Drilling technology has evolved considerably since those days (a full century and a half ago) along with the machinery used for the purpose, both on - and off - shore. There are over thousands Mobile Offshore Drilling Units alone in operation today in the Gulf, with the most modern ones costing as much as US$ 300-400 million to construct. KeppelFELS is one major rig-builder contributing to the supply of world-class offshore drilling rigs suitable to work in every part of the world.
These 650 + MODU’s in the worldwide fleet represent dozens of different styles, or classes of rigs. Some are specialized ships, modified to carry a drilling derrick, and maintain their position over the ‘hole’ either with anchors, or dynamic positioning [ DP uses satellite technology, together with thrusters motors to maintain the ships position over the 'hole', even during high sea conditions ]. Some of these vessels can drill in over12000 ft. of water depth . sinking well holes many times that distance ! Many fall into the "jack-up" category, which contains over 60 ‘sub-classes’ itself. These are typically restricted to working in shallower waters, approximately 350 ft. or less. A newer concept in drilling is being utilized in the deeper water arena. jack-up rig
Floating platforms, twice the size of a football field, are anchored firmly to the bottom ( using vertical "tension legs" ), and prevented from ‘swaying’ by using anchors, further out on all sides, in ‘guy-wire’ fashion. These facilities can then be used to both drill the wells, and then act as the production station as well. Another type of rig is the semi - submersible. These units also either anchor themselves in place, or use DP for extended periods of drilling, then are moved to a new drilling location while a permanent installation is placed at the drilled well(s).
The word "Petroleum" means rock oil and is derived from the Greek petra - rock and the Latin oleum - oil. Petroleum is thought to have developed from organic matter deposited with rock particles during the formation of sedimentary rock millions of years ago. This organic debris builds and is eventually broken down into subject matters rich in carbon and hydrogen. Weight and pressure compact the sediment into hard shales, which entrap these hydrocarbon particles. Over time and under certain conditions, petroleum is produced. The first nation to form an oil industry was France (1765 - 1849), however it was unsuccessful Up until around 1854 whale oil was use as lighting and lubricants. In 1854 Dr. Abraham Gesner, of Nova Scotia introduced kerosene as an alternative.
Companies such as Gulf Oil and Texaco that were formed as a result of the Spindletop discovery Other large corporations and wealthy families were now become very interested in petroleum The banking empire of the Rothschild family and Alfred Nobel (of dynamite and Nobel Prize fame) were both exploring in the Ukraine. In 1908, the Anglo-Iranian Oil Company had success in the Middle East and British Petroleum was born. At around the same time the Samuelson Trading Company in the Dutch East Indies (now Indonesia) began trading in oil under its family logo - a pecten sea shell.
The operating company decides where to drill only after careful consideration is given to several factors. The most important being that the company knows or believes that hydrocarbons exist in the formations beneath the site and that they will get a good return on their investment. In known fields this is quite easy but finding new fields may mean years of forward planning, research and searching For this, the operator will need a team that will identify, finance and plan the operation Based on the information provided, the management will then decided whether to drill.
In the early days of the industry, the only way of locating underground petroleum and natural gas deposits was to search for surface evidence of these underground formations. Those searching for natural gas deposits were forced to scour the earth, looking for seepages of oil or gas emitted from underground before they had any clue that there were deposits underneath. However, because such a low proportion of petroleum and natural gas deposits actually seep to the surface, this made for a very inefficient and difficult exploration process. The practice of locating natural gas and petroleum deposits has been transformed dramatically in the last 15 years with the advent of extremely advanced, ingenious technology.
As the demand for fossil fuel energy has increased dramatically over the past years, so has the necessity for more accurate methods of locating these deposits Technology has allowed for an incredible increase in the success rate of locating natural reservoirs. In this section, it will be outlined how geologists and geophysicists use technology, and knowledge of the properties of underground natural gas deposits, to gather data that can later be interpreted and used to make educated guesses as to where natural gas deposits exist. However, it must be remembered that the process of exploring for natural gas and petroleum deposits is rife with uncertainty and trial-and-error, simply due to the complexity of searching for something that is often thousands of feet below ground.
The exploration for natural gas typically begins with geologists examining the surface structure of the earth, and determining areas where it is geologically likely that petroleum or gas deposits might exist. It was discovered in the mid 1800's that anticlinal slopes had a particularly increased chance of containing petroleum or gas deposits. These anticlinal slopes are areas where the earth has folded up on itself, forming the dome shape that is characteristic of a great number of reservoirs. By surveying and mapping the surface and sub-surface characteristics of a certain area, the geologist can extrapolate which areas are most likely to contain a petroleum or natural gas reservoir.
Arguably the biggest breakthrough in petroleum and natural gas exploration came through the use of basic seismology. Seismology refers to the study of how energy, in the form of seismic waves, moves through the Earth's crust and interacts differently with various types of underground formations. In 1855, L. Palmiere developed the first 'seismograph', an instrument used to detect and record earthquakes. This device was able to pick up and record the vibrations of the earth that occur during an earthquake. However, it wasn't until 1921 that this technology was applied to the petroleum industry and used to help locate underground oil formations.
The same sort of process is used in offshore seismic exploration. When exploring for natural gas that may exist thousands of feet below the seabed floor, which may itself be thousands of feet below sea level, a slightly different method of seismic exploration is used. Instead of trucks and geophones, a ship is used to pick up the seismic data. Instead of geophones, offshore exploration uses hydrophones, which are designed to pick up seismic waves underwater. These hydrophones are towed behind the ship in various configurations depending on the needs of the geophysicist. Instead of using dynamite or impacts on the seabed floor, the seismic ship uses a large air gun, which releases bursts of compressed air under the water, creating seismic waves that can travel through the Earth's crust and generate the seismic reflections that are necessary.
Logging refers to performing tests during or after the drilling process to allow geologists and drill operators to monitor the progress of the well drilling and to gain a clearer picture of subsurface formations. There are many different types of logging, in fact; over 100 different logging tests can be performed, but essentially they consist of a variety of tests that illuminate the true composition and characteristics of the different layers of rock that the well passes through. Logging is also essential during the drilling process. Monitoring logs can ensure that the correct drilling equipment is used and that drilling is not continued if unfavourable conditions develop. It is beyond the scope of this course to get into detail concerning the various types of logging tests that can be performed. Various types of tests include standard, electric, acoustic, radioactivity, density, induction, caliper, directional and nuclear logging, to name but a few. Two of the most prolific and often performed tests include standard logging and electric logging.
Standard logging consists of examining and recording the physical aspects of a well. For example, the drill cuttings (rock that is displaced by the drilling of the well) are all examined and recorded, allowing geologists to physically examine the subsurface rock. Also, core samples are taken, which consists of lifting a sample of underground rock intact to the surface, allowing the various layers of rock, and their thickness, to be examined. These cuttings and cores are often examined using powerful microscopes, which can magnify the rock up to 2000 times. This allows the geologist to examine the porosity and fluid content of the subsurface rock, and to gain a better understanding of the earth in which the well is being drilled.
Electric logging consists of lowering a device used to measure the electric resistance of the rock layers in the 'down hole' portion of the well. This is done by running an electric current through the rock formation and measuring the resistance that it encounters along its way. This gives geologists an idea of the fluid content and characteristics. A newer version of electric logging, called induction electric logging, provides much the same types of readings but is more easily performed and provides data that is more easily interpreted.
The data is interpreted by an experienced geologist, geophysicist, or petroleum engineer, who is able to learn from what appear as 'squiggly' lines on the well data readout. The drilling of an exploratory or developing well is the first contact that a geologist or petroleum engineer has with the actual contents of the subsurface geology. Logging, in its many forms, consists of using this opportunity to gain a fuller understanding of what actually lies beneath the surface. In addition to providing information specific to that particular well, vast archives of historical logs exist for geologists interested in the geologic features of a given, or similar, area.
There are many sources of data and information for the geologist and geophysicist to use in the exploration for hydrocarbons. However, this raw data alone would be useless without careful and methodical interpretation. Much like putting together a puzzle, the geophysicist uses all of the sources of data available to create a model, or educated guess, as to the structure of the layers of rock under the ground. Some techniques, including seismic exploration, lend themselves well to the construction of a hand or computer generated visual interpretation of underground formation. Other sources of data, such as that obtained from core samples or logging, are taken into account by the geologist when determining the subsurface geological structures. It must be noted, however, that despite the amazing evolution of technology and exploration techniques, the only way of being sure that a petroleum or natural gas reservoir exists is to drill an exploratory well.
There also exists a technique using basic seismic data known as 'direct detection'. In the mid-70's, it was discovered that white bands, called 'bright spots', often appeared on seismic recording strips. These white bands could indicate deposits of hydrocarbons. The nature or porous rock containing natural gas could often result in reflecting stronger seismic reflections than normal, water filled rock. Therefore, in these circumstances, the actual natural gas reservoir could be detected directly from the seismic data. However, this does not hold universally. Many of these 'bright spots' do not contain hydrocarbons, and many deposits of hydrocarbons are not indicated by white strips on the seismic data. Therefore, although adding a new technique of locating petroleum and natural gas reservoirs, direct detection is not a completely reliable method.
One of the greatest innovations in the history of petroleum exploration is the use of computers to compile and assemble geologic data into a coherent 'map' of the underground. Use of this computer technology is referred to as 'CAEX', which is short for 'computer assisted exploration'. With the proliferation of the microprocessor, it has become relatively easy to use computers to assemble seismic data that is collected from the field. This allows for the processing of much larger amounts of data, increasing the reliability and informational content of the seismic model. There are three main types of computer assisted exploration models: 2-dimensional, 3-D, and most recently, 4-D.
These imaging techniques, while relying mainly on seismic data acquired in the field, are becoming more and more sophisticated. Computer technology has advanced so far that it is now possible to incorporate the data obtained from different types of tests, such as logging, production information, and gravimetric testing which can all be combined to create a 'visualization' of the underground formation. Thus geologists and geophysicists are able to combine all of their sources of data to compile one clear, complete image of subsurface geology. An example of this is shown where a geologist uses an interactive computer generated visualization of 3-D seismic data to explore the subsurface layers. Geologist Using Interactive 3-D Seismic Source: BP
One of the biggest breakthroughs in computer-aided exploration was the development of three-dimensional (3-D) seismic imaging. 3-D imaging utilizes seismic field data to generate a three dimensional 'picture' of underground formations and geologic features. This, in essence, allows the geophysicist and geologist to see a clear picture of the composition of the Earth's crust in a particular area. Obviously, this is tremendously useful in allowing for the exploration of petroleum and natural gas, as an actual image could be used to estimate the probability of formations existing in a particular area, and the characteristics of that potential formation. This technology has been extremely successful in raising the success rate of exploration efforts. In fact, using 3-D seismic has been estimated to increase the likelihood of successful reservoir location by 50 percent!
Most of the oil produced today is extracted by drilling into sandstone and limestone. In contrast to shale, these so called reservoir rocks are sufficiently permeable and porous to allow a modest amount of oil and gas to flow into the bore hole. Porosity is defined as the quantity of oil a rock can hold, while permeability is a measurement of the resistance as oil flows from pore to pore within the rock. In reservoir rocks at moderate depths of 4921 to 11482 ft (1.53.5 km), porosity and permeability are usually satisfactory. At greater depths down to16000 ft (5 km), sandstone can become so impermeable that exploitation is not financially viable even if large quantities of oil are present. However, rocks of the required porosity do occur even at such depths.
Before any decision can made to drill a hole several departments will offer information and advice based on evaluations gathered from previous wells, data collected, calculated estimated and guessed. The Geologist staff within the company will give this evaluation. The management will then decide on the action to be taken. If they decision to go ahead and drill the Drilling Engineer will asked to plan the well. His planning will be based on the information supplied.
If the location is offshore, the cost will run into millions. The rewards may be high, but so are the costs. There is no proven way of accessing any formation without drilling a hole. Once all the legal work are completed and in order, the drilling costs are evaluated. The operator can then decide if they think it is worth drilling, and if so where to put the rig. So far we have only looked at the planning from the operators side.
It is the responsibility of the drilling engineer to design and plan the well and guide the drilling tools to the zone of interest. A drilling engineer is a planner of operations, a technologist/engineer, and a scientist. He or she must understand and be able to synthesise the principles of geology, physics, mathematics, chemistry, and engineering science. Drilling technology is changing daily as well get deeper and rigs operate in deeper offshore waters.
It is the job of the drilling engineer is to design and implement a procedure to drill the well as economically as possible. It is also important that the well be drilled so that the formations of interest can be evaluated as to their commercial value to the oil-company . He/she does however, have limitations. The safety of the drilling crews and rig must be a prime concern. Governments of countries have rules and regulations that must be followed. Multilateral. Horizontal Directional.
Drilling Superintendent : He works hand in hand with the drilling engineer as the plan develops. He will source out equipment and companies that will be needed for the success of the operation. You would have noted, ?? I said hole and not wellbore the reason for this is, Not all holes are drilled to produce oil or gas. Tools and equipment will vary considerably depending on the reason for the hole to be drilled.
He will be the direct link to and organise all the contractors. This includes the drilling contractor and all the service companies that will be used for the operation. In fact from experience, this position requires the more experienced person as this individual will carry much of the responsibility throughout the operation. Once the location is selected and the well plan developed, a rig must be selected. The selection of a rig will depend on many variables but the depth of the intended hole will be the main concern.
Drilling Superintendent Rig Superintendent Drilling Supervisor Tourpusher Driller Mechanic Electrician Assistant-Driller Derrickman Crane Operator Floormen Roustabouts Medic Radio Operator Welder Drivers Truck Drivers Catering Mud Engineer Directional Crew Mud Loggers Cement Company Logging Company Wireline Company Fishing Company Completion Company Testing Company Toolpusher Drilling Contractor Operator Management Base Team Service Companies Field Team Before continuing it is extremely important that the people going out to the rig understand the infrastructure and the chain of responsibility within the working boundaries of the rig. It is often this misunderstanding that brings about many of the problems faced on the rig. It must be understood the company rep and the toolpusher work for separate companies. It must also be understood that the final cost, be it direct or indirect will be born by the operator
In the field the drilling operation and service personnel are supervised by the company rep. He is the witness for the operator and will remain with the operation from start to finish His duties are to see that instructions sent from the base in the form of the contract or well program are carried out to the companies satisfaction It is not his duty to run the rig. Many operators over the years have attempted to run their own drilling operation. Most have failed or found it to be somewhat more expensive. Logistics plays a major part in this mans work. Having equipment on site and ready is possibly the most cost effective part of a operation. Accurate and honest reporting is also very important. It is his report that affects the daily running of the operation
Before writing this manual the author spent 35 years working on or around the drilling and workover industry. He has held the position from roustabout to Operations Manager. Worked for drilling contractors both large and small. He also worked as a consultant for many small oil companies where he ran both the rig and drilling operation often being the only expatriate on the work force. In that time he spent 22 years in a senior position designing, building and running many different types of rigs both onshore and offshore. Of all the position within the industry the most underrated is the job of the rig toolpusher It is a position that shoulders most of the responsibility with out the authority. It is often his knowledge and skills that carry the operation
He and he alone, is responsible for the rig and keeping it running. The safety of the well and the people on site are also his responsibility. Once orders are passed to him from the drilling supervisor, it is his responsibility to see they are carried out as efficiently and safely as possible. He will check all equipment coming to the rig and report any defects to the drilling supervisor. He will ensure all the rig equipment is maintained and in good working order. He will relieve or supervise the driller should there be problems with the wellbore. He will plan and suggest a rig budget for the coming year He is supported by a team of: Drillers, Mechanics, Electricians and a Tourpusher
Under normal conditions a drilling crew will consist of: Assistant Driller, Derrick man and 3 Floormen. They are backed up by a crane operator and the roustabout crew. Backing up the rig floor are the maintenance people . The mechanic and his department, Electrician, Medic, Radio operator, Welder. The conditions under which they work will vary and depend on the part of the world the rig is operating in. Work schedules will vary with the type of rig. As a rule, once an operation starts it is a 24 hour a day operation. Offshore the crews will work 12 hours on and 12 hours off for periods ranging from 7 days on and 7 days off, to 28 days on and 28 days off. The living conditions would be close to that of a local hotel. However on land operations, conditions can very drastically and the standard of living can range from living in a hotel or camp, to looking after yourselves.
Offshore rigs and land rigs have a lot of similarities. The rig is the drill floor and all are designed to do the same work however they do differ in as much as the type of equipment the may have to be used and their flexibility.
The derrick provides the necessary height and support to lift loads in and out of the well, and must be strong enough to support the hook load, deadline and fast-line loads, pipe setback and wind loads, Although derricks come in many heights there are only 3 standard ranges. The drill string, when retrieved from the wellbore, if not laid down, will be stood back in stands. A stand can range between 95 feet and 65 feet. However, derricks can also be designed to hold a single joint of 32 feet. A small workover rig may have a single 32 ft or double 64 ft racking area, where as a big rig will have a 95 foot derrick rack back capacity.
The double derrick gets it name from the fact it is designed to stand back stands ranging in lengths from 57 feet to 65 feet The average length of a joint of drill pipe is 31.20 feet. Such a rig will be rated to drill up to eleven thousand feet or workover a well as deep as 13000 feet. Most are truck mounted for fast moving and would have a total number of loads not exceeding 50. With a well trained crew, a small rig such as this can finish a well in the morning and be moved, rigged up and back at work within 36 working hours.
The mast capacities range from 100,000# hookload to 440,000# hookload with heights ranging from 70 ft under crown to 131 ft under the crown. Many of these rigs are equipped with heavy duty hydraulic systems capable of providing power for hydraulic pipe tongs, tubing and sucker rod tongs, hydraulic rotary tables, hydraulic hand tools and hydraulic swivels. Truck mounted rigs have both stiff and telescoping masts that are manufactured from high strength, cold drawn, seamless, square steel tubing. Cross beams are high strength, low alloy, angle iron for design capacity and ease of repair or replacement. The hydraulic pump is driven from a power take off the transmission, other common methods are to mount the pump below the engine and use a belt drive. The transmission design has the advantage that it protects the pump from dirt and grime during rig transportation and make it easy to maintain.
Mix Tanks Superintendents office 150’ Cement unit
They also have the advantage of being able to be walked in to a platform. Once the rig is pinned in location the legs will be jacked down penetrating into the sea bed. Once on solid ground the hull will be raised from the water until it has a small air gap. Jack ups are very versatile and easy to move. They come with two basic type of legs. Independent leg – Mat supported Independent leg jacking is a great advantage if for some reason the rig has to jack up and around a platform. the rig can be tilted by stopping the movement on any of the legs
The rig will then take on a preload of between 3 and 6000 tons. After holding the preload and allowing the rig to settle, the load will be dumped and the hull will be moved to needed working height. (air gap) Once there, the rig will be skidded out over the slot or well it will work. A well organized operation can be driving pipe within 5 hours of dumping the preload. One disadvantage is the penetration each leg may get into the sea bed. It is also possible for a leg to punch through the formation even having taken on the full preload although this is rare.
Mat supported rigs do not have the penetration problem of the independent leg rigs and can sit on soft sea beds. However I have known them to have problems due to cutting settling on the top of the mats. Moving jack ups is done by towing or if a long move it may be dry towed. This is done by putting the rig on the back of a special ship that submerges itself until the jack up is in place above it, the ship the discharges it ballast and lift the jack up out of the water.
With the rig tied down it is now ready to be move, such a move can be anywhere in the world and will cut days off a towing move
It is possible to have a semi and a jack up on the same barge. However many of the rigs now being designed will not fit on the back of this barge
The older type would use tugs to move them. Designed to operate in water depths from 200 to 5000 feet. The hull is supported by up to 8 cylindrical legs that are mounted on pontoons. After the rig has moved onto location it will take on ballast and fill the ballets tanks thus submerging the legs between 50 and 90 feet under the surface. Designed to work in deep water The modern Semi Submersible is a self propelled unit that is held on location by the use of anchors. More modern types are now using dynamic position that work for satellite navigation systems. Ballast tanks are incorporated into the base of the legs and pontoons and once filled with water and the rig is in the semi-submerged mode it provides stability during drilling operations.
Sea bed Sub Sea BOP System Choke Lines Kill Lines Hull Pontoons Rig and Derrick Mean sea level Moon pool The rig is connected from the BOPs to Surface by a Sub sea riser Air Gap Water Depth up to 10000 feet
Drill Ship are for ultra deep water and have worked waters up to 10000 feet. Riser drilling technology is used for drilling from a floating vessel. A large diameter Riser Pipe is used to connect the rig to the Subsea BOP’s on the seabed and provide a conduit for running the drill string to the stata below the seabed.
The floating buoyant material acts to reduce weight in water. This Riser Pipe receives, in addition to self weight, other forces such as bending, tension or compression caused by motion of the vessel. In order to provide sufficient strength against these forces, high-tension steel will be used. BOP is provided at the bottom end of the Riser Pipe on seabed. The Riser Pipe is a steel pipe of a diameter of approximately 50 cm, and is equipped with attached line and floating buoyant material (partially). This is a safety unit that closes the borehole to prevent any fluid (liquid such as oil or water, gas such as natural gas or hydrogen sulfide) contained in the strata from rising up to Drill Ship through Drill Pipe or Riser Pipe when the Drill Pipe reaches abnormally high-pressure strata.
Swamp Barges and Submersibles This type of rig is used in shallow water, lakes or in swamps. The derrick will often be laid down for moving as they will often be towed on main rivers Some swamp barges have legs that will be lowered to pin the barge in place. Swamp barge at work in Nigeria Swamp barge on tow. Note how the derrick is laid down this allows it to be towed under bridges and up main water ways The draft on such a unit is often less than 6 feet allowing it into very shallow water
Some times the water may be too deep for a swamp barge but does not warrant the expense of a big offshore rig. For such an operation a true submersible would be put to work. Submersibles sit on the sea bed while working by taking on ballast and dumping the ballast once the operation has been completed and they are ready to move. You will often see the working in lake or at the entrance of rivers Average water depth for working is between 60 and 80 feet
Platforms are designed so that many wells can be drilled from one central point off shore. The size of the platform varies depending on some of the condition that will have to be meet later. The Ecofisk Charlie platform in the North Sea extended to over a mile and has two hotels platforms adjoining it. When I worked there, there were only 12 wells on it. This small platform is being worked by a jack up that has canterlivered out the rig and would possibly have 9 wells drilled from it.
This is the Hibernia Platform Working offshore Nova Scotia. It’s a concrete gravity platform designed for impact resistance From ice bergs.
Gone are the days when the boss came out for the day as now day hotels are installed offshore. After many of the platforms have completed all the wells, the rig will be stacked and left behind ready to workover any wells that have problems or decrease in production. Other platforms and wells from the field will be linked into one main platform and a trunk-line laid from the platform to the oil terminal onshore or there could be a storage terminal offshore, as in many of the Middle Eastern countries Hotel
This tender is a purpose built self-erecting drilling tender barge with a flat bottom, raked stern and raked bow hull shape. The Self-Erecting Tender Rig (SETR) is designed especially as a cost efficient and very flexible drilling system for development scenarios involved multiple well slot, fixed offshore platforms. Whereby the rig moves from platform to platform using its own Drilling Equipment Set (D.E.S) which is lifted on by its own crane. Lifting operations can be made onto platforms up to a height of 65 feet above mean sea level. Smedvic T-7 tender Rig
Not every hole drilled will become an oil well. Even in a production field, the hole may miss the target. Small platforms allow for marginal fields to be tied into a main trunk-line running from the main field. Note well “a” and “b” they could very well be drilled not as production but enhanced recovery wells. Injection wells, To boost production or support the depleting formations. a b
It must be understood that there are many manufactures and different types of drilling rig, however they are designed to do a job. That job is to drill holes in the ground, not find oil. Once understood, there is no reason that a person can not move from one type of rig to another with confidents. The pages that follow will take a person that has never seen a rig, and introduce them to all the equipment they will ever need to know.
Platform derricks are designed to maximises the operation and/or limitations of the installation. Many of today's Platform derricks are designed to meet the demanding specifications required for North Sea due to the adverse weather condition. With the demand for deep water drilling many derrick accommodate a diverse range of specifications, that can include the crown mounted compensators, vertical pipe handling systems and harsh motion and environmental criteria.
Standard Derrick: is a bolted structure that must be assembled part by part, usually used on offshore platforms.
• Derrick installed on floating rigs are designed to withstand extra dynamic stresses due to rolling, pitching, heaving and stresses from wind.
• The space available between the rig floor and the crown block must be higher to handle the wave- induced vertical movement of the floating support.
The mast on the other hand is raised or lowered into position by the use of hydraulic rams and then scoped out to its operational height. The jack knife type derrick is pivoted at its base and is raised or lowered by the use of drawworks. The mast is constructed with the use of pins that join the sections together. The stripped down structure is moved by truck load. A big derrick would normally take 12 loads to move. Here you see a small land rig preparing to go to work. The rig has just moved over 300 miles and across several rivers and is now in the heart of bandit country in the Delta state of Nigeria where it will spend the next 5 month working over very high pressure wells.
Sling shot rigs and now the swing rig have improved on rig move times no end. The concept of picking up the derrick with the drawworks has been around a long time. The swing rig goes that one step more by picking up the complete rig package as one
The Swing Rig design, is one of the quickest and easiest rigs to assemble and raise. There are two basic types On one the drawworks are raised after the derrick and pined into the substructure. On the other, the drawworks are left down. This gives more room on the rig floor for people to work.
Installing the drawwork on a land rig can be done in several fashions. On many sling shot rigs the rig will be assembled on the ground, the drawwork section will then be hoisted into position, Followed by the derrick then the floor section. On other rig designs, the derrick will be picked up first and the drawwork follows. This will often mean the driller having to ride up with the platform For this to be accomplish the substructure will have an A frame incorporated into it By stringing up the drill line and block the driller will slowly raise the derrick and providing the crown section has been installed on an A frame the derrick should start to pick up at around 300,000 lbs.
Hook Load C.W. Height Base Racking Cap DYNAMIC DERRICKS - Deep Water 2,000,000 170' 40x56' PRS4i 2,000,000 170' 55x60' PRS4i Both the above to accommodate C.M.C. systems DYNAMIC DERRICKS - Standard 2,000,000 180' 40x40' 25,000 1,400,000 170' 40x40' 20,000 1,400,000 160' 40x40' 20,000 1,300,000 185' 40x40' 24,000 1,000,000 160' 40x40' 20,000 DYNAMIC DERRICKS - With Crown Mounted Flare Stack 1,000,000 160' 40x40' 20,000 750,000 160' 40x40' 20,000 300,000 120' 20x20' 6,000 STATIC DERRICKS - Platforms and Jackups 2,000,000 190' 46x52' 36,000 1,500,000 180' 46x52' 30,000 1,300,000 170' 32x36' 36,000 1,000,000 170' 30x30' 30,000 1,000,000 170' 30x30' 26,000 1,000,000 147' 30x30' 20,000
As you can imagine, to operate the average drilling rig there would need to be a lot of power. Although I know of a rig that draws it power from the local community this is very rare and would normally only exists in areas where the rig is working within the community. In general the rig will generate the power need from it own generators fed on fuel supplied by the operator (oil Company). The water needed would be drawn from a previously drilled water well or trucked to the site In times gone by many rigs would run on steam. However nowadays there are two basic systems Compound - run on air and clutches Diesel Electric with the base power coming in the form of electricity All rigs use the air and clutch to operate many of the components. But it is the main equipment drives that determine the rig. Such as the Rotary, Drawwork and Pumps
Ask most people what make the world go around and they will say money. Over the years many well-known people and some not so well-known have found out the hard way this is not quite true. There are two common factors that will bring a mighty nation to it knees within days. One is communications. The other is fuel. The rig will not run without fuel and will not keep going long with dirty or watered down fuel. Between the years 1993 and 2001 I worked in Nigeria. There were constant fuel strikes and to make money the fuel would often be tampered with. The damage done to the prime movers was incredible the cost to the operator was unbelievable as the rig would close down due to lack of supplies. Therefore a good covered-in fuel tank is needed, the minimum requirement is 400 bbls.
Many people believe the rig Toolpusher runs the rig. This again is not totally true. The toolpusher supervises the running of the rig. The person that keeps it running is the Mechanic supported by his team and the electrician. A good Mechanic will keep a rig running no matter what. His/hers top priority are the main engines. It dose not matter what kind of rig it is - with-out the engines there is no power. It is often extremely hard to explain to people the power that a driller has at his finger tips. A typical modern rig will have as much power as a small town. Four or five main generators and one emergency/ auxiliary generator will supply the rig with a total of 11,275 hp These generator are driven by powerful engines such as the Caterpillar shown here.
If anybody ever refers to the cat's on a rig their talking about the Caterpillar prime movers. Land-based and offshore drilling operations have long relied on Caterpillar and it would be very hard for someone to get a new type of engine installed on a rig. Four or five main generators and one emergency/ auxiliary generator will supply the rig with a total of 11,275 hp. Five Caterpillar generators model 3516B electronically control at 1,200 rpm, diesel engines driving 600 volt, 60 hertz, 2,150 KVA, model SR 4 generators One stand by generator will have, in addition to its emergency functions, significant power to the SCR system in the event the main power system fails, thereby enabling the driller to circulate mud or pull the drill string into the casing. The emergency system’s large capacity enables it to simultaneously power all of the rig lighting, cranes, air compressors, bilge and fire fighting systems, and miscellaneous AC loads.
The power generated from the generators is distributed around the rig. Some rigs draw the power from one source by selecting just the equipment needed to be run. Others have pre-set selection that are controlled from a central unit such as a Silicone Controlled Rectifier (SCR) it is possible using the SCR system to be running several items from the same generator at the same time. This is the inside of the SCR trailer from the last rig I worked. Most of the morning meetings were held in here as it was the only part of the rig where the air conditioning worked as it should have.
To get the power needed the driller would normally call down to the engine room and tell them what the operations for the day will be. The mechanic and electrician will then assign the SCR the driller will need to the board. The drawing of the system flow of the power starting at the prime mover (Diesel Generator) As you can see the generator will send the power through the system ending up at the motor that will drive a said peace of equipment. The DC motor, usually a 752 horse power motor, will the power the machinery. Rigs use both AC and DC power. The AC power system runs the lighting and suchlike. The DC power system runs the machinery, drawworks, mud pumps, rotary etc.
This hoisting system starts at the dead line anchored point and finishes at the drawworks. The wire line used is threaded up and over the crown block, back down and to the travelling block, back up to the crown block, then down to the drawworks that has a rotating drum and is the winch that pull or runs the pipe to or from the hole . The drawworks main drum stores the excess used line as the string is raised or lowered .
The drawwork is a winch and is part of the hoisting system. It can also be used to drive the rotary. The one you see here is a National Oilwell 1625 DE with an input horse power of 3000 (2238Kw) and is rated at drilling depths from 16000 ft (4877m) to 25000 ft (7620m). It is driven by 2 or 3 electric DC motors that offers four hoisting speeds and two rotary speeds. This model uses a 42 in. double plate clutch for low drum drive and a 46 in. x 10 in. Dy-A-Flex air clutch for high drum drive. The clutches drive a 36 in. dia. x 61 1 /4 in. integral, spiralled, two- step grooving long main drum. Older modules were furnished with the standard band brake system that are now being replaced with a hydraulically controlled disc brake system. Disc brakes provide improved performance over conventional band brakes
The drillers has a control panel that is mounted along side him enabling him to have full control over the equipment around the rig. By assigning electric power via different SCR’s to various equipment. He can also control the amount of power being used on the equipment. This is a very important point as he can set equipment up to pull or stall at a given power making it an excellent safety factor. Unfortunately not every one understands the power they are controlling and accident can still happen.
It is used in making up and breaking out tool joints in the drill string. It is also used as a hoisting device for heavy equipment on the drill floor The cathead is a shaft with a lifting head that extends on either side of the drawworks and has two major functions. This is done by wrapping the cat-line (cat-line is generally made of rope and is connected to a piece of chain used to tie on to equipment) around the lifting head. The number of turns of rope on the head and the tension provided by the operator controls the force of the pull. Make up cat head use when running in the hole to make up the tools.
The break out cat head: Use for breaking the tool joint when the string is pulled from the hole. This cat head is more powerful than the make up cat head. The jerk line is attached to the cat-head and break-out tong. Two tongs are used to break the tool joint the break out tong will always go on top unless breaking out the connections above the kelly. Most connections above the kelly are left hand thread. The jerk line is fitted to the cat-head, the best way to do this is to make a slip noose on the sling that fits over the lug on the cat-head. This is best done by brazing two nuts together and passing the line thought both and brazing one end to the nut allowing the other part of the wire to slide Wire Rope Nuts brazing Free
The distance from the drum to the first sheave of the system is the controlling factor in the fleet angle. A winch is most effective when the pull is exerted on the bare drum of the winch. When a winch is rated at a capacity, that rating applies only as the first layer of cable is wound onto the drum. The winch capacity is reduced as each layer of cable is wound onto the drum because of the change in leverage resulting from the increased diameter of the drum. The capacity of the winch may be reduced by as much as 50 percent when the last layer is being wound onto the drum.
The drum of the winch is placed so that a line from the last block passing through the centre of the drum is at right angles to the axis of the drum. The angle between this line and the hoisting line as it winds on the drum is called the fleet angle. As the hoisting line is wound in on the drum, it moves from one flange to the other, so that the fleet angle changes during the hoisting process. The fleet angle should not be permitted to exceed 2 degrees and should be kept below this, if possible. A 1 1/2-degree maximum angle is satisfactory and will be obtained if the distance from the drum to the first sheave is 40 inches for each inch from the centre of the drum to the flange. The wider the drum of the hoist the greater the lead distance must be between the winch and the first sheave.
As mentioned before, in the old days a drilling contractor would have purchased only enough rotary drilling line to string up his reefing system. Depending upon the height of his derrick and the number of parts of line to be used, lengths would vary from 650 to 1,750 feet Today, purchasing longer lengths of drilling line, and periodically slipping new rope into the system while cutting off old line at the drum end, shifts the rope through the critical wear areas and distributes the wear more uniformly along the length of the rope. Wire line, chains, pulleys, turnbuckle bulldog clamps, rope and sockets are use continually in the industry and have in the past be a major cause of accidents. Even with the stringent safety rule of to-day they are still a major cause of accident
Often when new drill line arrives at location it will be transferred to a automatic spooler before being strung up. The spooler has the advantage in that when cutting and slipping the drill line you will only need one person to control the line feed speed. Line spoolers are driven by air or hydraulics and have a braking system. Where they really come into there own is on land operations when stringing back. One person runs the drum, the rest of the crew can keep the wire from laying on the ground picking up dirt.
The sand line is a small line incorporated into the back of the drawworks system. The line is generally used for running surveys or fishing for lost surveys. These units are usually integral parts of the drawworks. The sand line will often be used as a hanging line for tools. However all precautions must be taken when using it this way as when the drawworks is running fast the cat heads are spinning very fast. The best way to use the sand line to hang off tools is to shut down the drawwork and put in the clutch then start the Drawworks and use the hand throttle to adjust the speed Sand lines are 6x7 EIPS fibre core construction which makes a strong and flexible combination. Available in 5/16", 3/8", 7/16", 1/2", 9/16" and 5/8" diameters.
Take a trip around any warehouse or yard and you will find several drums of wire line, ask why they are there. The normal answer will be, they were here when I came. Such warehouses are often full of wrong orders. Measuring line is a simple procedure that is best done by using a clapper of some description. If your unsure of how to read it have your Mechanic do it Care must be taken not to measure across the flat between adjacent strands. In accordance with industry standards, all new rope has a plus tolerance of approximately five percent, so a new one inch rope may measure from 1.000" to 1.050". Incorrect Correct
Wire is often damaged due to incorrect transferring from drum to drum. Which of the methods is the right way? Correct Incorrect Wraps of wire rope should not overlap when wound on the drum of a winch but should be wrapped in smooth layers. Overlapping will result in binding, causing snatches on the line when the rope is unwound. To produce smooth layers, start the rope against one flange of the drum and keep tension on the line while winding. Start the rope against the right or left flange as necessary to match the direction of winding.
Correct incorrect The more layer of wire on a drum the less efficient the wire becomes. Over laying a wire can severely damage and lessen the strength of the wire Often if the electric brake is not set in accordance with the manufactures recommendation, when applied when running the block up to pick up a stand of drill pipe on trips the block will stop dead. This will jump the wire and over lay the drill line. If not noticed and the string is picked up it will severely damage the line. The electrician should set the controlling current so as the control liver applies the current in increments. The same will happen if the fleet angel is to high or the wire line guide is not installed in the derrick.
There are two recognised cable cutters in the industry. I say two, but if we count the cutting torch it will make three. The hammer blow cutter uses a cutting blade that is held in the punch and cut the cable after x amount of blows with a sledge hammer. The hydraulic cutter is a little easier to use. Y ou lay the wire in the clamp close and secure the latch than use the hand pump to pump out the cutting blade.
It is virtually impossible to calculate the precise length of wire rope that can be spooled on a reel or drum, the following formula provides a sufficiently close approximation. L = length of rope to fit Drum (ft.) D = depth of rope space on drum (inches) B = width of drum between flanges (inches) E = drum barrel diameter (inches) A = diameter of reel flanges (inches) C = clearance K = constant for given rope diameter The formula is: L = ( D+E ) * D * B * K Find K on the next page or use the Wire line drum calculator Wire line drum calculator Basic Windows Calculator B A C D E
The A Frame is the upper most part of the derrick. It is designed to support the weight of the crown block. And is used for any maintenance that might be needed up in the derrick such as changing a sheave.
It is also use for lowering the crown from the derrick.
Rigs that use a hoist type derrick would not normally have an a-frame as any work needed would be done when the hoist is in the horizontal position once it is laid down.
At the very top is a flashing red light. Often the rig antenna will be mounted on the top along side the light
Originally when a derrick had to 'built' at every location, the water table was used to check if the derrick was level,
By looking at the water level in a wide, shallow tray (bucket, basin, whatever)
and using a plumb bob,
The derrick could be check for line up and that it was centred over the well and that the crown block was level so that there would be no side loading or wear on the crown sheaves and drill line.
The method of using water to find the true level is still used in many parts of the world and is often used when levelling of the pad the rig sits on.
The crown block consisted of a frame that supports series of sheaves (7) that make up the top section of the block and tackle use the move the drill string or tools being run in and out of the wellbore It sits on the water table and is held on place by guide and bolts. The drill line is strung up starting from the spare drum a round the dead line anchor. Up to the crown block. Back down to the traveling block (X) number of times, back over the last crown block sheave before going back down to the rig floor where it is install and secured to the fast drum on the drawworks Crown blocks range from 100 tonne through to 1000 tonne capacity and are available in a full range of sizes from 24" through to 72"
The block and tackle which is rigged with the crown block by multiples of drilling line strung between the crown block and the traveling block.
A cluster of sheaves taken from a national Oil Well Block. Changing the sheaves up on the crown is not the best place to have to work, but it happens.
The hook is located beneath the traveling block. This device is used to pick up and secure the swivel and kelly. The hook is designed in such away that it will allow the string to rotate while at the same time holding the travelling block steady so as not spin all the line as the block is moving. But it can be lock into a given position for the drilling mode. The second major function is to relieve some of the shock when a load is picked up. By allowing the hook to open under control whilst picking up the driller can creep into the load, thus saving a lot of ware and tear on the drilling line and the sheave bearings. This is a Varco BJ Dynaplex hook and they come with lifting capacity's between 350 and 1000 tons
Lifting tools include the bails ( Links) and the elevators. These are often classed as drilling tools but they are part of the hoisting system and must be treated with the same respect as you would other more obvious parts. The links fit onto the lugs of the hook and elevators. Once in position the flaps are closer and locked using a bolt. They should be inspected along with the drill string
It is imperative that top drive users exercise care and caution when using a top drive during and after a jarring operation. Due to the changing parameters of jarring operations (depth of hole, drill string, free point, type of jars, etc.), it is impossible to establish firm limits or guidelines for jarring with the top drive. Every situation will have to be evaluated on individual merits with due consideration of the costs of abandoning a well.
After any jarring operation the top drive should be thoroughly inspected according to the following guidelines: Perform a thorough visual examination of the top drive looking for any signs of damage. Visually inspect the mud inlet piping. Check all wire locked bolts for damage or broken wires. If broken wires are detected, re-torque the bolts, and re-wire. Replace damaged wires.
Check all external bolts and nuts that are not wired for tightness. Any bolts found to be loose should be removed, coated with Loctite 242 thread locker, reinstalled and re-torque according to the specifications in the manual Check all guards, vents and covers for tightness. Ensure that all safety cables are properly and securely attached. Visually examine the inside of the junction box(s) for loose components. Open the motor brush access covers and check that all bolts are tight and all brushes are correctly positioned. Also ensure that the condensation heater is secure.
Check that all electrical plugs are properly engaged and secured. Check the seals at the bottom of the rotary manifold to ensure they are properly in place..4. The top drive hoisting load path is designed according to API Specification 8C; it can be treated in much the same manner as any API hoisting equipment. The main difference is that the top drive has many accessories bolted on; these should be checked for loose bolts, etc. as described above. Jarring operations can be done with the load connected through either the quill shaft or the elevators.
The final components that go to make are the hoisting assembly are the lifting elevators. There are many types of elevators how ever they can be classes into two categories. Centre Latch: These are mostly used for drill pipe and have protruding handles. Side door: mainly used for casing and drill collars. The opening handle is more flush with the body. Not all elevator are design to lift the string some are designed to pick up just one joint. Always check the Safe Working Load (SWL) of any set of elevators before using them. If possible check any later data posted about elevator from the latest Safety bulletins as over the years some have been down graded.
The drillers weight indicator is used to monitor string weight, overpull and set down loads. Like so many tools on the driller console it talks. Listen too it and understand what it is saying. How it works
Anchor Point: This is a fixed position in one corner of the rig floor and would normally be on the other side of the rig floor from the draw-works. This is done to help distribute the load being moved. The unused drill line that is stored on the drum is past around the dead line anchor before being strung up. Incorporated into the dead line is the load sensor that operates the weight indicator on the drillers console. The dead line base is bolted to the main substructure by 4*3 inc bolts
Crown Block Safety System is used to prevent the collision of the travelling block with the crown block. This system senses when the travelling block is within a preset distance of the crown block. This is done using the spooling drill line that connects with the toggle allowing air to operate the piston in the air cylinder It then disengages the clutch, then simultaneously applies the brakes to the drawworks. This device is critical to the safety of rig personnel. Toggle Air inlet Operating Cylinder
Crown-O-Matic's and crown savers are designed to provide crown and floor protection by ensuring that the rig's braking system can stop the block before the draw work's brake is overrun. Derrick designs generally incorporate extra space at the crown area to allow for safer operation of the travelling block in an area that is hard for the driller to see, and also to allow for potential travelling block overrun of the upper mechanical stop caused by high block ascending speeds near the crown. Fitting portable top-drives to rigs reduces this extra space increasing the possibility of the travelling block impacting the crown. By installing and setting up the crown-o-matic properly, safe operation of the travelling block is maintained to the maximum upper block travel limit.
In generally the drawworks will have two braking systems; The brake as most driller will refer to it is a manual braking system that incorporate a handle that is attached to a set of brake bands that have a number of brake pads attached. When applying weight to the brake lever the bands are tightened around the brake flange attached to the drawworks main drum and the load is slowed down and will eventually stop. As the well gets deeper so the string weight will increase. As the string weight ingresses so will the speed of acceleration as the block and string is lowered. As with a car, the faster it is move the longer it takes to bring it to a halt. If the load moving is so heavy, it will not stop. The heat generated by the friction of the two contacting surfaces will lift the handle so high, the driller will lose control. Therefore and auxiliary braking system is installed. It can be one of two systems. Hydromatic or electromagnetic.
The Hydromatic Brake is a hydrodynamic device that absorbs power by converting mechanical energy into heat in its working fluid, which is normally water. Resistance is created exclusively by fluid friction and agitation of the fluid circulated between the vaned pockets of the rotor and stator elements with the conversion of mechanical energy to heat taking place directly within the fluid itself. The amount of mechanical energy that can be absorbed in this manner is dependent upon the quantity and velocity of the fluid in the working chamber.
It will be readily seen that with any specific quantity of fluid in the working chamber, the velocity of the fluid will be increased with increased revolving speed of the rotor. In this manner the horsepower capacity of the brake increases approximately in proportion to the cube of the speed; if the speed is doubled, the horsepower resistance is increased eight times. The hydraulic horsepower capacity increases at this rate to the maximum operating speed of the brake. It should be noted, however, that other limitations such as shaft diameter and fluid flow capacity may be the limiting factor instead of speed.
Cooling Fluid circulating system. The lay out can be different in so much as the fluid tank can be closer to the driller All the driller has to do is open and close Valves
The electromagnetic type braking is provided by two opposing magnetic fields. The magnitude of the magnetic fields is dependent on the speed of rotation and the amount of external excitation current supplied. In both types of auxiliary braking systems, the heat development must be dissipated using a liquid cooling system. An excellent braking system if set up properly. Unfortunately there seams to be very few rig that have it set up the right way. It is designed is such a manner that hand adjustment should apply the power at the rate the driller move it allowing the block to come to a controlled stop. It is possible to run the rig the complete round trip without applying the main brake if this one is set up properly
The work string starts at the swivel or the circulating point and end at the tool being run to do the job. This can consist of many combinations but would normally come under one of four headings. Drill string - used to drill the well Workover string - this include many tools. Casing string - run to protect the open hole. Completion string - run to produce from a well. All can be broken down into a variety of sub strings.
Modern day drilling operation employ a Top Drive or Power sub to rotate the drill string. However it will be many years if ever before all drilling rig use a top drive and many will finish the time still using the conventional equipment. Although many companies manufacture equipment for the industry, most rig floors are designed in a similar fashion. All have the same job to do. Therefore the equipment will be basically the same, most variations are installed not to improve on performance but to get around copyrights.
Kelly hose . The kelly hose, visible in the lower right of the photograph, connects from the standpipe to the swivel thus allowing the drilling fluid to circulate while drilling. This high pressure hose moves up and down every time the pipe is moved and needs to be pressure tested at the same time as the BOP’s.
Stand Pipe Manifold coming from Rig Pumps 65 ft kelly Hose Kelly Double pin Sub Upper BOP Kelly Spinner Swivel Bail and Elevators Hook assembly Travelling Block Gooses Neck & wash pipe The upper kelly assembly is unique in the fact that all the threads are cut to the left. This is some times forgotten and drillers have spent hours when attempting to break the subs and tools from between the swivel and kelly. The double pin sub is often a second cause for concern. As well as being left hand it often has two different types of thread. Normally the pin facing up is regular and the pin facing down will match the thread on the drill pipe.
The swivel is a clever piece of engineering that has changed very little from the time it was first designed.
It is the point of entry where the drilling fluid that is being pumped under pressure goes inside the drill string while the drill string is rotating while the hook holds the weight of the drillstring that has not been applied to the bit.
It is connected directly to the hook while in the drilling or circulating mode but taken off and set back while pulling the string from the well bore.
The prime purpose of the Kelly Spinners is to make fast connections as the hole is drilled. The kelly is drilled down 32 feet and then replaced by a single joint of drill pipe. It can be also be used for rotating drill pipe slowly, and for limited rathole and mouse hole drilling These units are completely reversible; and can spin out, as well spin in, when making connections, therefore replacing the need for a spinning chain. Installation is relatively simple, they are made up below the swivel similar to a routine sub installation and above the kelly cock (upper BOP) the two torque arresting chains are attached to the bumper block, Once installed in the string the air supply hoses are connected up. The tool joint threads, are 6 5/8" in. API regular left hand.
This is a Safe and fastest means of making connections with a make-up speed in as little as 5 seconds It bolted to bottom of swivel -always in position for use yet out of the way very handy if you do not have the space between the crown and rig floor. Available with Air or Hydraulic motors suitable for rig's power system It is very similar to a power tong and can be equipped with a reversing out or double acting jaws allowing right and left hand rotation. They are also very powerful and have no problem drilling the rat or mouse hole. The controls are situated at the drillers console.
The first upper kelly valve came into being in 1947. A company by the name of OMSCO set the standard by designing a flapper-type upper kelly valves. This has proven to be dependable and has remained virtually unchanged. The valve must be manually closed. It can be partially opened by starting up the mud pumps, but must be fully opened manually to prevent mud cutting. Other types of valve include the Hydrill and Itag straight body valve. The upper kelly valve is also referred to as the upper BOP. It is installed directly below the kelly spinner and is last of the components to have a left hand thread .
Safety valves located above and/or below the kelly. These valves are of a ball type and must be manually operated. Their primary purpose is to prevent flow up the drill string in case of emergencies. A third kelly cock is generally kept on the drill floor to be used in the drill string in the event flow up the drill string occurs while making a connection or tripping pipe. It must be understood that the valve has to have the same OD as the connections in the string just incase it is needed for stripping into the well while the well is under pressure. 3 to 5 Day
There are basically two types of pump in sub. Top entry and side entry. For testing the BOP I like to use the side entry with the inside BOP “Ball Valve Type” on top with the Grey type on top of that. This allows you to test the valve at the same time as you test the BOP. It also allows you to test the rest of the kelly using the test plug and rams. As a rule this will save over an hour on the standard test. Side entry pump in sub with butt weld unions
There are two type of kelly, square or hexagonal. They are precision machined of the finest steel. Although slowly being replaced by power swivels (Top Drives) many companies still maintain the kelly as a back up unit. They have been tried and tested for over 70 years and if treated with respect will last for many years. The shape of the kelly makes it the drive cog for the drill string and it is driven by the rotary drive bushing.
The Kelly is the part of the drill string that allows a round pipe to be turned at great speed and also allow the spring to be picked up and down while still rotating. It will also carry the complete string weight under tension. Therefore all kellys are made of fully heat treated alloy steel and have a Brinell hardness range of 285-341 and a minimum average Charpy impact value of 40 ft-lbs. Before leaving the manufacture they are inspected and sealed into their scabbard. All kellys are shipped in a protective steel casing scabbard.. Square Kelly Hexagonal Kelly
Drive bushings transfer the rotary power to the drill string so that it can be turned. They are installed on the kelly allowing the kelly to be raised and lowered while at the same time rotating the drill string. There are two types of drives The Drive Pin: This has four pins protruding from underneath that fit into the rotary master Drive bushing. The square fit. For this type directly into the drive bushing that have been designed to accept the kelly bushing
As one can imagine the kelly is an extremely expensive piece of equipment and will be doing much of the work throughout the drilling of the well. It therefore needs to be protected. Installed directly below the kelly is the kelly saver sub. The sub protect s the base of the kelly from rubbing against the bell nipple and BOP. Thus protecting the inside of the BOPs. Below the kelly saver sub is a valve, the lower kelly BOP. This is a ball valve that is manually operated and can be closed in order to remove the kelly should the string need to be striped back to bottom. This valve must have the same OD as the Tool Joints on the drill pipe. The final sub that make up the kelly is the throw away thread protector sub. This is a small sub is used to protect the lower BOP threads on connection. It is a very important sub. If it gets damaged and the threads are bad it can damage the complete string of drill pipe as it is made up to all joints at some point while drilling the well.
Drill pipe is used to extend the depth of the well. Although there are many grades, weights and sizes, there are only 3 lengths ranges. A joint of pipe can be broken down into 3 sections. The Box. Connection The Tube “Body” The Pin Connection. There are two sides Inside “ Diameter “ (ID) Taken from inside the pin All we need now is the grade. We then have most of the information needed to design the drill string Grade Yield Strength Min psi Max psi Maximum Tensile Strength psi D E X95 G-105 S-135 135000 105000 95000 75000 55000 -------- 10500 125000 135000 165000 95000 100000 105000 115000 145000 Outside “ Diameter “ (OD) Taken from the Tubing Box Pin Tube OD ID
There are three basic calculation that a driller will need to know Capacity: Formula: ID 2 /1029=bbl/ft Displacement: Formula:= Pipe adjusted weight/2745 Maximum Pull Formula:= OD 2 -ID 2 *.7854* Minimum Tensile Strength psi Drill pipe adjusted weight can be found in most service company manuals or in courses Rig Components for Supervisors. This is a five day course that deal with many of the drilling techniques and calculations for senior personal
The person running the rig "The Toolpusher" is himself running a business, a business designed to make money. He presides over many departments and is responsible in see that all are run in a professional manner. Before a rig is to be put to work, a plan should be made and carried out. This must include the inspection of the drillstring and drilling components. This section will introduce you to the drill string from the kelly down and will include some of the tools use to drill a well. The drill string starts at the swivel and finishes at the bit. The drill pipe is the component that is used to extend the depth of the well. The normal length of a joint of pipe is 31.00 ft. however some rig use 45 ft joints.
Hevi-Wate Drill Pipe (HWDP) differs from normal drill pipe in as much as it weights a lot more. It is used for many reason. Thick-walled heavy drill pipe is used in lieu of drill collars. It is generally used in high-angled well where too many drill collars hamper drilling operations. To help keep tension on the drill pipe while drilling. Keeps the transition zone out of the drill pipe. Flexibility are just a few of the uses. HWDP can be recognised by the oversized centre and the amount of hard banding that is on the tool joints. HWDP can be ordered in two ranges Range 2 Range 3 OD range from 3 1/2 “ to 5”
Used to supply the weight needed to drill the hole. Also used to keep the drill pipe in tension. There are many weight and sizes of drill collars They can be slick or spiralled. Spiralled drill Collars are use to keep the hole to pipe contact to a minimum and assist in stopping hole problems such as differential sticking OD Length Fish Neck Elevator recess . Slip Recess Slick Drill Collar Body Spiral Drill Collar Body
Stabilisers are used to control the direction of the wellbore String Stabilisers are designed to assist in directional control By adjusting the size and position of the stabiliser the bit can be made to drop, build or hold angle. They also help to hold the drill collar a way from the walls of the wellbore lessening the possibility of wall contact and the BHA getting stuck. The near bit stabiliser is also used to help with directional control. But its main purpose is to centralise the bit prolonging the working life.
The Jar is used to free stuck drill strings or to recover stuck drill string components during drilling or workover operations. Many jars have both an up and down impact that are variable from light to extra-heavy depending on the overpull applied. There are two types of jar. Oil operated and Mechanically operated. Jars are used in vertical, directional and horizontal holes, and are also used in fishing, coring, testing, casing swaging and other downhole operations. Extended reach drilling has lead to many improvements within the industry. Many of the service companies have invested millions of dollars in research to improve tool that we use every day. Many of to-day Jars are both oil and mechanically operated
When a set of jars arrive at the location they normally have a transfer and work form with them. This is a good time to get to know your jars and work out where to place them and how they work. It is both the drillers and supervisors responsibility to understand the working of the jars at the location. Rig-Site information Sheet Depth in FT / M Jar re-latches from open at: LB/DAN Jar re-latches from closed at: LB/DAN Jar length Ft. mm Jar OD. inc.mm Jar smallest ID inc. mm (this may not be at the pin or box) Fish Neck Length inc/mm Jar serial no OD and length of Mandrill inc.mm
Not all jars are quite the same. The SLEDGEHAMMER Jar (Sperry Sun) is an HYDRAULIC UP-MECHANICAL DOWN jar. Where the Daily Mechanical Jar can be adjusted from surface. Other jars have a pre set detent. NOTE When the jar has been fired and before it is re cocked, the jar’s free stroke can be used to establish an accurate measurement of frictional drag acting on the free portion of the drillstring.
Jars are run for protection and should always be installed at least 30 feet above the largest outer diameter tool in the string and never below a tool that has a larger outside diameter. Using the oil type, the driller can control the jarring direction, impact intensity and jarring times from the rig floor. The operation of the tool is not affected by downhole torque so that the orientation of directional drilling tools is unchanged by jarring operations. The mechanically operated jars is normally a preset jar, set to fire at a given overpull. However there are some that can be adjusted from the surface by the driller by applying left or right hand torque
Purpose Enhances impact up and down jarring. Provides stretch for short strings. Directs shock waves towards fish. Concentrates energy at the jar. Absorbs damaging shock waves . Application Horizontal drilling Shallow drilling High drag or dog legs Severe sticking problems Operation Double acting Drilling or fishing Place 15% of overpull between Accelerator and Jar.
A joint in the drilling string located above the bit to absorb and prevent any vibrations from affecting the drill bit (same functions as a shock absorber). The bumper sub is a downhole shock absorber. It operates as a slip joint. Most bumper subs have a 3-5 feet stroke and can be run in tandem for motion exceeding 3-5 feet. The bumper sub is used on floating operations to reduce the heaving motion of drill ships or semi-submersibles on the bits. A disadvantage of the bumper sub is maintenance costs both for the tool itself and lost time due to tripping pipe when one fails. Furthermore, the position of the bumper sub is not ever really known while drilling operations are being carried out, so its effectiveness can be limited.
Under-reamers are designed primarily to under-ream below casing to provide adequate clearance and cementing space for running small clearance consecutive strings of intermediate casings. Before running this tool a thorough check should be made of the arms and cutter blade. Rough drilling and bouncing will tear off the arms if they are not secure. Using a bit and stabiliser will assist in keeping the reamer on course, an expanding stabiliser should be installed above. If you are only opening a short section of hole, space out some stabilisers in the old hole section. They will help to centre the cutters. Once at the point of interest. Start your pumps while rotating the string slowly between 20 and 40 rpm. This will allow the blades to open fully and will be noted at surface when the rotary torque drops off. With the cutter now out, open up about 10 ft of hole or what is needed to extend the stabiliser blades before extending the blades. With the pumps still running, stop rotating, pick up the string then go back and tag the ledge.
Often when a rig is going to drill top hole in an area suspected of having shallow gas, the operator will drill a pilot hole. This pilot hole will be much smaller than the hole needed later to accept the conductor pipe. If the section of hole proved to be safe, it will be opened up to the full OD. For this you would need a hole opener. Such a tool will have fixed or replaceable arms and is guided by a pilot bit or mill. The tool is made up on the bottom of the bottom hole assembly usually with a near bit stabiliser installed directly above.
In the early days of rotary drilling drag bit, "fish tail" bits were the main technique involving cable tool rigs. In 1909 Howard Hughes Snr introduced the world's first rotary rock bit equipped with two rolling cone cutters. This bit radically change rotary drilling by making it possible to penetrate harder formations. The development of drilling bit has played a major role in the way the petroleum industry have drilled to produce energy. Hughes also established the first research laboratory to study rock bit performance in 1910 and in 1917 introduced a reaming cone bit with two regular cones in addition to a reamer built into the body of the bit.
During the planning stage, the Drilling Engineer makes a thorough review of offset well data and record bit performance and bit grading characteristics. All occurrence of gauge wear and the tooth dulling characteristics should be noted. This will help determine the bit type suitability for the formation drilled, i.e., for insert bits whether the inserts were worn or broken etc. Data required for the correct bit selection include the following: 1. Prognosed lithology column 2. Drilling fluid details 3. Well profile.
LONG TOOTH Long Tooth (Milled) Bits produce a hole by shearing the formation, and are mainly used on surface hole. Good fast drilling bit but are limited by the hardness and shearability of the formation being drilled. They work extremely efficiently in plastic clays and soft rock formations such as chalk and cemented sands, provided sufficient flushing is available to lift large cuttings and prevent the bit from "Balling". Graphics Courtesy Reed Bits
Proven cutter technology for increased penetration & directional control Fixed or interchangeable nozzle systems for improved hydraulics Spiral gage pads improve cutting ability while reducing whirl Tapered Shaped Cutter technology provides for increased responsiveness and directional control Junk slot design allows for better cleaning Flat profile, short shank length & other low torque features maximize steerability
Core Bit Close up of core bit Diamond Bits are used for hard formation and coring Diamonds are impregnated into the outer body then heat treated
Nozzle size plays an important role in bit hydraulics. The benefits of correct selection include improved bottom hole cleaning, reduced risk of bit balling, faster ROP and lower drilling cost. In conventional bits, the flow stream strikes the bottom or bottom corner of the hole. The fluid then disperses radically 360 degrees. Some fluid flows under the cutters to remove cuttings, but most of the fluid flow is directed toward the centre and toward the whole wall without passing under the cutters. That fluid returns up the annulus without assisting the process of chip formation or removal of cuttings from the wellbore. Shrouded nozzles provide maximum protection against snap ring erosion due to abrasive fluids, excessive turbulence or extended drilling hours. Standard jet nozzles are easier to install and recommended for situations where erosion is not a problem. Orifice sizes are stated in 1/32 increment. The nozzle code indicates the diameter of the jet socket and nozzle O.D
The rotary table is the driving force behind any drilling operation. Up until recently the rotary was fixed at the rig floor and it is the component that drives the drillstring. Now day modem rig have power sub "Top Drive" that have incorporated the rotary into them. But there are still more rigs running rotary's than top power subs, as many of to-days hole are drilled with down hole motors the rotary still plays an important part. Because it is a tried and tested method very few drilling contractors are prepared to remove it from the rig equipment list and keep it as a stand by even if the rig has a power sub. The rotary table itself is a very simple design and has changed little over the years. Some rotary's can be driven from the main drawworks by changing the drive sprocket and incorporating a chain.
Charts are the most useful of all tools as they maintain and record the drilling trends over time. A quick backwards glance at the past will soon put you on track. The Mud logger will have them and there should be a recorder in the drillers dog house. Use them. For sudden and immediate changes the Amp meter or rotary torque gauge on the rig floor are used. The amp meter being the most accurate. But for people use to a rotary and kelly the change in sound will be the first indication of pending high torque . A little past it’s prime “like myself” the rotary torque gauge is still one of the most useful tools in assisting the driller to determine hole problems
Fitted into the master bushing are a set of smaller bushings they are known as Insert Bowls, they are in two half's and can be removed independently. They come in several sizes Size 1, 2, 3. and it is the combination of master bushing, insert bowls and pipe slips that allow the rig to run the different size pipe. Insert Bowls 1 allow pipe size from 13 5/8 to 11 1/4 Insert Bowls 2 allow pipe size from 10 3/4 to 9 1/2 Insert Bowls 3 allow pipe size from 8 1/2 down The important factor to remember is the split bushing must match the casing or drill pipe slip. It is possible to run the wrong slips and bushing however should you ever rock the pipe and it starts to move you can say good by to the pipe along with your job. Here we see the insert bowl being removed from the master bushing with the use of the bushing pullers. They are picked out using the rig floor air hoist as each segment can range with the region from 185 to 336 lbs. Pulling the inserts by hand has been a major cause of back injury form many years
The table itself is design so that it can be adapted to hold different sizes of pipe and will come as different size rotary's, they range from 48 in. on a big rig to 17 1/2 inc. on a small rig. The master bushing has is designed so that it can be pulled out of the rotary opened up and taken from around the pipe or tool that is being lowered into the well. To do this a 4in. pin has to be remove d and the master bushing opened up from one side. The size is the maximum pipe size that can go through the rotary, however any pipe below the rated size can be held in the rotary this is done by changing the combination of bushing and slips that will hold the pipe. The rotary itself is fixed and contains an assortment of drive cogs and bearing that in turn drive the main rotary. As a main drive has to be round there needs to be a cog that will fit inside the round drive that will not spin while the rotary is turning. This is known as the master bushing and it is rectangular in shape.
Again you must use the right slips. It is not impossible to drop the big pipe in the hole by accident as an up and coming driller I dropped a short string of 20 in. pipe in the hole when the casing elevator hooked under the collar. It did not pick up, but just rocked the pipe and away it went. Fortunately I made up a tool to retrieve it and the pipe was successfully retrieved without a spear on the fist run and not a lot of time was lost or my job. For pipe sizes larger the 13 5/8 in. you would have to remove the master bushing and insert bowls that are designed for that particular size pipe, such as 20 in.
A rotary that has a size of 48in. would need to have the master bushing taken out and the pipe adapted to hang on the rotary. However a rotary is not limited by the manufactures size over the years, I have run 48 inc pipe using a 36 in rotary. This will mean taking the rotary out and using the skid beams as a false rotary. On one particular well we install 48 in casing over a well we had just completed and use the same technique to build and install the platform and to my knowledge the platform is still there to this day. The drawing shows the 36 inc pipe that is to be driven sitting on the rotary table before it is welded and driven. It is sitting on the same pad eyes that it was picked up with.
The rotary has to be strong as it will often take more weight than it was designed for. When the drill or casing string is settled in the slips the rotary will be holding the buoyant weight of the string this could be 75% of the total weight. However not everyone seems to have the time to settle the string into the slips under control, it is not unusual for such people to drop the slips in around the pipe as the pipe is still moving at a fair speed. Under such conditions, a string with a buoyant weight of say 400,000 lbs could very easily weigh 800,000 lbs as it come to a sudden stop. Don't do it .
Rotary Slips are designed for use in API Bowls. There are 3 gripping lengths. 11 in, 13 3/4 in and for deep holes 16 ½. They are rugged in design and the slip assembly is designed to provides full load distribution throughout the length of the slip thus preventing bottle-necking or slip crushing of the drill pipe. It is important the right length of drill pipe slips are being used for the string weight that is being run and that the insert bowls are not worn or damaged.
Drill pipe slips come in a range of sizes and in many case the dies that grip the pipe can be interchanged or a set of slips are so design that different size slip dies will fit the same body. The handles are designed in such a way that the people handling them cup the handle from below. This is the safe way to pull slips if the worm on the brake can not stop the block and should land the elevators on the slips it is just a matter of releasing the handle and letting the elevator hit them and not taking off most of your hand.
This is the most common view people get of the rig floor, and it is the view the driller sees most of the time. The pipe in the middle is going down the hole and tools are laying around. However there is far more too it than that. One must remember that all roads lead to the floor and everything and body on the operation is there to support it. It is only when things go wrong do people other that the drilling crew realise there is more to it than standing behind the driller drinking coffee
Safety is always a top priority on the floor The photo shows the rig pulling from the hole under very tight conditions. Note how every thing is moved away from the rotary. It only takes a second to clear the floor. The drawworks are an Oilwell 2000 and is less than two years old. Before this pull we pulled 998,700 lbs on the casing to get it back out of the well. Here we are only pulling 470000 lbs and cleaning out the 84 o 8300 foot hole in 1984. The well was drilled and completed in 12.3 days
Working over wells using a swamp barge has it fair share of hazards especially where this one is working. Here you see the pipe deck and the V-door as we pull out laying done pipe ready to wire line. The completion string has yet to arrive and the wire line unit is installed behind me up on the poop deck.
Same well. With the string now laid out. The operation going on is wire line. As you can see the kelly has been racked back. And the wire line lubricator is hanging free in the derrick.
More time is wasted on testing due to drillers not knowing the piping around their rig A well designed floor will have a minimum of 4 manifolds Stand Pipe Manifold High Pressure Manifold Cement Manifold Choke Manifold
The stand pipe is a configuration of valves, sensor and gauges designed to divert the flow of fluid from the rig pumps Normally designed in a “H” shape it should be able to direct fluid under pressure to the following areas. The Kill Line on the BOPs The Cement Manifold. The Choke Manifold. The Shale Shakers. Back to the pump Room. On land to the Production Area Of course it must also direct fluid down the drill string. While all of this is going on, it must also have a point where a sensor can monitor the pressure. Such points would need to be isolated in case one needs to be repaired. It cannot do this alone. Other manifolds are connected to it but the lines are out of sight
Testing Port From Cement Pump To Bottom Kill Line From Bottom Choke Line From Top Choke Line Manual Gate Valves Pressure Gauges Manual Chokes Hydraulic Chokes Baffle Chamber To Mud Gas Separator Valve Behind Chokes
Hydraulic Chokes Controlled by the Driller Manual Bean Chokes Test Port Inlet Main by Pass Valve would normally be 4inc. Baffle tank leading to Mud Gas Separator Double studded adapter Flange to reduce pipe size Flow Nipples to reduce wear and wash on the manifold High Pressure Side Low Pressure Side Hydraulic Gate Valve
There are many configurations of drilling choke manifolds. They can be purchased or custom built to fit the condition that will prevail on any particular well. However the basic must have the following.
On land a hydraulic choke is essential. It is extremely hard to control an influx from the rig floor if the choke is 50 or 60 feet away from the driller. There must be three flow paths with one that is not choked back. This will normally be in the centre and will when open allow the fluid to flow un-interrupted directly to the sump. Other outlet will go to the mud gas separator and one to the flare line. The line leading to the flare must be anchored to the ground. Both must have an isolation valve and they must be tested at the same time as the BOP’s.
The high pressure circulating system start with the rig pump (slush Pump). The total pressure loss in the system is highest at the discharge of the pump a point that is often missed when making out the drilling hydraulic program. The 200 or 300 psi between the rig pump and the stand pipe gauge can often be the deciding factor in the amount of rig down time due to pump failure. Look after the rig pumps and they will look after you.
There are two drilling fluid circulating system involved in oil well drilling, the low pressure mixing system and the high pressure circulating system. For the rig to operate effectively good high pressure mud pumps is needed. Wells are getting deeper by the day and circulating pressures are climbing. 20 years go circulating with 3000 psi was high pressure, today drilling pressure in excess of 4200 psi are not uncommon and so the need for a reliable circulating system arises. The National-Oilwell model 12-P-160 Triplex mud pumps offers the rig a wide range of pressures and volumes for maximum operational flexibility. The Pump is equipped with a maintenance free suction and discharge pulsation dampener that is designed reduce hydraulic noise and improve detection of MWD signals that are transported from the tools to surface via the drilling fluid. Triplex Single Action stroke cycle
Discharge Pod Suction Pod Quick change caps Fluid Flow Direction Triplex pumps are force feed with the cylinder under pressure when the piston is on the forward stroke Piston Complete with Head Piston extension clamp Cylinder and Valve Plug and seal assemblies
Due to the speed the triplex can run at it is force feed by a charger pump. Normally a 11" centrifugal pump powered by a 75 horse power electric motor. By changing the liner and piston the pump pressure can be regulated between 0 and 7500 psi. As the name triplex indicates, there are three liners and all there have to make a complete cycle to complete one the stroke. The pressure being applied from the two other cylinder hold the discharge valve closed until it starts it's forward stroke. The suction valve then closes and the drilling fluid is forced up into the main stream circulation system. Quick release caps and heads make them an extremely easy pump to work on when changing out the liners As you can see as the piston is withdrawn the fluid is forced into the liner cylinder by the charger pump. The forward stroke pushes the fluid under pressure The back stroke fills the cylinder.
Relief Valve Discharge Manifold Discharge Pod (3) Suction Pods (3) Suction inlet Mud filter screen inside Pulsation Dampener Bleed off line To stand pipe
The secret of successful pumps is to run a program. This is done by changing out and replacing expendable parts. A six valve insert change allows for a pump program of 2100 hours before a major parts change Valve and seat Valve and seat Seat Pulling Tools
Skid To Well Isolation Valve Pressure Gauge Pulsation Dampener Nitrogen Fill Up Point Nitrogen Pressure gauge Pop off Valve 2” bleed off line Discharge Pod Suction Pod Main suction inlet Unlike the Triple The duplex needs a little more looking after. Attention needs to be paid to the valves while the pump is running. Not being able to see when a swab goes out can and often does lead to a lot of extra work. Ideally the rig should have a pump program Anybody can pull pipe but a good Derrick Man is judged on his ability to look after his pumps and drilling fluid Graphic: Leonard T. Roe RigSite www.workover.co.uk
The duplexes double acting pump can be hard work especially when working on pumps like the Oilwell 1700. The liners is closed in making diagnosing problems harder, if the piston starts to wash it is very easy to confuse the signs with a valve washing out. and if you get it wrong ? The duplexes stroke slower than the triplex and can be gravity feed how ever most company now run them force feed. Forward Stroke Backward Stroke
Running a pump with a damaged pulsation rubber is a quick way to damage a pump. It should be checked daily and adjusted to the rated working pressure. Introduced over 40 years ago it has solved many of the problems associated with oilfield reciprocating mud pumps. A stabilizer disk enhances reliability by precluding the trapping of fluids in folds of the diaphragm which increases diaphragm life and predictability. The pulsation dampener if filled up with nitrogen from the top inlet valve to a maximum pressure of 750 psi and should be sealed using Teflon tape on the threads before reinstalling the cap. Hydrill K-Series Is rated at 7500 psi and is possibly the most well know of all pulsation dampeners
Type "B" reset relief valve is used as a safety valve on slush pumps, mud manifolds and other equipment to protect against damaging pressure surges. The valve pressure setting is indicated by a pointer and is adjustable over the entire operating range. The pressure setting can be changed while the valve is under pressure. When the preset pressure is exceeded, the valve snaps to the fully open position. After pressure is relieved, a trip-free reset lever closes the valve. Setting accuracy is not affected by vibration, pressure surges, or valve operation. Pressure setting scales are available in psi, bars, and MPa.
The stainless steel valve piston seats against an elastomer seal which is out of the direct path of flow. Rapid valve opening and isolation of the seal, minimizes erosion. The valve is fully enclosed for safety and to retain the protective grease coating on all moving parts in the bonnet assembly. No shear pins or other parts are needed for resetting to the closed position. A manual release button in the bonnet assembly permits easy and rapid opening of the valve regardless of line pressure. The position of the release button indicates whether the valve is open or closed. Relief pressure can be set at any value over the entire range of the valve. Finish
Chemicals, clays and weight materials are added to drilling fluid to achieve various needed properties. Drilled solids, consisting of rock and low-yielding clays. These solids affect many mud properties. Solids removal is one of the most important aspects of mud system control, since it is directly related to operating efficiency. The volume of solids has a direct bearing on the: rig efficiently, rate of penetration (ROP), hole stability, drilling hydraulics, torque and drag, surge and swab pressures and is the major mechanism associated with many of the hole problem such as lost circulation and stuck pipe. Therefore solid control is a major influence the cost of any drilling operation Introduction
It is impossible to remove all drilled solids, either mechanically or by any other methods however they can be reduced by:
Screens “shale shakers”
Dumping and dilution
Hydroclones and centrifuges use centrifugal force to obtain higher rates of separation than can be achieved by gravitational settling.
Many potential problems can be avoided by observing and adjusting the shale shakers to achieve maximum removal efficiency for the handling capacity. As the first step in the mud cleaning/solids-removal chain, the shale shaker represent the first line of defence against solids accumulation. They produce nearly a 100% cut (D100) at the screen opening size. A 200-square-mesh shale shaker screen will remove 100% of the solids greater than 74 microns, Shale Shaker Using screens of the finest mesh to remove as many drill solids as possible on the first circulation from the well is the most efficient method of solids control. It prevents solids from being re-circulated and degraded in size until they cannot be removed. As much as 90% of the generated solids can be removed by the shale Shakers Warning NEVER BYPASS The SHAKERS
De-sanding Cyclones A desander is needed to prevent overload on the de-silters. Generally, a 6-in. ID or larger hydroclone is used, with a unit made up of two 12-in. hydro-clones, rated at 500 gpm per hydro-clone, being common. Large desander hydroclones have the advantage of a large volumetric capacity (flow rate) per hydroclone, but have the disadvantage of making wide particle-size cuts in the 45- to 74-micron range. To obtain efficient results, a desander must be installed with the proper “head” pressure.
De-silting Cyclones To achieve maximum efficiency and prevent overloading the desilter, the entire flow should be de-sanded before being de-silted. Generally, a 4-in. ID hydroclone is used for de-silting, with a unit containing 12 or more 4-in. hydroclones, rated at 75 gpm per hydroclone, being common. The proper volumetric capacity for de-silters and de-sanders should be equal to 125 to 150% of the circulation rate. Large-diameter wells with high circulation rates require a greater number of hydroclones. Desilter hydroclones generally process a significant volume of fluid and have a more-desirable narrow cut point. A well designed and properly operated 4-in. hydroclone will have a D50 cut point of 15 to 35 microns, with a D90 of around 40 microns. Since barite falls into the same size range as silt, it also will be separated from the mud system by a desilter. For this reason, desilters are rarely used on weighted muds above 12.5 lb/gal. Both desilter and desander are used primarily while drilling surface hole and where un-weighted, low-density muds are used.
Linear Motion Mud Cleaner Basically, a mud cleaner is a desilter mounted over a vibrating-screen shaker generally 12 or more 4-in. hydroclones above a very fine-mesh screen, high-energy shaker. A mud cleaner will remove sand-size drill solids from the mud, yet retain the barite. It first processes the mud through the desilter, then screens the discharge through a fine-mesh shaker. The mud and solids that pass through the screen (cut size depending on screen mesh) are saved; the larger solids retained on the screen are discarded. By API specifications, 97% of barite particles are less than 74 microns in of the waste material lowers disposable costs. Unless the mud cleaner is discharging a significant amount of solids, the centrifugal pump feeding the desilter will be causing detrimental particle size degradation. If fine-mesh shale shaker screens of 200 mesh or less are operating properly and no mud is bypassing the shakers, a mud cleaner may not be of any additional value
Decanting Centrifuges CENTRIFUGES As with hydroclones, decanting-type centrifuges increase the forces causing separation of the solids by increasing centrifugal force. The decanting centrifuge consists of a conical, horizontal steel bowl rotating at a high speed, with a screw-shaped conveyor inside. This conveyor rotates in the same direction as the outer bowl, but at a slightly slower speed. The high rotating speed forces the solids to the inside wall of the bowl and the conveyor pushes them to the end for discharge. Whole mud is pumped into the hollow spindle of the conveyor, where it is thrown outward into an annular ring of mud called the “pond.” CENTRIFUGE APPLICATIONS In weighted drilling fluids, a centrifuge is normally used for barite recovery. This is beneficial when the liquid phase of the mud is very expensive .
Drill Cuttings & Solids Pulverizer The disposal of drill cuttings and environmentally hazardous materials is becoming a critical issue aboard offshore drilling rigs. Governments are becoming intolerant to the use of oceans as a "waste can" for oil exploration. The issue now becomes one of HOW and WHERE do oil companies dispose of these liquid and solid wastes? To combat this companies have had to develop new ways of Disposing of Drill Cuttings and Hazardous Materials. This machine is the "Drill Cuttings & Solids Pulverizer" (DCSP). The DCSP reduces the volume and the handling difficulties associated with the disposal of materials generator during offshore exploration. Solids are reduced to a smooth slurry which can be handled via pumps and piping instead of with conveyors and shovels. Liquid waste streams can be mixed into these slurries thereby eliminating the need for separation of waste materials.
Why do we want to remove gas from drilling fluids? There are several problems caused by gas, but the main reason we want to remove gas from drilling fluids is to keep the mud pumps pumping mud. Due to the compressibility of gas a mud pump with a compression ratio of 1.5 will stroke with almost no delivery if the mud weight is cut by 33%. A mud pump with a compression ratio of 2.0 (some triplex pumps) will stroke without pumping mud at all when the mud weight is cut 50%. Many think that pumping gas cut mud down the hole is serious because it will reduce the hydrostatic head and even lead to a kick. Any bubbles in the suction pit that can be picked up by the pumps and pumped down the drill pipe will probably be smaller than 1/8" in diameter. As the bubbles are pumped down the drill pipe, they are under so much pressure and are compressed so small that it will only slightly affect the mud weight and consequently the hydrostatic pressure.
Return to mud tanks Half Round baffle plates Or it can be used Closed in Designed for under balanced drilling an H2s Gas. Gas line would be 200 feet and up to 12 inc diameter Inlet from choke could be up to 8 inc diameter. Return mud line up to 12 inc. diameter. Can be fixed or skid mounted. and would have a diameter of 6 feet. The mud gas separator is very often referred to as the poor boy degasser. This goes back to the times when it was just a tank open to the atmosphere. The values of this equipment can not be overstressed as it is generally the first device available to extract gas from the mud. It consists of a chamber with baffle plates, which are flat plates that force the fluid through a certain path. The mud is allowed to flow in the chamber over the baffle plates which separates some of the entrained gas. This device generally can extract 50% to 60% of the gas. To flare line Under normal conditions it would be lined up as an atmospheric degasser sending any gas up the derrick This type of degasser can be directly plumbed into the return flowline and used as part of the diverter system. In this case the returning fluid would go back into the system
Compressing a gas at a constant temperature to double its pressure causes the gas volume to decrease to one-half its present volume. For a 10 ppg mud gas-cut to 9 ppg (23.1 in3 of gas) at the surface at atmospheric pressure (14.7 psi) it will be 2 atmospheres of pressure at 30.6 ft. The gas volume is now 11.55 in3 and 9.5 ppg. At 58.8 ft. and 4 atmospheres of pressure the volume is 1/4 of 23.1 in3 and mud weight is 9.75 ppg. At 1800 ft. the mud weight is 9.98 ppg which is so little the difference can't be seen on a mud balance. Boyles Law - Pressure-Volume Relationship for Gasses:= P1/P2 = V2/V1 As an example, if you take a 10 ppg mud that is gas cut 10% to 9 ppg, the volume of all the bubbles in one gallon is 231 in3 times 10% = 23.1 in3. According to Boyle's Law:
The added solids in the mud would reduce the penetration rate, bit life and solids removal efficiency. If drilling at or near the fracture gradient of the formation, there is a possibility of fracturing the formation and losing all or partial returns. All of the above slow the drilling process and cost money. If you have a true mud weight of 12 ppg that is gas cut to 10 ppg and add barite to increase the mud weight to 12 ppg in a 1000 bbl system, it would take approximately 1200 sacks of barite. This would be an unnecessary expense in unneeded materials, but the initial cost of the barite would not be the only problem. The real problem with gas-cut mud is that it can go unnoticed. If the apparent mud weight is low, barite may be added to increase the mud weight to the desired level.
Blowout Preventors (BOP’s) and Blowout Preventors Equipment (BOPE) are installed on the well to control invading formation fluid should the primary well control fail. The primary well control being the drilling fluid in the wellbore. BOP’s and the subject of well control is a is a course within its own right and can not be cover in this short time, However this introduction will help you understand its value
Cameron TL Double Preventer Pressure controlling devices designed for wellhead service. Various ram designs may be used to seal off open well bores; the annulus around drill pipe, tubing or casing; or shear the drill string. A complete selection of sizes and pressure capabilities to handle any drilling application on land, offshore or subsea. Now days Smart BOPs: Both standard and compact BOPs can be instrumented to sense, quantify and remember pressures, temperatures, on/off status and incremental ram positions. This data can be used for display and control functions in land, offshore and subsea operations
Locking Screw Ram Piston Pipe Ram Body Pipe Ram Top Seal Bore Ring Grove Bonnet Pipe Ram Sealing Elements (rubbers) Upper Flange Pipe ram lifting eye