
By the end of this lesson, you should be able to:
To Read | Read the Lesson 9 online material | Click the Introduction link below to continue reading the Lesson 9 material |
---|---|---|
To Do | Lesson 9 Quiz | Take the Lesson 9 Quiz in Canvas |
Please refer to the Calendar in Canvas for specific time frames and due dates.
If you have questions, please feel free to post them to the Course Q&A Discussion Board in Canvas. While you are there, feel free to post your own responses if you, too, are able to help a classmate.
In the last lesson, we learned about Rig Contracts, the Rig Crew, and Different Drilling Rigs. In this lesson, we will continue our discussions of the drilling rig and start a discussion on the drilling process. In Lesson 8, we saw that there are different onshore and offshore drilling rigs. While these rigs have different applications and there are pros and cons for each, there are many similarities. We will continue our discussion on drilling rigs with these similarities.
While there are different types of drilling rigs, these rigs obviously share many similarities since the tasks that they perform are identical. In particular, all modern hydrocarbon rotary rigs contain five main systems. These systems are:
These systems are shown in Figure 9.01. In addition, Figure 9.02 shows a more detailed schematic diagram of a rotary table, land rig.
|
|
|
Source: Serintel: Oil and Gas Portal - Drilling Technologies [1] |
The power system on a drilling rig provides the power for the other main systems on the rig and other ancillary systems, such as electrical systems, pumps, etc. The system typically consists of a prime mover (the component of the power system that generates the raw power) and a means to transmit the raw power to the end-use components on the rig.
In the detailed rig schematic (Figure 9.02a), the power system is comprised of:
Historically, coal was used to generate the power for drilling rigs; however, modern drilling rigs use other sources of fuel. Typically, modern rigs are now run using an internal combustion engine with diesel or lease fuel. Diesel oil is a petroleum-based fuel that is a product of the distillation process. If the rig is running in a developed field, then the field may have a small on-site refinery that is used to distill the diesel fuel. If the rig is drilling an exploration, appraisal, or delineation well, then the fuel will need to be delivered from an external source and stored on-site.
Lease fuel is typically produced natural gas. As we have learned, natural gas is always produced along with crude oil. Again, if the rig is drilling wells in a developed field, then the field may use the natural gas or Natural Gas Liquids (NGL) to fuel the prime mover. This natural gas may be processed to remove NGLs if a gas plant is available on site; may need to burn these hydrocarbon liquids (possible sales product) if a gas plant is unavailable; or may burn the processed NGLs (butane).
The transmission of the power can be:
In the mechanical transmission, power is generated with the prime mover and is transmitted to the end-use components by the application of chains and sprockets (similar to a bicycle), drive belts, drive shafts, etc. In a direct current (DC) electrical system, an internal combustion engine operates an electrical generator (in this case a DC generator) and the electrical energy is transmitted to the motors, electrical actuators, etc. Finally, in an alternating current (AC) electrical system, an internal combustion engine operates an electrical generator (in this case an AC generator) which is converted to DC with a silicon-controlled rectifier (SCR). AC-SCR power systems are the most widely used power systems on modern drilling rigs.
The hoisting system on a drilling rig does the heavy lifting on the rig. It is used to raise, lower, and suspend the drill string and lift casing and tubing for installation into the well.
In the detailed rig schematic (Figure 9.02b) the hoisting system is comprised of:
A schematic of the hoisting system is shown in Figure 9.03 for a kelly drive rig. In this figure, the derrick (or mast) provides the structural support for the hoist system. It must be capable of supporting the entire load on the system including the weight of the drill string (accounting for buoyancy effects) and any frictional forces.
The crown block and the traveling block form a Block and Tackle System on the rig. The drill line can be strung as pairs of 2 through 12 lines (six pairs). The greater the number of lines (and pulleys) in the block and tackle system, the greater its lifting power but at the expense of slower upward and downward movement of the system.
The drawworks of the hoisting system is a winch that reels the drilling line in or out causing the traveling block to move up or down. The drawworks is the component of the hoisting system that consumes energy from the power system. The drum on the drawworks is grooved to accommodate a specific size drilling line. Figure 9.04 shows a photo of an actual drawworks used on a drilling rig .
Not shown on the schematic or the photo is the braking system on the drawworks. Modern rigs use both a mechanical brake and an electromagnetic brake. The braking system is an integral part of the drilling process because it is used to control the Weight-on-Bit (WOB) during drilling. The two most important drilling parameters within the Driller‘s control to maximize the Rate of Penetration (ROP) are the weight-on-bit and the rotational speed of the rotary system in Revolutions per Minute (RPM).
The weight-on-bit is achieved with the weight of the drill pipe and Drill Collars, however the optimum weight-on-bit is often less than the total weight of the drill string. The brake is used to take up some of the weight of the drill string, so that the weight-on-bit is only a fraction of the total weight.
Also shown in Figure 9.03 is the Swivel. The swivel is the link that connects the hoisting system to the rotary system and to the circulation system. The function of the swivel is to:
The circulation system on the rig is the system that allows for circulation of the Drilling Fluid or Mud down through the hollow drill string and up through the annular space between the drill string and wellbore. 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 mud pumps of the circulation system and the drawworks of the hoisting systems are the two largest draws on the power from the power system
In the detailed rig schematic (Figure 9.02c), the circulation system is comprised of:
Drilling fluid is mixed in the mud pits and pumped by the mud pumps through the swivel, through the blow out preventer (not part of the circulation system) down the hollow drill pipe, through holes (Jet Nozzles) in the bit, up the annular space between drill pipe and wellbore (where it lifts the rock cuttings), to the surface, through the Solids Control Equipment (Shale Shaker, Desander, and Desilter), and back to the mud pits. A schematic of the circulation system is shown in Figure 9.05.
In this figure, fresh water-based drilling fluid (mud) is mixed with water from the Water Tank (not shown in Figure 9.05) and components from the Bulk Mud Components Storage (not shown in Figure 9.05) in the Mud Pit. The Mud Pumps then pump the mud through the swivel, kelly, kelly bushing, and rotary table down to the drill string.
The mud pumps on a typical drilling rig are either single-action or double-action Reciprocating (Positive Displacement) Pumps which may contain two pistons-cylinders (duplex pump) or three pistons-cylinders (triplex pump). Figure 9.06 shows schematics of a single piston-cylinder in (A) a single-action and (B) a double-action reciprocating pump.
In these pumps, the positive pressure and negative pressure (suction) in the cylinder cause the valves to open and close (note: the valves in the schematic are simple representations of the actual valves). Due to the high viscosity of the drilling fluid, the inlet side of the pump may require a Charge Pump to keep fluids moving into the cylinders at high pressures and to prevent Cavitation in the pump.
From the mud pumps, the drilling fluid goes to the swivel, through the blow out preventer, and down the hollow drill string and bottom-hole assembly. The drilling fluid then goes through jet nozzles in the drill bit; at which point, it begins its return to the surface. The drilling fluid travels up the annular space between the drill pipe and the wellbore, picking up and carrying the drill cuttings up the hole.
Once the drilling fluid reaches the surface, it goes through the mud return line to the gas-mud separator and the solids control equipment. The shale shaker is where the large cuttings from the returning drilling fluid are removed. The shale shaker is a set of vibrating mesh screens that allow the mud to pass through while filtering out cuttings of different size at screen screen mesh sizes. A Mudlogger or a Well-Site Geologist may be stationed at the shale shaker to analyze the cuttings to determine the lithology of the rock and the depth within the Stratigraphic Column at which the well is currently being drilled.
The drilling fluid then passes through the Desander and Desilter. These are hydrocyclones which use centrifugal forces to separate the smaller solids from the drilling fluid. The desander typically removes solids with a diameter in the range of 45 – 74 μm, while the desilter removes solids with a diameter in the range of 15 – 44 μm.
The drilling fluid is then sent through a degasser to remove any gas bubbles that have been picked up during the circulation. These gasses may include natural gas from the subsurface or air acquired during the solids control. Typically, the degasser is a piece of equipment that subjects the drilling fluid to slight vacuum to cause the gas to expand for extraction. The drilling fluid is then returned to the mud pit to start the circulation process over again.
We have discussed the mechanics of how the drilling fluid is circulated during the drilling process, but we have not discussed the role of the drilling fluid. The term “mud” is often used in oil and gas well drilling because historically the most common water-based drilling fluids were mixtures of water and finely ground, bentonite clays which, in fact, are muds.
There are many objectives for using a drilling fluid. These include:
As I stated earlier, historically drilling fluids were mixtures of bentonite clay, water, and certain additives to manipulate the properties of the mud (density, viscosity, fluid loss properties, gelling qualities, etc.). Today, there are several different options available for drilling fluids. These include:
Of the listed drilling fluids, the water-based muds and the oil-based muds are the most common; foam drilling and air drilling can only be used under specialized conditions. Of the two liquid based mud systems (water-based muds and oil-based muds), water-based muds are the most common mud system. They are more environmentally friendly and are used almost exclusively to drill the shallow portions of the well where fresh water aquifers exist to minimize any contamination to those aquifers. As this implies, drilling fluids can be – and often are – switched during the course of drilling operations in single well.
In addition, water-based muds are cheaper than oil-based muds, so they are used to reduce drilling costs and commonly represent the “default” selection for a drilling fluid. In other words, water-based muds are often used unless there is a specific reason to switch to an oil-based mud.
Oil-based muds are formulated 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. They were specifically developed to address certain drilling problems encountered with water-based muds. The reasons for using an oil-based mud include:
The first three bullet points in this list are becoming more common problems in the oil and gas industry. The shale boom in the U.S. has made long horizontal sections in shale reservoirs targets for drilling. In addition, deviated wells and deeper wells are also becoming more common. For these reasons, the use of oil-based muds is also becoming more common.
There are also several disadvantages with oil-based muds. These include:
Other drilling fluids currently in use that were listed earlier are foams and air. In the context of drilling fluids, foams have the consistency of shaving cream. Both foam and air drilling are used in hard rock regions, such as in the Rocky Mountains, where drill bits render the drill cuttings to dust. Thus, the foam or air only needs to lift this dust to the surface. Air drilling is always an environmentally friendly option if it is applicable because environmental contamination by air is never an issue.
The rotary system on a drilling rig is the system that causes the drill bit rotate at the bottom of wellbore. We have discussed some components of the rotary system when we discussed rotary table and top-drive rigs, but we have not yet discussed the entire system.
In the detailed rig schematic (Figure 9.02d), the rotary system is comprised of:
A schematic of the rotary system is shown in Figure 9.07. As we can see in Figure 9.07, the rotary system shares many components with the circulation system. This is because in the rotary system, these components rotate in support of causing the bit to rotate, while in the circulation system, these components act as conduits for the drilling fluid.
In Lesson 8, we saw that the rotary table imparted the torque for the drill string in a conventional rotary table rig, while the top-drive imparted this torque on a top-drive rig. We also saw that drill pipe was added to the drill string one joint at a time on a rotatory table rig, while a top-drive could add multiple joints of drill pipe during one connection operation.
The Bottom-Hole Assembly is comprised of any bottom hole equipment required to drill the current section of the well. A bottom-hole assembly may be as simple as a Drilling Collar. Drill collars are sections of heavy, thick walled pipe used to add weight-on-bit to the drill string. More complicated bottom-hole assemblies may include Jars, downhole directional steering and positioning equipment, logging-while-drilling, and measure-while-drilling equipment.
Jars are mechanical devices that deliver a transfer of kinetic energy to another piece of downhole equipment as the result of an impact. They are typically used to loosen a piece of downhole equipment with an impact (jarring action). You can think of a jar as comparable to a hammer used to loosen two boards that are nailed together by hitting one of the boards in the direction opposite of the head of the nail.
At the end of the drill string and bottom-hole assembly is the drill bit. There are many types of drill bits, but we will focus on two types of drilling bits, the Tri-Cone (or Roller Cone) Bit and Fixed-Cutter Bit. In addition, we will be discussing two variants of the tri-cone bit: the milled-tooth bit and the insert bit. All of these bits can be classified as in the following bullet list:
Tri-cone bits are the most common drilling bits and, historically, have been the workhorse of the drilling industry. As the name implies, tri-cone bits contain three cones, each of which contain cutting teeth.
The two-cone bit (an early version of the tri-cone bit) was invented by Howard Hughes Jr.’s father (Howard Sr.). The tri-cone bit and the formation of the Hughes Tool Co. (now part of Baker-Hughes, a subsidiary of the General Electric Corporation) was the source of the Hughes family wealth. In case you do not know who Howard Hughes Jr. was, he was an award winning pilot in the 1920s and 1930s (holder of several aerial speed records and subject of the movie “The Aviator”), a filmmaker (had controlling interest of RKO Studios and actively produced several notable silent and early “talkie” films), airplane designer (owner of Hughes Aircraft – contractor for the world’s largest wooden airplane, “The Spruce Goose,” with Howard as its only pilot in 1947), and a billionaire by the 1970s and 1980s (back when a billion dollars had some value).
In a milled-tooth bit, the teeth of the bit are machine-milled along with the rest of the cone. The cones of the tri-cone bit, including the teeth, are formed from a single, solid piece of steel. An example of a milled-tooth bit is shown in Figure 9.08.
In this figure, we can see that the teeth of the bit are intrinsic parts of the cones; they are milled from the same piece of steel. These bits, as do all tri-cone bits, drill through the rock by exerting the full weight-on-bit on only a few contact points (the sharpened teeth) between the bit and the rock. This exerts extremely high levels of stress at the contact points causing the rock to fail catastrophically (almost explosively). We will see this in a YouTube video later in the lesson.
One design feature of the tri-cone bit is the interaction of the teeth on the different cones helping to remove any small cuttings or sticky shales/clays (Gumbo Shales) that may get lodged between the teeth and reduce the efficiency of the bit. This phenomenon of cuttings and clays getting lodged between bit teeth is referred to as Bit Balling and results in slower Rates-of-Penetration (ROP) of the drilling process. The self-cleaning action of the teeth in a tri-cone bit is designed to reduce the bit balling.
Milled-tooth tri-cone bits are mainly used for drilling through soft rock formations. This is because, no matter how strong the steel used in the construction of the cone, hard rock can cause excessive wear and degradation of the teeth.
Insert drill bits, on the other hand, are bits in which the teeth are made from materials stronger than the steel used in the cone and are inserted into cone. Example of insert tri-cone bits are shown in Figure 9.09.
While the insert bit shown in Figure 9.09 may superficially look like the milled-tooth bit; careful inspection reveals that the teeth in the insert bit are not milled but are inserted into the cone. Typically, the teeth in an insert bit are made from tungsten-carbide steel (Tungsten Carbide Insert bit or TCI bit) which is a much stronger alloy of steel than the alloys used for the cones. Other design features included on insert bits include the length and the shape of the teeth (short, round-shaped teeth for hard rock formations or long, chisel-shaped teeth soft formations). These designs allow for a range of lithologies for these bits to be used: in hard rock formations that would be inappropriate for milled-tooth bits or in soft rock formations for extended bit-life.
While the insert bit helps to alleviate the issues with tooth-wear, there is an additional source of wear that can shorten the life of a drilling bit. Due to the moving parts associated with a tri-cone (or roller) bit, the bit requires a bearing where the moving parts meet and move past one another. Thus, the wear on the bearings may also shorten the life of the bit.
Fixed cutter bits are bits that do not contain any moving parts. These bits are designed to drill by shearing and scraping the rock formations as opposed to the gouging action used by a tri-cone bit. These bits typically use industrially made diamonds for the teeth and are also known as Polycrystalline Diamond Compact (PDC) bits. Figure 9.10 shows an example of a PDC bit.
The PDC bits are used to drill through very hard rock formations or for extended bit-life drilling. These bits have a large initial cost but because of the hard teeth and lack of any moving parts have a longer bit-life. One recent innovation for PDC bits in geologic basins with many shallow (short-footage) drill sites is the ability to rent the drill bit from the drilling company rather than to purchase it from a tool company. This innovation allows for an operating company to rent the bit and to use it for the footage that they require before relinquishing it to another operating company.
We have discussed that the tri-cone bits and the fixed cutter bits have different drilling actions. Here is a YouTube video, "Drill Bits - Oil and Gas Drilling: From Planning to Production" (3:26), that demonstrates the differences of the explosive, gouging, and crushing action of the tri-cone bit and the scraping action of the fixed cutter bits:
The Well Control System or the Blowout Prevention System on a drilling rig is the system that prevents the uncontrolled, catastrophic release of high-pressure fluids (oil, gas, or salt water) from subsurface formations. These uncontrolled releases of formation fluids are referred to as Blowouts. Due to the explosive nature of oil and gas, any spark on the surface can result in the ignition of the fluids and an explosion on the rig. An explosive blowout and the failure of the Well Control System were the causes of the Mocondo Well disaster that killed eleven of the rig crew on the Deep Water Horizon Rig on April 20, 2010 and resulted in 35,000 to 60,000 bbl/day of crude oil to spill into the Gulf of Mexico. We will discuss this later in the lesson.
In the detailed rig schematic (Figure 9.02e), the well control system is comprised of:
A picture of a Blowout Preventer (BOP), pronounced “B-O-P” not “bop”, is shown in Figure 9.11.
The blowout preventers are the principal piece of equipment in the well control system and are operated hydraulically; pressurized fluids are used to operate pistons and cylinders to open or close the valves on the BOP. The Accumulators (Item 18 in Figure 9.02) are used to store pressurized, non-explosive gas and pressurized hydraulic fluid to run the hydraulics systems on the rig. The accumulators store enough compressed energy to operate the blowout preventers even if the Power System of the rig is not operating.
The blowout preventer is a large system of valves each of which is capable of isolating the subsurface of the well from the rig to provide control over the well. These valves are typically stacked as shown in the Figure 9.11 and sit below the rig floor on land wells or some offshore wells; or they may sit on the seabed on other offshore wells.
A schematic diagram of a blowout preventer is shown in Figure 9.12.
Figure 9.12 shows three type of valves (there are others) – an Annular Preventer, Blind Rams, and Shear Rams. The Annular preventer is the ring-shaped piece of equipment on the top of the BOP in Figure 9.11. As the name implies, the annular preventer is used to prevent flow through the annular space between the drill string or casing and the annular preventer. The annular preventer can also be used for non-cylindrical pipe, such as the kelly, or open hole. The annular preventer consists of a doughnut shaped bladder that when in the open position allows the drill pipe to rotate but in the closed position seals the annulus. Figure 9.13 provides a schematic of the annular preventer.
In Figure 9.13, the blue area represents the doughnut-shaped bladder. As mentioned earlier, in the open position, (A), the drill pipe can be rotated or can be run up or down; while in the closed position, (B), the bladder pushes out, closing off the drill pipe, kelly, or open hole. The bladder based sealing element is not as effective as the ram type sealing elements; however, almost all blowout preventer stacks include at least one annular preventer.
Schematics of the ram-type preventers: the blind rams, the shear rams, and the pipe rams (pipe rams are not shown in Figure 9.12) are shown in Figure 9.14.
This figure shows that:
A blowout begins as a Kick (entry of subsurface formation fluids into the wellbore). What distinguishes a kick from a blowout is that a kick can be controlled while a blowout is uncontrollable. We have already discussed two of the defenses against kicks when we discussed drilling fluids when we listed the objectives of the drilling fluid:
In the first objective re-quoted above, if we can keep the pressure exerted by the drilling mud greater than the pore pressure, then we know that fluids will flow in the direction of the mud to the formation. This cannot always be achieved. For example, if we drill through a natural fracture or if our mud density is too great and we inadvertently fracture one formation, then we may lose large quantities of the drilling fluid into the fracture (Lost Circulation). In this situation, instead of having the full weight of the mud column exerting pressure on a second (porous and permeable) formation, we may only have a fraction of the oil column height exerting a lower pressure on that second formation.
In the second objective re-quoted above, if we deposit an impermeable Drill Cake (filter cake) across an otherwise porous and permeable formation, then for a slightly Underbalanced Pressure (drilling fluid pressure lower than the formation pressure) we have created a seal between the wellbore and the formation. Again, this is not a Failsafe System because at greater underbalanced pressures, the higher formation pressures may be able to displace the drill cake.
The two previously discussed methods are used to help prevent a kick from occurring, but as mentioned they are not always successful, and kicks may still occur. The causes of a kick include:
The following are Indicators/Warning Signs of a kick:
When a kick occurs, the Operating Company and Drilling Company always have well-specific plans in-place for all wells to ensure that any controllable kick does not turn into an uncontrollable blowout. I cannot go into the details of a well-specific procedures, but they will include some of the following features if a kick occurs during drilling operations:
Other procedures will be used if the kick occurs while tripping into or out of the well. The details of some aspects of this procedure such as hard or soft shut-ins and the circulation methods, The Driller’s Method and The Weight and Wait Method, will be discussed in detail in your later drilling classes. More importantly, for every well that you are involved with, there will always be Daily Safety Meetings that discuss the current status of the well and the important safety aspects of all drilling activities related to that day’s operations.
So, we have discussed the role of drilling fluid to exert pressure on porous and permeable formations and to coat them with an impermeable filter cake to help prevent kicks from occurring. We have also discussed the role of the blowout preventer and company procedures to control a kick once one occurs. So, how do blowouts happen?
Perhaps you remember the Macondo Blowout (Deep Water Horizon Rig) disaster. The name Macondo was the Prospect name (remember, we discussed prospects and well proposals in a previous lesson) while the Deep Water Horizon was the name of the rig. This was the largest oil spill in the Gulf of Mexico. When the disaster occurred, eleven members of the rig crew were killed by the explosion when the natural gas ignited.
The following YouTube video, "Deepwater Horizon Blowout Animation" (11:22), describes the Deep Water Horizon disaster and what its root causes were:
After learning about offshore drilling rigs, drilling crews, components of the drilling rig, kicks, and blowouts, I would highly recommend watching the movie “Deep Water Horizon” and use your knowledge about oil and gas well drilling to identify some of the technical aspects of the film. Ask yourselves some technical questions:
We have discussed the components of the drilling rig, now let’s discuss the drilling process itself. An oil or gas well is drilled in a very ordered sequence. The steps in this sequence are almost universally applied to the drilling of all wells.
Finally, here is a YouTube video, "Drilling Animation" (5:58), showing the entire drilling process. This animation is from Chesapeake Energy, and it discusses the drilling process for a Marcellus Shale well:
We began this lesson by discussing the five major systems on a modern rotary drilling rig. These are:
We discussed each of these systems along with the more important sub-systems that comprise these systems.
The power system on a drilling rig provides the for the other main systems on the rig and other ancillary systems, such as electrical systems, pumps, etc. The system typically consists of a prime mover (the component of the power system that generates the raw power) and a means to transmit the raw power to the end-use components on the rig. The sub-systems of the power system that were discussed in detail or listed and shown in Figure 9.02 include:
The hoisting system on a drilling rig does the heavy lifting on the rig. It is used to raise, lower, and suspend the drill string and lift casing and tubing for installation into the well. The sub-systems of the hoisting system that were discussed in detail or listed and shown in Figure 9.02 include:
The circulation system on a drilling rig allows for circulation of the Drilling Fluid or Mud down through the hollow drill string and up through the annular space between the drill string and wellbore. 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. The sub-systems of the circulation system that were discussed in detail or listed and shown in Figure 9.02 include:
The drilling fluid (mud) is a critical part of the drilling process. Muds can be water-based fluids, oil-based fluids, foam, or air. The objectives/functions of the mud are:
The rotary system on a drilling rig is the system that causes the drill bit rotate at the bottom of wellbore. We have discussed some components of the rotary system when we discussed rotary table and top-drive rigs, but we have not yet discussed the entire system. The sub-systems of the rotary system that were discussed in detail or listed and shown in Figure 9.02 include:
Drill bits come in different shapes and sizes. The choice of the appropriate bit depends on the formations to be drilled. The drill bits that we discussed in this lesson include:
The well control system or the blowout prevention system on a drilling rig prevents the uncontrolled, catastrophic release of high-pressure fluids (oil, gas, or salt water) from subsurface formations. The sub-systems of the well control system that were discussed in detail or listed and shown in Figure 9.02 include:
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 volatile, combustible nature of hydrocarbons.
The causes of a kick include:
The indicators/warning signs of a kick include:
Safety is of the utmost importance in the oil and gas industry, and detailed well procedures are developed for each well. In addition, daily safety meetings discussing the status of the well, the day’s operations, and the safety concerns for that day’s operations are typically performed by all responsible drilling companies and operating companies.
Finally, we discussed the steps in the drilling procedure (Making Hole). An oil or gas well is drilled in a very ordered sequence. The steps in this sequence are almost universally applied to the drilling of all wells. These include:
You have reached the end of Lesson 9! Double-check the to-do list on the Lesson 9 Overview page [11] to make sure you have completed all of the activities listed there before you begin the Final Exam Review week.
Links
[1] http://www.oil-gasportal.com/drilling/technologies/
[2] https://creativecommons.org/licenses/by-nc-sa/4.0
[3] https://www.drillmec.com/en/equipment/drawworks
[4] http://www.drillingcontractor.org/23877-23877
[5] https://gulfofmexicooilspillblog.wordpress.com/2010/12/24/gulf-of-mexico-oil-spill-blog-blowout-preventer-evidence/
[6] https://oges.info/library/145849/BOP-PRESSURE-TESTING-PROCEDURE
[7] https://en.wikipedia.org/wiki/Blowout_preventer
[8] https://commons.wikimedia.org/wiki/User:Egmason
[9] https://creativecommons.org/licenses/by-sa/3.0
[10] https://www.youtube.com/@Industrial3dvisualsolutions
[11] https://www.e-education.psu.edu/png301/node/816