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get to know the common types of mining equipment - equipment & contracting

get to know the common types of mining equipment - equipment & contracting

The multi-billion-dollar global mining equipment market is growing at a rapid rate. As in an expected compound annual growth rate (CAGR) of 12.7% through 2027. Technology is, in part, driving sales. Although machines are getting smarter, the types of equipment used in mining have largely remained the same. In this article we discuss common types of mining equipment.

There are five basic categories of mining equipment. Drills, blasting tools, earth movers, and crushers. The last category is a group of machines that move material to and through the crusher then analyze the mined material.

There are many different types of drilling activities at mine sites. Generally, they fall into two major categories: exploration and production. The goal of exploration is to provide detailed information about a proposed mining site. The goal of production is to access and extract raw material for other uses, such as building roads.

Whether its oil and gas, diamonds, or construction materials, drills are used to access the material underground. Drills are also used to prepare an area for blasting. In coal mining, drills are used to create portals for workers to enter the mine.

The type of drill selected depends on the drill method used which in turn depends largely on the type of material being mined. For example, reverse circulation (RC) drilling is often used in mineral exploration. In RC drilling, a hammer (actually a pneumatic reciprocating piston) drives a drill bit made of tungsten-steel into the rock. Air is blown down the rods, creating differential pressure. This drives the material back up. With RC drilling, you can drill down up to 500 meters. However, its not always the best solution for diamond mining: it sometimes can break larger stones.

There are many different types of drill bits, including spiral pointed bits, cone type bits, and diamond-coated bits. Diamond-coated drill bits are made of very low-quality diamonds; there value comes from their cutting strength.

Blasting tools are used in underground and open pit mining. The desired material is usually found along with other waste material. Blasting tools are used to break down the material so it can be sorted. Blasting is also used to remove areas of rock that are blocking access to the production material. Blasting is very dangerous work and requires a high-level understanding of explosives, detonators, and much more.

Both the production material and waste material need to be handled once they are extracted (or blasted). Excavators, with their long arm and bucket attachment, are used to remove materials, such as coal. Dump trucks and haul trucks move the excavated material around and off the mining site. Bulldozers help create a flat surface for other heavy equipment to travel over. These heavy machines require experienced operators.

The first material excavated from the mine needs to be broken down to sort and transport it. Crushers are used for this purpose. Strip mining operations use haul trucks to transport the material to the primary crusher. Whereas in underground mines, conveyers are used to move the material to the crusher. Crushers reduce the cost of transporting large, heavy pieces of rock.

There are three classifications of crushers: primary, secondary, and tertiary. The primary crusher handles what comes out of the mine. (Known as run of mine or ROM.) Then this material is fed into the secondary crusher to further reduce the size. The material is then further processed by the tertiary crusher. However, the material may continue to go through crushers to meet the desired size. In fact, some material is reduced to dust.

Conveying equipment moves the excavated material to a feeder. The feeder pushes or feeds the material into the crusher. The equipment controls how fast the material is fed into the crusher. It determines whether the material has been reduced to the desired size. If not, it feeds the larger pieces back into the crusher. Online elemental analysis equipment can be used to take periodic samples of the material to provide data in real-time. This information is used to ensure quality and streamline processes, such as sorting and blending.

There are several different types of equipment used in mining. Although the machines continue to evolve, they perform many of the same functions as they did in the early days of mining. They provide access to production material, move it, crush it, sort it, and haul it. Mining equipment gives us access to the basic materials needed to create items we use every day from roads and bridges, gasoline for our cars, even beautiful jewelry.

View the complete article here. The information in this article focuses on the proper inspection of embankment construction, with the goal of ensuring a solid, good, lasting embankment. Not only will the embankment withstand the []

View the complete article here. By its very nature, mineral exploration involves drilling to discover what is below the surface. While there have been a number of advances in drilling technologies in drilling techniques in []

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drilling equipment - an overview | sciencedirect topics

drilling equipment - an overview | sciencedirect topics

Drilling equipment that is broken or stuck in the hole can be dissolved by means of nitric and hydrochloric acids mixed in a proportion of 1:3. To accelerate the dissolving of the metal, a mixture containing 1.1 parts of sodium nitrate and 1.0 part of monoethanolamine is added initially to the acids in the amount of 0.0513.0 parts per 100 parts of acid mixture. The acidic residue in the hole is neutralized by addition of alkali and converted into drilling fluid by addition of polymer solution (Dolganskaya and Sharipov, 1992).

Walking drilling equipment is located at the end of the high deck of a pillar supporting a drilling barge, and can move by land if necessary to the beach/shallow sea region to drill into the sea. When the wells are located in the tidal flat areas, not fit for sailing, the equipment goes by land. When the wells are located in beach-shallow sea area that can be sailed, you can go from the sea to the well location. The Victory II Chinese design is an example of this walking drilling equipment, is put into use in 1988. That walking drilling platform was first proposed by with a conceptual design by Yi, chief engineer of the Chinese Academy of Engineering, and patented by the Shengli oil field Drilling Research Institute and Shanghai Jiao Tong University Design and Development. This walk-up drilling platform works for water depth less than 8 m, has a drilling depth of 7620 m, scale of 75.24 m 43.14 m 12.6 m, and a 4500 m electric drive moves the rig. Walk type platform composes of the inner body and the outer body, and the outer body is mat and can sit on the bottom. There are vertical and horizontal directions for the cylinders on the platform. When the inner body and the outer body is fixed to the inner body or outside the body in turn in the fluid, cylinder is driven to the vertical or horizontal direction step line, with each walking stroke of 10 m. In this way, you can crawl in the beach area.

As quickly as the exploratory wells give successful results, feasibility studies are carried out in order to define the new actions of the project, which are mainly focused on locating wells to be drilled. With the technical support of exploratory wells, these wells are drilled with the clear objective of finding the thickness and production depth.

Temperature and pressure profiles, logged approximately every 400m, using resting time series of 0, 6, 12, 18, 24, and 30h. The objective is to determine the profiles in undisturbed state and the static pressures and temperatures to be used in the numerical models of the reservoir.

If the well presents thermodynamic characteristics of production, its surface facilities, valves, pipes, silencer, measuring instruments (manometers, thermometers, and sampling holes) should be enabled to make a discharge test to different openings and develop the initial characteristic curve of the well production.

Determined parameter values from wells drilled at this stage of field development are useful for designing mechanical well completions, which are related to production thickness and capacities of surface production equipment. Due to thermodynamic bottom conditions prevailing in geothermal systems, only thermodynamic parameters (temperature and pressure) are logged with mechanical tools. However, these measurements are used for determining interval thickness, depth, static level, and the thermodynamic state of the fluid wells, among others. The graphs shown in Figs. 7.9 and 7.10 show the correlation of the temperature and pressure profiles of different wells, used for defining the characteristics of the conceptual model.

With information on each well, the conceptual model of the field can be developed in order to carry out the simulation of different exploitation scenarios in order to go forward with the power generation plant capacity design. With known well production parameters, their characteristic production curves are defined in order to be used for continuous exploitation. The next step is to develop the feasibility report, which should include these elements:

This stage is characterized by the growth of the field in production wells and the increase of the production flow until the supply requirements of the generation plant are satisfied. Also, an environment-friendly eviction of the brine produced must be sought through reinjection wells.

During this stage, the development of transient pressure tests for the wells that are finishing drilling is continued as far as possible. The results of these tests are useful for characterizing the reservoir in its undisturbed state.

Generally, a hydraulic drilling equipment spread has a smaller footprint than a conventional drilling rig. This is, in part, because hydraulic drilling usually involves smaller hole sizes requiring smaller drill string diameters, smaller OD and lighter BHAs, and smaller mud systems and pumps that require only the circulation rates necessary to clean the hole. All of this means less areal space is required on the wellsite for the equipment spread.

Less equipment, lower pump rates, and smaller horsepower requirements also mean less fuel consumption and fewer air emissions. There is less equipment on the location, so exposure risk to leaks or spills is reduced. Smaller hole sizes also mean that a smaller cuttings volume must be handled, and the risk of a cuttings spill is also reduced.

The snub drilling spread may be required to drill the same size holes as the conventional drilling rig. It does not have a substructure and mast, however, and most of the other equipment is smaller. So, the snub drilling spread will usually have a smaller footprint than a conventional drilling rig.

Some items on the snub drilling site may be the same size as those on a conventional drilling rig such as the mud logger's shack, the MWD/LWD and computer facilities, and supervisors' offices. Pipe will still be staged, picked up, and run in the hole. On most rigs, each joint must be pulled and laid down on a trip out of the hole as well. Some racking systems allow the drill string to be stood back in singles or doubles. This further reduces the footprint of the snub drilling equipment.

The weights of most of the individual pieces of equipment are usually less than those on a conventional drilling rig. So, offloading and spotting them requires smaller lift equipment and is less complicated. For packaged rigs, such as an offshore jack-up rig, this does not apply. Onshore, much of the work in spotting equipment is done by tandem-axle gin pole trucks, so the crane comparison does not apply. Inshore equipment spreads still require a crane to load and position equipment on barges, however.

Most onshore conventional drilling rigs are designed to be self-contained and sized to manage the deepest, largest-diameter hole and casing string that the derrick and substructure are rated to handle. Because onshore rigs may not have to deal with compressed locations, there is little need to place the equipment items close together.

Often, the mast and substructure require extra lifts and truckloads. This is not the case with snub drilling equipment since there is no heavy substructure and mast involved in snub drilling. Many conventional rig substructures are self-elevating and most of the derricks are raised by the drawworks. However, a crane is sometimes required to erect both. A crane is usually required to assemble the unit and BOP stack in a hydraulic unit drilling spread.

Mud systems on conventional rigs are also sized for the largest and deepest hole capable of being drilled by the rig. On many conventional rigs, over 1,000bbl total mud system capacity is required where snub drilling rigs may only require a quarter of that volume. Similarly, conventional rigs need pumps that can clean large-diameter holes. Some have two large pumps; others have three. Usually, only two smaller-capacity (and lower-horsepower) pumps are required for hydraulic unit drilling.

The result of the smaller equipment package for hydraulic unit drilling often means that there are fewer mobilization and rig-up costs associated with this type drilling. Mobilization cost for an offshore jack-up rig is quite expensive. The rig must first rig down, deballast, and free itself from the seafloor at the previous location before moving to the new well, either under its own power or towed by large tugs.

Once the jack-up is spotted, the spud cans and legs must be jacked down to lift the rig above the waterline while avoiding punch-through (penetrating the sea floor unexpectedly). The rig must be preloaded with seawater pumped into the ballast tanks to place weight on the spud cans. This is commonly done to ensure stability before the rig is raised to the proper height to drill. Then, the drilling package must be cantilevered out to the well centerline above the wellhead deck. Only then can the drilling package be extended and rigged for drilling. Several days or even weeks may be required to perform this work depending on weather and sea conditions. The hydraulic unit package is rigged up on the platform floor, and aside from hoisting individual lifts from the transports, rigging up and drilling is sea-state-independent. Costly delays are unnecessary.

Inshore locations normally use canals to reach existing wellsites in marshes or swamps. Shallow draft barges can navigate these canals with little difficulty. A large, bottom-supported conventional jack-up drilling rig might require widening and deepening an existing canal that has partially filled in over time. A dredging permit is often required. All dredging is expensive especially when one considers the cost of spoil disposal.

Environmental concerns may delay or prohibit securing a dredging permit from regulatory agencies especially when the routes to the well or the well itself are in sensitive areas. In some cases, these areas became sensitive after the original hole was drilled. Securing a dredging permit in these areas is improbable, at best, even though there is an existing well at the end of the canal. So, new drilling operations on old inshore wells may not be possible at all using a conventional rig. The smaller footprint of a hydraulic unit drilling spread mounted on barges is certainly attractive in these situations.

The RCD is installed on top of the BOP directly onto the annular or an adapter spool. It safely diverts well returns, such as pressurized gas, fluids, and cuttings to a surface separation system during UBD applications.

The RCD is a key component of Schlumberger's managed pressure drilling (MPD) and UBD service offerings, and can also be provided as a stand-alone service as required. It includes a sealing element made of urethane and utilizes wellhead pressure to form a positive seal on the drillstring. Depending on the application, well returns are diverted through the side outlet of the RCD body to a choke manifold/surface recovery system or directly to the rig shakers.

Choke systems are based on the principle of creating a restriction in the flow path of return flow from the well. This creates a back pressure on the well, which is translated downhole as a change in bottom-hole pressure. By virtue of this capability, the choke can be opened or closed to allow a variation in the resulting back pressure, changing the bottom-hole or annular pressure profile in real time. This is the basic principle applied in UBD operations.

Choke operators no longer have to handle the controls during transition operations, such as mud pump start-up or shut-down, or when mud and gas are flowing alternately through the choke. The ability to automatically regulate casing pressure greatly simplifies the process of managing pressure. It should be noted, however, that the connection procedures involving multiphase operations that need drillstring bleed offs, equalization of pressures between RCD and stack, and stabilization of gas injection rates will still need skilled personnel at the rig site.

The AUTOCHOKE also makes stripping pipe simpler and safer by maintaining casing pressure. As the drillpipe is lowered into the hole, an equal volume of fluid is automatically displaced through the choke allowing the bottom-hole pressure to remain constant.

The low pressure AUTOCHOKE console (LPAC) is uniquely adapted to UBD operations because they typically require less than 500 psi backpressure. Achieving precise backpressure control with a 10,000 psi choke is challenging. The LPAC meets that challenge and is widely used in UBD applications. One advantage of the LPAC system is the precise digital adjustments it can make to the programmable logic controller (PLC) remote operation; this allows real time adjustment of set point pressures on the choke, thereby making the back pressure control process safer, faster, and more precise compared to standard joystick or wheel controlled chokes.

Typical UBD manifolds consist of two choke-legs to provide redundancy and a gut line which allows bypassing the chokes as required. The manifold sizes can vary from 36 in. for typical land operations.

Entrained and produced gas must be separated and vented or flared. The Mud Gas Separator (MGS) is used to remove the free gas from the drilling fluid and is typically the first piece of equipment the drilling mud encounters when it reaches the surface.

Depending on the design, the mud gas separator vessel may be pressurized to a specific rating or held at atmospheric pressure. In addition a MGS may be designed to separate two, three, or four phases, meaning that they can separate solids and multiple types of fluid comingled in the return flow stream. During separation the drilling fluid returns have a typical retention time of 12 minutes in the MGS.

Vacuum degassers are more efficient degassers, but have lower throughput capability (see Figure 11-9). They are better suited to lower flow rate mud systems with high gas cuts or systems that are very sensitive to entrained gas. Vacuum degassers require a separate mud pump to operate the eductor nozzle, which can drive up the initial cost of installation.

Centrifugal degassers employ centrifugal forces to separate the gas from the fluid by exerting centrifugal force to the mud, multiplying the force acting on the gas bubbles to increase buoyancy and release. The increase in buoyancy accelerates the bubble-rise velocity. As the bubbles rise toward the surface, they escape the mud and are further broken down by flow turbulence. A light vacuum is pulled by a regenerative blower to vent the gas. The freed gas and the gas-free mud are then separately discharged as desired.

The gas-flow meter is particularly useful in tight-gas reservoirs while drilling underbalanced. A meter like the M-I SWACO CARBONTRACKER measures gas-flow velocity, temperature and pressure to determine the actual and standard volumetric flow, as well as mass flow rates. It is installed in the flow line between the MGS and the flare stack and is accurate at flow velocities as low as 0.1 ft/sec (0.03 m/sec). It creates no obstructions in the flare line and meets drilling well control and industry code requirements (see Figure 11-10).

During UBD operations it can help characterize tight gas reservoirs, determine the location of productive gas zones and production rates, and provide an indication of the true production potential of a reservoir. That allows operators to make accurate, more cost-effective decisions because it allows them to avoid relying solely on expensive log data to predict production zones. In addition, it can also provide quantitative data for carbon emissions reporting that the global environmental protection community will require.

Inventions in this regard involve a method for geosteering directional drilling equipment, such as horizontal drilling equipment, that can provide real-time formation information. Included are techniques for real-time location identification for a drilling bit during directional or horizontal drilling. One or more embodiments of the software program can be used for horizontal and directional drilling and can utilize various geologic and seismic curves including curves. The drilling discussed herein can include drilling for an oil well, a natural gas well, a water well, or any another type of subsurface well drilling. The method can include using computer software designed to import and export WITS-compliant information. WITS, as used herein, stands for Wellsite Information Transfer Specification.

The computer software can enable a user of the method to receive and send updated drilling and seismic survey data from a plurality of formats, such as WITSML, WITS, Log ASCII Standard (LAS), different streaming formats, different logging formats, and other formats installed for use. The receiving and sending of updated drilling and seismic survey data from the plurality of formats can occur in real time, such as in a matter of seconds.

One or more embodiments of the method can be used: solely in the field adjacent a drilling site; remote from the drilling site, such as at an office; at sea on a subsea well site; or simultaneously from various remote and field locations. The method can include using an executive dashboard program that can be used to present data to a plurality of users simultaneously and in real time. The executive dashboard can allow users to simultaneously view numerous pieces of data and information associated with the drilling.

The method can enable users, which can be computers, to more efficiently and effectively determine stratigraphy, dipping, and faulting by using graphical matching of actual curve data against reference curves, such as type log curves, using real-time drilling data.

The method can help users visualize formation structures by allowing users to explore formation structures in three dimensions and in two dimensions, and to explore different segments of a stratigraphic section or map simultaneously, thereby allowing the users to determine where a drilling bit is within a wellbore. The method can therefore be used to avoid disasters associated with formation problems, such as unexpected faults and the like.

One or more embodiments of the system for geosteering, also referred to as geosteering of directional drilling equipment, can include a processor in communication with directional drilling equipment and with a data storage. The communication can occur through a network. The processor and the data storage can be used to receive and send data to the directional drilling equipment and to control at least portions of the directional drilling equipment. The directional drilling equipment can include mud pumps, mud tanks, drilling pipe, controls, directional tools installed on a drill string, and similar conventional directional drilling equipment. The data received from the directional drilling equipment can be an inclination of the wellbore as measured by a directional drilling tool, such as a sensor or gyro; a measured depth of the wellbore, such as a measured depth measured by a depth encoder on a crown of the drilling rig; a tool depth, which can be the measured depth minus the distance of the tool from the bottom of the drill string; an azimuth as measured by a sensor on a directional drilling tool; and actual curve data such as ray readings and resistivity readings as measured by sensors on directional drilling tools. The processor can send data and/or commands to the directional drilling equipment or to user's operating the directional drilling equipment, such as user's viewing the executive dashboard at the drilling site. The data and/or commands can include all of the data that can be presented in the executive dashboard as described herein and a suggested build rate to remain at a target depth or in a target formation, as well as other instructions regarding drilling. The commands can be commands that directly control the directional drilling equipment, suggestions and/or instructions to users on how to control the directional drilling equipment, or combinations thereof.

The data storage can include computer instructions to instruct the processor to import data including an actual survey of the wellbore. The actual survey data can include a plurality of azimuths for the wellbore, a plurality of inclinations for the wellbore, a plurality of measured depth points for the wellbore path, and other data and information associated with an actual survey of the wellbore. The actual survey data can be stored in the data storage using computer instructions and can be presented within the executive dashboard.

The data storage can include computer instructions to instruct the processor to import data including a geological prognosis on the wellbore site to a prognosed tops table, which can then be stored in the data storage. The geological prognosis can include at least one depth for at least one formation top, a formation top through which the drill bit is expected to pass along the projected path, and other information. The prognosed tops table can be presented in the executive dashboard.

The data storage can include computer instructions to instruct the processor to construct a wellbore profile, to save the wellbore profile in the data storage, and to present the wellbore profile in the executive dashboard. The wellbore profile can include a composite visualization of a plurality of TVD of the wellbore, as can be more easily understood with reference to the figures in the following.

The data storage can include computer instructions to instruct the processor to use the imported data to form a stratigraphic cross section in the wellbore profile. The data storage can include computer instructions to instruct the processor to position the actual location of the drill bit onto the stratigraphic cross section. The stratigraphic cross section can include a depiction of a formation dipping away from an angle perpendicular to a horizontal plane representing the surface surrounding the wellbore. The stratigraphic cross section can include a depiction of a formation dipping toward the angle perpendicular to the horizontal plane representing the surface surrounding the wellbore.

The data storage can include computer instructions to instruct the processor to superimpose the projected path for the drilling bit over a formation structure map and to position the formation structure map behind the projected path to establish faults in the formation relative to the projected path and/or the actual drilling path. The formation structure map can be imported and/or inputted into the data storage from an external source and saved therein and can include a calculated stratigraphic cross section before the wellbore has been drilled.

The data storage can include computer instructions to instruct the processor to superimpose the projected path for the drilling bit over stratigraphic cross section and to position the stratigraphic cross section behind the projected path to establish formations simultaneously both in two dimensions and in three dimensions.

The data storage can include computer instructions to instruct the processor to form at least one report. Each report can include any information imported and/or inputted into the data storage; any information and/or data stored in the data storage; any data received from the directional drilling equipment; any information and/or data presented within the executive dashboard; any information and/or date included within the various reports described herein; any information and/or data associated with the wellbore, the drilling equipment, and the drilling process; or combinations thereof. Similarly, the executive dashboard can present any information imported and/or inputted into the data storage; any information and/or data stored in the data storage; any data received from the directional drilling equipment; any information and/or date included within the various reports described herein; any information and/or data associated with the wellbore, the drilling equipment, and the drilling process; or combinations thereof.

The data storage can include computer instructions to instruct the processor to plot an actual drilling path on a real-time basis in view of the projected path and to transmit the plot along with images and a text report to a plurality of users simultaneously over the network for presentation on the executive dashboard.

The executive dashboard can include a report for a wellbore of current information. The current information can include a current measured depth, such as 10,500 feet, which can be adjustable using an onscreen control button. The current information can also include a current formation name, such as Selman Formation. The formation name can be procured from an offset/type log table that the processor can obtain from communicating with another data storage accessible through the network.

The data storage can include computer instructions to instruct the processor to compute the current dip or dip angle. The current dip or dip angle, as the term is used herein, can be the angle of a formation referenced from the horizontal plane representing the surface surrounding the wellbore. In operation, if the angle is positive and the angle points toward the surface or is shallower, the current dip or dip angle can be referred to as dipping toward the wellbore, whereas if the angle is negative and the angle points away from the surface or is deeper, the current dip or dip angle can be referred to as dipping away from the wellbore.

The data storage can include computer instructions to instruct the processor to present a current TVD in the executive dashboard, which can represent the distance measured at the angle perpendicular to the horizontal plane representing the surface surrounding the wellbore to the drill bit using the kelly bushing as a reference point on top of the wellbore. Related patents are listed in Table3.8.

Corrosion fatigue is responsible for most of drill pipe failures. Fatigue strength (endurance limit) can be defined as the unit stress that a metal can endure for a large number of cycles of stresses. Stress levels are usually expressed as a percent of yield strength (see Jones, 1988).

Pits form on the inside of drill pipe as a result of corrosion due to presence of dissolved oxygen. These pits increase the stress and initiate a fatigue crack, which is propagated to failure upon cyclic stressing.

As pointed out by Cron and Marsh (1983), the economic impact of drill pipe corrosion is immense. The cost of a joint is $12,000, but the fishing job in the case of pipe break-off will cost $40,000/day rig time. If the fish cannot be recovered, then the well is lost, resulting in a multimillion-dollar loss. Thus, a corrosion-control program should be initiated initially: an ounce of prevention is better than a pound of cure!

Often, drilling fluids are used as packer fluids in the annular area of wells after completion. If not properly treated, this drilling fluid can cause costly corrosion problems late in the life of a well. Water-base and oil-emulsion drilling fluids (oil-in-water) may attack the metal surfaces in contact with it in the casing if not properly treated. The type of corrosion involved is electrochemical corrosion.

Numerous conditions encountered during drilling operation cause corrosion to the drilling equipment. Hydrogen sulfide (H2S) and carbon dioxide (CO2) are commonly encountered in drilling deep wells. Hydrogen sulfide, which reacts with iron at the pipe surface, forms iron sulfide (FeS), liberating two hydrogen atoms that permeate steel and lead to corrosion. Carbon dioxide, which forms carbonic acid (H2CO3) in water, has a similar reaction with steel, i.e., iron carbonate forms, releasing hydrogen atoms that attack steel (Magcobar Services, 1972, Corrosion, Sect. 19). Oil-base drilling muds are very effective in reducing corrosion to the drilling equipment, because the continuous oil phase prevents the completion of the galvanic cell, which is necessary for corrosion to take place (Magcobar Services, 1972, Corrosion, Sect. 19). Certain chemicals, when added to the oil-base muds, make the steel surface oil-wet and protect it against corrosion. Because of different drilling conditions, drilling fluid cost varies widely. The most important factors that affect the cost of drilling are as follows:

Special drilling fluid systems are available either for reducing the severity of or eliminating corrosion. The cost of the drilling fluid, however, is increased as a result. For example, the use of oil-base drilling fluid in place of water-base mud eliminates the problems of cement and salt contaminations; however, it is very costly to change (switch) the mud type.

The cost of drilling fluid increases with increasing size and depth of the well because of the higher volume of the fluid required. Logistics is also responsible for high drilling fluid cost, because materials that have to be transported a long distance will cost more than those that are available locally. Consequently, there are no typical drilling fluid costs. For example, drilling fluid cost alone for different wells in the west Texas area drilled to a depth of 15,000 ft can vary from $20,000 to over $30,000 (1977 prices, Allen, 1977, P. 4).

In this chapter, after a brief outline of the floating drilling equipment and subsea systems, the riser components and vessel data are outlined. This chapter also presents various methods of riser analysis. Floating drilling risers are used on drilling semisubmersibles and drilling ships. As the water depth increases, integrity of drilling risers is a critical issue. The design and analysis of drilling risers are particularly important for dual operation, dynamically positioned (DP). Two different types of risers are used for installation and intervention in and on a well: completion risers and workover risers. A completion riser is generally used to run the tubing hanger and tubing through the drilling riser and BOP into the wellbore. A workover riser is typically used in place of a drilling riser to reenter the well through the subsea tree and may also be used to install the subsea tree. From a structural analysis point of view, a drilling riser is a vertical cable, under the action of currents. The upper boundary condition for the drilling riser cable is rig motions that are influenced by rig design, wave, and wind loads. One of the key technical challenges for deepwater drilling riser design is fatigue of VIV due to (surface) loop currents and bottom currents.

On 18 February 1924, Elvin E. Townsend filed for a patent on well drilling equipment that was, in fact, the first snubbing unit (Fig. 1.1). This device had a movable frame that could be raised and lowered along with a stationary frame connected to the wellhead. Each frame contained a set of slips to hold pipe in compression, and each contained a sleeve with 24 metal reinforcing arms that would affect a seal around the pipe, an annular blowout preventer (BOP).

The movable frame was raised and lowered using two hydraulic cylinders manifolded together for uniform lifting power. The two cylinders and the two annular BOPs operated using well pressure routed through pipes to each device. The slips on each frame were manual screw-type slips. The screws were run in to grip the pipe, and run back out to release the slips.

This device was intended to be used with the drilling rig that hoisted the pipe (i.e., a rig-assist snubber). The movable frame repositioned the traveling annular BOP and slips to get another discreet section, or bite, of pipe. The cylinders then pulled the pipe in the hole as the blocks were lowered. When coming out of the hole, the traveling frame held the compressive force back on the pipe in short bites to keep the string from being expelled from the well.

The most important part of this invention was the annular BOP. The element with its steel fingers became the basis for the first general use of annular preventer later used on almost every rig. This portion of the invention was purchased by the Hydril Company and is referred to in subsequent literature as the Townsend Hydril packer (Fig. 1.2). The similarities to current-day annular BOPs are obvious.

It is not known whether this snubbing unit was ever actually built. The basis of design is such that it could have been used for pipe-light conditions as a rig-assist unit. Later designs of a similar type were used in the field.

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