Job Vacancies in the Oil Industry
Rotary dual wall pipe reverse circulation operations must be used on drilling rigs equipped with hydraulic rotary top drive systems (for single drilling rigs) or with hydraulic power swivel systems (for double and triple drilling rigs) to rotate the drill string. Dual wall pipe is quite rigid and has a much higher weight per unit length than standard single wall drill pipe. Thus, dual wall pipe can be used like drill collars (the lower portion of the drill string can be placed in compression). The dual wall drill string in Figure 3-3 is shown rotating a tri-cone drill bit. The top drive system rotates the entire drill string. The tri-cone drill bits used in reverse circulation operations have the same cutting structures as tri-cone bits used in direct circulation operations. However, the reverse circulation bits are fabricated to allow the compressed air to flow from the annulus between the two walls of the dual wall pipe to the bit rock cutting face. At the bottom of the well the air...
Next to the blowout preventers, the most important component for well control in floating drilling is the system that monitors and controls the behavior of the subsea BOP's from the drilling rig. From 1955 to 1963, the control system design used in subsea drilling was basically a land rig or closed-type system. A hydraulic power unit provided fluid to a shipboard mounted control valve manifold. Hydraulic power lines were run from this manifold directly to each BOP stack function. These hydraulic lines were either run down the riser, were an integral part of the riser, or were huge independent hose bundles, Actuation of a control valve directed fluid to the respective stack function. The opposite function on that ram or other stack component discharged back through the respective power line, through the shipboard mounted control valve, and into the reservoir of the hydraulic power unit. The drilling water depths during the initial years of this period were relatively shallow and the...
Small rotary drilling rigs often use drill rod as a drill pipe substitute. Drill rod is used in mining, environmental, and geotechnical drilling operations. These rods are available in 2 ft, 5 ft, and 10 ft lengths. They are used in both mud (or water) and air drilling operations. There are two types of drill rods, wireline drill rods, and conventional drill rods.
Table B-4 gives the dimensions and mechanical properties of various drill pipe sizes (and nominal weights) and tool joint combinations for API grade E75 1, 2 . The approximate (actual) weight per unit length data given in the table is for a 30 ft drill pipe element (Range 2). In general, API grade E75 drill pipe elements are used on single rotary drilling rigs. These drill pipe elements are usually Range 1 lengths (see Table 1-1). Table B-4 also shows the drill pipe body to tool joint type (either external upset or internal upset), the tool joint connection, outside diameter, inside diameter, tensile yield of the pipe body and tool joint (threaded connection), and the torsion yield of the pipe body and tool joint (threaded connection). The data given for tensile yield and torsion yield are based on the minimum yield of the API grade E75 (i.e., 75,000 psi).
In view of the patent situation, California Talc Company agreed to discontinue the sale of Plastiwate. The announcement was made in oil industry magazines that beginning March 1, 1931, Baroid* would be sold by Baroid Sales Company (a subsidiary of National Lead Company) through distributors in all areas except Louisiana, Mississippi, New Mexico, and Texas, where the Peden Company would be the agent. Aquagel would be sold by Baroid Sales Company in essentially all oilfields of the world. George L. Ratcliffe, formerly president of California Talc Company, became general manager of Baroid Sales Company, which, through the years, has become the Baroid Division of NL Industries, Inc.
The drilling superintendent called a bit company and obtained records on two wells in the section where the prospect well was to be drilled. Although the records were approximately 15 years old, it appeared that the formation pressures would be normal to a depth of 9,800 ft. Since the prospect well was to be drilled to 9,000 ft, pressure problems were not anticipated. The contractor elected to set 10 -in. casing to 1,800 ft and use a 9.5-lb gal mud to 9,000 ft in a 97 s-in. hole. At that point, responsibility would be turned over to the oil company.
The drilling equipment must be run and the inventory checked. The records of the rig's performance should be checked. Are the crews who achieved this performance still there What turnover of crew is there If turnover is high, then find out why. Other oil companies, who have used the rig, should be contacted for comments. Remember, it is the operator who writes the contract. The operator can incorporate as much or as little control as he desires in these contracts. It is probable that in the future, the oil industry will use more and more incentive-styled contracts as a means of motivating contractors towards greater efficiency.
The survey is usually accomplished by using a magnetic single-shot instrument. This instrument is usually part of the equipment inventory of a typical double and triple rotary drilling rig. The magnetic single-shot instrument survey is carried out by the drilling rig crew. The single-shot instrument contains a small compass which floats in a liquid and gives borehole compass direction information. The floating compass is also designed with a half sphere top and an extended pendulum bottom. The spherical top of the compass is etched with a traditional compass rose allowing direction determination when viewing the compass from above down the axis of the instrument. Also etched on the spherical top are concentric circles that represent different angles of inclination from the vertical. When viewing the compass from above and down the axis of the instrument, a set of crosshairs shows the concentric circles of angles of inclination. A small single-shot camera is installed in the instrument...
The Marsh Funnel is a device that is common to every drilling rig. Details of the Marsh Funnel and receiving cup are shown in Figures 1-2, and 1-3. The viscosity is reported in seconds allowed to flow out of the funnel. API specifications call for 1500 ml and one quart (946) ml out.
A further restriction applies to the rotary method. Rotary drilling is widely used and can be adopted to almost every drilling problem, but drilling velocity normaly is not very high and can become extremly low in unfavourable conditions. Rotary cutting with drag bits in soft and medium rock can be effective even with light rigs, but rotary crushing with rock- or roller bits and even more with button bits requires heavy load on the bit to crush the rock when rolling over the teeth (fig. 3). In deep holes as in oil well drilling, the drill string alone brings enough load onto the bit for shallow holes, the required load often exceeds the weight of a light drilling rig, in spite of using heavy tubing. The optimum load increases with borehole diameter Fig. 5 Drilling rig optimised for BHE installation, mounted on all-terrain vehicle Fig. 5 Drilling rig optimised for BHE installation, mounted on all-terrain vehicle
Projected Drilling Time, Time Categories, Time Consideration, Cost Categories, Tangible and Intangible Costs, Location Preparation, Drilling Rig and Tools, Drilling Fluids, Rental Equipment, Cementing, Support Services, Transportation. Supervision and Administration. Tubulars, Wellhead Equipment, Completion Equipment
Figure 3-1 shows a schematic of a standard rotary drill string used to drill deep boreholes with direct circulation. Such a drill string would be used on large drilling rigs. At the bottom of the drill string is the drill bit. The drill bit is threaded (made-up) to a bit sub. The drill bit has a male thread or threaded pin pointing up. The bit sub is a short thick wall pipe that has a female thread or threaded box on both ends. Above the bit sub are the drill collars. Each of the drill collars and most
Non-rotating blade stabilizers can be repaired at the drilling rig location. The worn sleeves can be removed and new ones placed on the stabilizer body. This is an important advantage over the rotating stabilizer. The non-rotating stabilizer is most effective in abrasive, hard rock formations since the sleeve is stationary and acts like a drilling bushing. This action decreases wear on the metal sleeve blades. Such rolling cutter reamers are used when drilling in abrasive, hard rock formations. The gauge of the rolling cutter reamers can be adjusted by replacing the rolling cutter elements on the stabilizer body with different outside diameter elements. Also, damaged rolling cutters can be replaced. These replacements can be accomplished at the drilling rig location. When drilling abrasive, hard rock formations, the gauge of the rolling cutter reamers are usually adjusted to be slightly under the drill bit gauge or at the drill bit gauge. The reamers provide the near-bit stabilization...
The Drawwork console, which looks exactly like the one on a regular drilling rig contains five clutches and rheostat controls that control the drum, rotary table and the pumps (both mud and cement). In addition, the drawwork brake enhances a mechanism for controlling the weight on bit, penetration rate and the lifting of the drill string.
Air and gas drilling operations require a variety of flow line designs from the drilling rig. Drilling operations using compressed air or other compressed gases require the use of large inside diameter flow lines. These return flow lines should be designed not to choke the air or gas flow as it exits the circulating system. This line is known as the blooey line which derives its name from the sound made when a slug of formation water is ejected from the line with high velocity air or gas (see Figure 2-1). Aerated drilling operations require return flow lines that are similar to those of conventional mud drilling operations since volumetric flow rates are very similar. These return lines are usually longer in length than the conventional mud return flow lines. The air in the returning aerated fluid with entrained rock cuttings
Evolutionary processes in the oil industry are slow since there is a natural resistance to change. But these processes are always at work and certain trends forecast the need or desire for subsea completions for oil and gas wells. With this trend worldwide the total offshore acreage under lease has increased rapidly. The Gulf of Mexico sale in October 1974, for example, offered more than 500,000 acres (2,023 square kilometers) to the oil industry. Many oil companies and research groups already have deep water drilling experience, as numerous exploratory wells have been drilled in water deeper than 600 feet. Shell Oil Company has drilled in 2,150 feet of water off the coast of Africa and the Glomar Challenger, a research vessel, has drilled in water well beyond the 2,000 foot mark. The oil companies have shown confidence in the industry's ability to cope with deep water problems through their heavy financial commitments for deep water leases.
A drilling rig in East Texas drilling a 2,800-foot well using earthen mud pits. Cuttings, for geological examination, were collected on a piece of hardware cloth at the end of the flow line. Solids control equipment was not used on this well. In the late 1920s and early 1930s, larger oil companies organized research laboratories and began exploring oil well drilling problems. They began to understand that the smaller cuttings, or particles, left in drilling fluid were also detrimental to the drilling process and another ore dressing machine was introduced from the mining industry the cone classifier. This machine, combined with the concept of a centrifugal separator taken from the dairy industry, became the hydrocyclone desander. The basic principle behind separating heavier and coarser materials from the drilling fluid is the centrifugal action of rotating the volume of the sand-laden mud to the outer limit, or periphery, of the cone. The heavier particles exit the...
Drilling rigs are used to drill the hole, lower and cement casing in the well, and provide a means to perform various auxiliary functions such as logging and well testing. Today's rigs are complicated and require highly experienced, trained personnel for efficient operations. If improperly selected, the rig can be the cause for low penetration rates, formation damage from poor solids control, and high ultimate well costs. Drilling rigs may be subdivided into several component systems for design and sizing. Although the following systems groupings are arbitrary, they serve as a basis for the selection process
After the California Division of Oil and Gas Operations was established in 1915, the employment of engineers in the oil industry began to increase. Usually, the engineers were concerned only with production and little attention was given to drilling.20 Several discussions on the use of mud were reported, however, in Summary of Operations California Oi Fields 2 J and some of these were reprinted in oil industry publications.22 In the late 1920s, several of the major oil companies initiated research into drilling and production practices. Drilling mud was recognized as a colloidal suspension and was accepted as a subject for investigation, primarily by chemists. Sellers of clays emphasized the colloidal character of their products. The development of gel structure when the flow of clay suspension stopped was accentuated as a desirable feature. The superior mud-making qualities of Wyoming bentonite were generally recognized. Mr. Rubel35 initiated a study by Union Oil Company of mud cake...
Mud cleaners are a combination of hydrocyclones mounted above shaker screens with small openings. Mud cleaners can be leased, rented, purchased as independent units, or assembled on location. When mud cleaners were invented in 1971, main shale shakers on drilling rigs were either unbalanced elliptical or circular motion machines. The finest screen at that time could separate solids only larger than about 177 microns (API 80) from a normal drilling-rig circulating rate. Barite specifications restricted solids to sizes predominantly smaller than 74 microns (API sand). Hydrocyclones removed large quantities of barite from a weighted drilling fluid and were not generally used. This meant that all of the drilled solids between 74 and 177 microns were available for removal but could not be removed with equipment available at that time. The mud cleaner was invented to remove those drilled solids. When linear motion shale shakers were introduced, mud-cleaner utility appeared obsolete. Linear...
In large BHE fields, several problems have to be dealt with. To allow completing of more than 100 BHE in a relatively short time, several drilling rigs have to be on site simultanuosly. The available space, the supply of water, BHE pipes and grout, and the disposal of drilling mud all have to be planned diligently in advance. Fig. 10 shows the drilling for the largest central BHE field in the world at Richard Stockton College in New Jersey, USA. Up to four drilling rigs were in use, and the connections in the field have impressive dimensions. Table 6 lists some of the most interesting examples of large BHE fields.
One of the industry's most complex and precisely engineered directional drilling programs was successfully executed to control eleven wild wells which blew out on Shell Oil Company's Platform B in Bay Marchand, offshore Louisiana, in December 1970. A total of five rigs drilled 126,925 feet of hole1 in ten relief wells to control the blowouts with 17 lbs, gal. mud. One relief well was used to kill two wild wells. It took 136 days to bring the Four drilling rigs took 47 days to drill four relief wells to Amoco Production Company's wild wells that blew out on Platform B in Eugene Island, offshore Louisiana, in October 1971. It cost about 9 million to drill the relief wells, fight fires, and control pollution.3 The cost of restoration was estimated at 5.4 million. shown in Figure 3-1 burned for four weeks while Chevron Oil Company amassed the largest collection of pollution control equipment ever marshalled for offshore purposes, as they prepared to snuff the blaze and cap the flowing...
A popular equation for cost comparisons is the total cost per foot equation. The costs used in the equation are dictated by drilling rig operations and fall into four categories bit, trip time, rotating time, and down time accountable to the drill bit. Rotation time is the time consumed while the bit is rotating on bottom with full weight on the formation. Down time is the time consumed other than rotating or trip times. For example, suppose a bit has such a short life that adequate mud treatment can not be accomplished while drilling and that the mud must be treated after the bit is worn out and before a trip is made. Then the time spent treating the mud must be charged to down time. Trip time is the time consumed while running and pulling the drill string for the purpose of replacing the bit. Time for connections is down time.
The surface flow head is the primary closing and safety assembly located on the surface. The surface flow head is attached to the top of the test string, sufficiently high above rotary table to accommodate rig heave. It should have a pressure rating equal to or greater than the maximum expected surface pressure, and have sufficient tensile strength to pick up the weight of the test string to unseat the packer. The assembly consists of various components and the components selected for each test depend on the downhole tools, drilling rig and the test objective. The following components may appear on a surface flow head
A drilling rig has eight lines strung through the travelling block. A hook load of 240,000 lb is being hoisted at a velocity of 50 ft min. Calculate 4. Crake, W. S., Application of Internal Combustion Engine Power to Rotary Drilling Rigs, The Petroleum Engineer, Dec. 1947, p. 70.
Drilling fluid should be processed through the solids-removal equipment in a sequential manner. The most common problem on drilling rigs is improper fluid routing, which causes some drilling fluid to bypass the sequential arrangement of solids-removal equipment. When a substantial amount of drilling fluid bypasses a piece or pieces of solids-removal equipment, many of the drilled solids cannot be removed. Factors that contribute to inadequate fluid routing include ill-advised manifolding of centrifugal pumps for hydrocyclone or mud cleaner operations, leaking valves, improper setup and use of mud guns in the removal section, and routing of drilling fluid incorrectly through mud ditches. Suction and discharge lines on drilling rigs should be as short and straight as possible. Sizes should be such that the flow velocity within the pipe is between 5 and 10 ft sec. Lower velocities will cause settling problems, and higher velocities may induce cavitation on the suction side or cause...
Casing is set 6000 ft from RKB. A 12 ppg mud is required to give a suitable overbalance at 8000 ft. The fracture of the rock is 0.79 psi ft. If a kick was to occur, the maximum pressure without losses (MAASP) on the choke gauge at surface would be 996 psi. Figure 1 - Land Rig, MAASP Figure 1 - Land Rig, MAASP
Fallacious arguments persist that drilled solids are beneficial. Drilled solids are evil and insidious. Increases in drilled-solids concentrations generally do not immediately reveal their economic impact. Their detrimental effects are generally not immediately obvious on a drilling rig so skeptics fail to believe that drilled solids foster the havoc that they truly do. The secret to drilling safely, fast, and under budget is to remove drilled solids. Drilled solids increase drilling costs, damage reservoirs, and create large disposal costs. Specific problems associated with drilled solids are The effects of drilled solids on the economics of drilling a well are subtle. Increasing drilled-solids content does not immediately result in disaster on a drilling rig. When a drill bit ceases to drill and torque increases, a driller knows immediately that it is time to pull the bit. When drilled solids increase, the detrimental effects are not immediately apparent. Decreasing drilled solids...
There are several methods commonly used or available to determine the presence of H2S in drilling fluids. Gas detectors or monitors are used on drilling rigs to detect unreacted H2S gas at the surface. The Hach test is used to detect H2S in the acid form, or as soluble sulfides in the makeup water, filtrate or mud. The Garrett Gas Train also analyzes the soluble sulfides in the filtrate of the mud. In addition, both tests can also determine the total sulfides, both soluble and insoluble, in a mud. It is important that the engineer have a complete understanding of the testing procedures and of the test results being reported.
For many drilling rigs, a set of Picenco SILTMASTERS large enough to process slightly more than the total circulating rate will handle the solids load below good screens. However, they will plug immediately under bypassed screen conditions (unless protected by VOLUMEMASTERS ) and will tend to plug quickly if overloaded (rope discharge) by relatively fast penetration rates in medium and large holes.
The rotary drilling method is comparatively new, having first been practiced by Leschot, a French civil engineer, in 1863. United States patents on rotary equipment were issued as early as 1866 but, as was the case with cable tools, the early application was for water well drilling. It was not until approximately 1900 that two water well drilling contractors, M. C. and C. E. Baker, moved their rotary equipment from South Dakota to Corsicana, Texas where it found use in the soft rock drilling of that area.1 In Texas in 1901 Captain Lucas drilled the Spindletop discovery well with rotary tools. This spectacular discovery is credited with initiating both the Southwest's oil industry and the widespread use of the rotary method. The inherent advantages of this method in the soft rock areas of Texas and California insured its acceptance, and it was in general use by the early 1920's. It is interesting to note that in the 1914-18 period, cable tools drilled 90 of all U.S. wells. At the...
When preparing to drill a vertical or directional well, all operational components of the process are reviewed, optimized and included in a drilling program. The surface location is scouted to determine the best site that will allow for any natural drift, provide suitable access for drilling rig, service rig, production facilities and can be constructed for a reasonable cost. A casing program is prepared to provide 1) adequate well control, 2) prevent water table contamination, 3) maintain wellbore integrity, 4) plan for varying formation fracture gradients, and 5) provide hydraulic isolation of various producing zones.
It is usually incumbent upon the contractor to ensure that his staff have the appropriate certification for their positions. Unless the drilling contract stipulates differently, then that is where the training effort might stop. Clearly, training is an expense for the contractor and if he can get out of spending any extra money on it he can improve his profitability. If the contractor can get the oil company to train his staff at the oil company's expense then this again improves the contractor's profitability. The cost of administering a drilling rig is considerable. To the operator, a smooth contractor administration is required to support an efficient rig. However, any excess administration will be paid for in the day rate directly or indirectly by the rig crews receiving less of the salaries pot. In every aspect of the contract that the oil company pays out, the contractor can make a profit. Most rig comparisons refer only to the day rate, as if it were the only payment involved....
In the case of an oil or gas well blowout, action should be designed to protect human life and control the disaster as rapidly as possible. Very often these catastrophic blowouts are accompanied by fire because ignition sources abound around a drilling floor. Secondary fire problems are caused by the use of ordinary combustibles on drilling rigs and or platforms. If a drilling rig is on location, all engines must be shut down and all feeder lines into the installation must be shut in. All electric power lines in the area should also be cut off. All personnel must be accounted for and evacuated to a safe distance (off of the rig or platform). In the event of an injury, medical and or ambulance service must be called out. These services should be alerted in any event.
The means by which exploration, drilling, petroleum engineering and production interface within an oil company varies between companies. In some cases, these specialisms form distinct departments within the organisation, whereas in others, the structure evolves from a limited number of departments and therefore would involve some combination of specialisms, such as exploration and petroleum engineering or well services and production.
One objective in the measurement of filtration rate is to simulate downhole conditions. Because conditions change so rapidly and frequently it is impossible to duplicate actual conditions downhole, filtration tests have been designed to produce relative measurements which are standardized and accepted in the oil industry. The tests which are made under static conditions include (1) the low temperature-low pressure test, or API fluid loss test, (2) the high temperature-high pressure test, and (3) the permeability plugging test, or PPT. The PPT allows for a larger range of temperature and pressure and allows the permeability of the filter media to be selected.
Calculation of SREE does not require knowledge of the volume of the circulating system if the other information is available. The system has reached a stable drilled solids concentration, and the changes to the system are the primary concern. In actual practice, the system is dynamic, with continuous additions of small amounts of drilling fluid ingredients and continuous discards from the solids-removal equipment. At the drilling rig, sand traps are dumped with a variety of quantities of good drilling fluid. For this reason, these calculations should involve a reasonably long interval of hole to include all of the solids reaching the surface.
Shown below is a sketch of a typical flow loop for rotary drilling rigs. The drill solids are generated by drilling new hole and hole enlargement. Because drill solids accumulate in the annulus, the drill solids are at their highest concentration there. A portion of the solids are removed by the solids removal equipment and a portion are retained. This is called separation of solids'.
Some of the basic techniques involved in hydraulic-rotary coring parallels the techniques of hydraulic-rotary drilling. A drilling fluid is circulated to carry cuttings out of the hole, cool the bit, lubricate the rotating drill pipe, and so forth. Some major components used in hydraulic-rotary coring, such as drilling rigs and mud pumps, may be identical to those used for hydraulic-rotary drilling. However, for most coring operations, equipment can vary considerably see figure 10 for a typical hydraulic-rotary coring rig and associated equipment. Hydraulic-rotary coring does not require the amount of rig power that is needed for standard hydraulic-rotary drilling, nor does it require a large drilling-fluid circulation pump because much less volume of drilling fluid is needed in coring operations. Drill bits used for hydraulic-rotary drilling also vary considerably from those used in hydraulic-rotary coring. Drill bits used for hydraulic-rotary drilling are designed to cut away all...
Depending on the test objectives, the duration of the test may range from a few days to several weeks months. The PT method is often considered to be very time-consuming and expensive, but those concerned with the planning and execution of the test must always judge the duration and cost of testing in relation to the potential rewards and to the overall venture costs. Often, complete production stations and, sometimes, very cosily offshore platforms, are designed on the basis of one or two production tests. In either context, the cost of a few days testing might be quite modest. It may be observed that the time and money spent production testing is a good investment ensuring the profitability of a field development.
A reciprocating pump is a positive-acting, displacement pump, which creates flow by displacing liquid from a cylinder or cavity with a moving member, or piston. Each chamber, or cylinder, is filled and emptied by the mechanical motion of a piston that alternately draws-in and then expels liquid. Available horsepower and the strength of the pump's structural parts determine pressure capabilities. Volume, or capacity, delivered per stroke by a reciprocating pump is constant regardless of pressure. The flow rate varies with changes in piston speed, the diameter of the cylinder in which the piston moves, and the stroke length of the piston. Most reciprocating pumps use multiple cylinders (i.e., duplex, triplex, etc.) to regulate the pulsating flow generated by the reciprocating motion. They are used primarily on drilling rigs as mud and cement pumps. Centrifugal or rotary pumps, except for special applications, have replaced small reciprocating pumps, although they are still used where...
NEMA designs (A, B, C, D, and E) classify motors according to specific torque characteristics for effective startup and operation of equipment under particular loading and operating situations. Design B motors are commonly used on drilling rigs. These are general-purpose motors suitable for normal startup required by pumps, fans, and low-pressure compressors (see Figure 17.11).
Most drilling rigs are equipped with at least one shale shaker. The purpose of a shale shaker, as with all drilled-solids removal equipment, is to reduce drilling cost. Most drilling conditions require limiting the quantity and size of drilled solids in the drilling fluid. Shale shakers remove the largest drilled solids that reach the surface. These solids are the ones that can create many well-bore problems if they remain in the drilling fluid.
Not only would the cost of the clean drilling fluid be prohibitive, but most drilling rigs do not have the surface volume to build 2256 barrels of clean drilling fluid for every 1000 feet of hole drilled. (See Chapter 15 for a complete discussion of dilution calculations.)
Underwater television can be one of the most useful and effective tools available to an oil company engineer. Provided the water is not too turbid, the engineer on deck can see what is being inspected and can often direct remedial action immediately, Video tape recordings allow studies to be made to determine what courses of action should be taken.
Designed for smaller drilling rigs and workover units, the ATL-1200 combines the performance of the ATL-1000 Separator with a lower weir height in a single, compact unit that routinely out-performs larger shakers. The flat (no crown) screen deck reduces liquid loss down the sides of the screens and maximizes usable screen area. The ramp-slope design allows the feed end screens to be operated downhill with the discharge end screens flat for maximum conveyance of sticky solids. With the feed end
Beneficial as an inexpensive substitute for weighting agents. As oil well drilling encountered more and more difficult conditions, hole problems finally became undeniably associated with excessive drilled solids. Frequently, production horizons near the surface were normally pressured and could be drilled with unweighted drilling fluids. Usually, these drilling conditions were relatively trouble free, and a poor-quality drilling fluid was used for drilling. Of course, drilling performances and well productivity could be enhanced with better-quality drilling fluids, but those effects were difficult to quantify. As these areas graduated from unweighted drilling fluids to weighted drilling fluids, better drilling-fluid properties were required to prevent trouble. The primary problem was that large quantities of drilled solids were intolerable. The drilling trouble costs could easily be traced to failure to limit drilled-solids concentration. This provided the impetus for most drilling...
Most starch products are used in salt and saturated saltwater environments. Most of the starches used in the domestic oil industry are made from corn or potatoes. The starch grains are separated from the vegetable and specially processed so that they will rapidly and efficiently swell and gelatinize to reduce filtration loss. The sponge-like pegs also fit into the tiny openings left in the filter cake and lower fluid loss by a plugging action. Biocide is recommended when bacterial degradation is a concern.
Can be installed outdoors if desired. These units arc suitable for crude oil or gasoline pipe line service either main line or booster and similar high pressure applications. Three sizes are available, a 4 size with 200-lip. motor, a fj size with 400 hp. motor and an 8 size with 700 hp. motor which will take care of a pumping range of from' 7COO to 38,000 barrels per day against 800 pounds pressure. These units are known as the Rannetl type after the inventors Messrs. Moran and Bennett, and were developed and built by Allis-Clialniers. This highly advanced, new type of pipe line pumping unit is now made available to the oil industry for pipe line pumping service. Additional information will be furnished on request.
The two filter types most often seen in the oil industry are the bed type (usually a bed of diatomaceous earth) and the disposable cartridge type a washable cartridge type is also available, but less frequently used. The diatomaceous earth filter consists of a rack or frame which supports the beds of filter medium (see Figure 1).
Satellite surveys Growing use is being made of satellites with infra red imaging techniques to detect potential subsurface deposits of hydrocarbons and other minerals. This technique will find economical application in many areas of the world and is likely to be more widely applied by the oil industry in the future.
Air and gas drilling operations require some special surface equipment not normally used in rotary mud drilling operations. Shallow drilling operations usually have this specialized equipment incorporated into the single rotary drilling rig design. For the deeper drilling operations that use double and triple rotary drilling rigs, this specialized surface equipment is usually provided by an air and gas drilling equipment contractor. These contractors supply the rotary drilling contractor (the drilling rig) with the necessary surface equipment to convert the mud drilling rig to an air and gas drilling rig. The rotary drilling contractor and the air and gas drilling contractor are usually contracted by an operating company.
Modern drilling rigs may be equipped with many different types of mechanical solids removal devices depending on the application and requirements of a particular project. Each device has a specific function in the solids control process. Equipment commonly utilized and the effective removal range for each are listed in Figure 3-1.
API RP 500B Recommended Practice for Classification of Areas for Electrical Installations at Drilling Rigs and Production Facilities on Land and on Marine Fixed and Mobile Platforms.* Another remote panel is sometimes located in the toolpusher's office. One control station should be located at least 50 feet from the centre line of the wellbore.
Offshore drilling rigs are often purchased on the basis of the unit's classification. Insurance rates are dependent as well on the classification of the unit. The governments of Norway and Britain also now require offshore units to be certified for fitness before they can drill in their waters. What procedures are involved in classification and certification of a drilling unit Secondly, what are the requirements for obtaining the appropriate classification or certification
The purpose of a drilling rig surface fluid processing system is to provide a sufficient volume of properly treated drilling fluid for drilling operations. The active system should have enough volume of properly conditioned drilling fluid above the suction and equalization lines to keep the well bore full during wet trips.
On some drilling rigs, the derrick rig floor is not high enough to allow some shale shakers to be used because the flowline is not high enough. Small land rigs frequently have difficulty positioning larger shale shakers so that the flowline has sufficient slope to prevent fluid from overflowing the bell nipple. Whichever shaker or shakers are used, consideration must be given to providing sufficient safe power to the shaker motors. Check with the manufacturer about electrical service needed for the shaker used.
Since the majority of diving tasks from a drilling rig can be accomplished within 30 minutes total bottom time, it is possible, with good operational planning and experienced divers, to effectively use bounce diving techniques to about 600 feet. Tasks requiring longer bottom times can be accomplished with back to back diving techniques using a second deck decompression chamber and additional divers. Saturation can be used effectively from 300 feet, but would probably only be justified if unusually long bottom times were required. Such capability is more applicable to construction work rather than drilling. Below 600 feet, bottom times must be limited to avoid prohibitively long decompression times.
Regardless of reputation, many drilling engineers were attracted to diamond bits because of the ability of being able to stay on the bottom and drill for longer periods of time. During the late 1950's several major oil companies began research programs on diamond bits, and these studies provided a much better understanding of the mechanics of diamond bit drilling and the influence of hydraulics on the penetration rate. This, plus subsequent developments of more erosion resistant matrix materials, led to performance levels in the 1970's which provided cost savings on a regular basis.
James Merrill has been involved in the design and manufacturing of shale shakers and shale shaker screens for the past 17 years in the petroleum, mining, and utilities business sectors. His vast knowledge of wire cloth and shaker screens has allowed him to solve screen problems around the world. His career has taken him from a roughneck on drilling rigs around the Gulf Coast to Technical Manager of a leading solids control company. construction and upgrades in Europe, the Far East and North America. Mike began his career in North America with Seismogrph Service Corporation, moving into international operations with Amoco International Oil Company, as a drilling engineer. Mike has worked as a Drilling Foreman, Drilling Supervisor, Drilling Superintendent and Drilling Manager throughout his career. He holds a BS degree in mechanical engineering from the University of Connecticut and is a registered professional engineer in the state of Texas. He has supervised inititiatives such as...
Marathon Oil Company Blowouts are of two types, surface blowouts and subsurface blowouts. Surface blowouts are possibly accompanied by fire, explosion, pollution, third party damage, and property damage to the drilling rig and platform. They also expose the company involved to potential unsatisfactory public opinion. If the blowout is uncontrolled, a valuable reservoir may be needlessly depleted. On the other hand, a subsurface blowout which leaves no impression on the surface can be equally devastating to a hydrocarbon reservoir. Although less spectacular, the subsurface blowout can be more difficult to control.
Reverse circulation can also be carried out using air and gas drilling techniques. Figure 1-8 shows a typical application of reverse circulation using compressed air as the drilling fluid (or mist, unstable foam) 7 . This example is a dual tube (or dual drill pipe) closed reverse circulation system. The closed system is characterized by an annulus space bounded by the inside of the outer tube and the outside of the innertube. This is a specialized type of reverse circulation and is usually limited to small single and double drilling rigs with top head rotary drives. Dual tube and dual drill pipe are available from a number of manufacturers in the United States and elsewhere in world (see Chapter 3 for drill pipe details).
Drill collars are thick walled tubulars that are used at the bottom of the drill string (see Figure 3-1). Their principal purpose in the drill string is to provide the axial force needed to advance the drill bit (see Figure 1-2). When drilling a vertical borehole, the axial force is the weight of the drill collars. Drill collars are available in API range lengths given in Table 1-1. Figure 3-16 shows a BHA with Range 2 ( 30 ft long) drill collars. Range 2 lengths are typical for double and triple land rotary drilling rigs. Also shown in Figure 3-16 are short drill collar lengths used to adjust positions of the stabilizers in the BHA. These shorter drill collar lengths are selected from Range 1 stock of drill collars.
The rotating head or a similar air flow diverter was developed for use in air and gas drilling operations to keep air or gas with entrained rock cuttings from flowing to the drilling rig floor through the rotary table kelly bushings. Diverting this drilling fluid flow from the drilling rig floor is mandatory for all air and gas drilling operations. Even on small drilling rigs the air exiting the annulus (direct circulation) must be diverted in order to provide a safe work space for the rig operators. These diverter devices were developed with the introduction of air and gas drilling operations in the early 1930's. (see Figure 2-7). Typically the BOP is used for all deep wells. The type of rotating head shown in Figure 2-8 is used with large drilling rigs. Direct circulation or reverse circulation drilling operations can be carried out with these rotating heads. This particular rotating head is available in a 8.25 inch bore design (Model 8000) and a 9.00 inch bore design (Model 9000)....
All air and gas drilling operations require the use of a rotating head (or similar air or gas flow diverter) which is installed below the rotary table. The blowout preventer (BOP) stack is always used when subsurface overpressured dangerous gases or fluids might be encountered while drilling (i.e., oil and natural gas drilling operations, and geothermal drilling operations). Figure 2-7 shows schematics of three typical wellhead assemblies for double and triple drilling rigs set up for air and gas drilling operations to recover oil and natural gas, or geothermal fluids 6 .
Figure 1-6 shows a schematic of a rotary drilling, direct circulation mud system that would be used on a typical double (and triple) drilling rig. Direct circulation requires that the drilling mud (or treated water) flow from the slush pump (or mud pump), through the standpipe on the mast, through the rotary hose, through the swivel and down the inside of the kelly, down the inside of the drill pipe and drill collars, through the drill bit (at the bottom of the borehole) into the annulus space between the outside of the drill string and the inside of the borehole. The drilling mud entrains the rock bit cuttings and then flows with the cuttings up the annulus to the surface where the cuttings are removed from the drilling mud by the shale shaker the drilling mud is returned to the mud tanks (where the slush pump suction side picks up the drilling mud and recirculates the mud back into the well). The slush pumps used on double (and triple) drilling rigs are positive displacement piston...
The smaller drilling rigs have on-board water injection pumps. These smaller rig water injection pumps have capabilities from 10 to 25 gal min. The small water injection pump carries out the same objective on these smaller rigs as the skid mounted water pump for the larger double and triple drilling rigs. The injection of water and appropriate chemicals and foamer is a vital option for air and gas drilling operations. Very few air and gas drilling operations are carried out without some water, chemical additives, and foam producing additives being injected.
Figure 2-1 shows the blooey line exiting from the drilling rig annulus for direct circulation operations. Blooey lines (or equivalent) are required for all air and gas drilling operations and are needed to keep drilling rock dust and cuttings away from the drilling rig and rig personnel. Blooey lines must be secured to the ground surface with tie-downs (see Figure 2-1). The high velocity of the air or gas flow from the well will interact with the flexible blooey line to set up an aerodynamic flutter situation which is very similar to the motion of a water hose on the ground when the water valve is turned on. This flutter situation can result in high dynamic forces and resulting blooey line movement. This potential movement must be constrained along its length by tie-downs to the ground. The typical length of the blooey line for large drilling rigs is from 100 ft to 300 ft. This line is run from the annulus to a burn pit (see Figure 2-1). The air or natural gas drilling fluid with the...
Dual wall drill pipe elements are used exclusively in reverse circulation drilling operations. This type of drill pipe is used for drilling shallow ( 3,000 ft or less) water wells, environmental monitoring wells, geotechnical boreholes, and mining boreholes. These rotary drilling operations can be a) rotation of the dual wall pipe drill string with a tri-cone or drag type bit, b) rotation of the dual wall pipe drill string with a standard downhole air hammer (with standard air hammer bit), or c) rotation of the dual wall pipe drill string with a reverse circulation downhole air hammer (with reverse circulation air hammer bit). These rotary drilling operations are carried out with hydraulic top drives (for single rotary drilling rigs) and with power swivels (for double and triple rotary drilling rigs).
Each of the compressors is equipped with independent gauges to assess its operating performance. In addition to the compressor gauges are those placed along the flow line. A low pressure gauge is placed downstream of the primary compressors but upstream of the booster compressor. This gauge allows assessment of the performance of the primaries. A high pressure gauge is placed downstream of the booster compressor to assess the performance of the primaries and booster when high pressure compressed air is required. Pressure gauges are also placed upstream and downstream of the water injection pump and the solids injector. These gauges allow assessment of the performance of these injection systems. All these gauges must be high quality gas gauges. Most drilling rig floors are equipped with a mud
1.2 Drilling Rigs The large investments required to drill for oil and gas are made primarily by oil companies. Small oil companies invest mostly in the shallow, less-expensive wells drilled on land in the United States. Investments in expensive offshore and non-U.S. wells can be afforded only by large oil companies. Drilling costs have become so great in many areas that several major oil companies often will form groups to share the financial risk. Many specialized talents are required to drill a well safely and economically. As in most complex industries, many different service companies, contractors, and consultants, each with its own organization, have evolved to provide necessary services and skills. Specialized groups within the major oil companies also have evolved. A staff of drilling engineers is generally identifiable as one of these groups. Fig. 1.3-Typical drilling rig organizations. Fig. 1.3-Typical drilling rig organizations. rotary drilling rigs Fig. 1.5-Classification...
Nearly all air and gas drilling operations are land operations. Figure 2-1 shows a typical air drilling location plan for the drilling rig and the other important surface equipment 1 . The plan in this figure shows the location of the drilling rig (borehole directly below the rotary table). This is a typical triple drilling rig configuration. The drilling rig floor is larger and, therefore, it is easier to show the important features of an air drilling operation with this type of rig. This rig is a typical mud rotary drilling rig that has been set up to drill with compressed air as the circulating fluid. The rig is powered by two prime movers on the rig floor. These prime movers provide their power to the rig equipment through the compound (a chain drive transmission system). The prime mover on a triple rotary drilling rig like that shown in Figure 2-1 is limited to operating either the rotary table or the drawworks (hoist system), but not both simultaneously 2 . The development of...
Drilling rigs, and their support vessels in the case of barge and floating vessels, have high power requirements. Some of the equipment requiring power includes the drawworks, mud pumps, rotary system, and life-support system. The power loading may be continuous or intermittent. Fig, 16-17 Semi submersible drilling rig (Courtesy Western Oceanic Inc.) Fig, 16-17 Semi submersible drilling rig (Courtesy Western Oceanic Inc.) The power system on a drilling rig usually consists of a prime mover as the source of raw power and some means to transmit the raw power to the end-use equipment. The prime movers used in the current drilling industry are diesel engines. Steam boilers are rarely used in present operations due to the difficulty in transporting the boilers and the fact that greater widespread knowledge of diesel units exists among crewmen. A drilling rig is working in an arid climate at an elevation of 3,600 ft. During the day, the peak temperature is 105 F. The minimum temperature...
When primary control of the well has been lost due to insufficient mud hydrostatic pressure, it becomes necessary to seal the well to prevent an uncontrolled flow, or blowout, of formation fluids. The equipment that seals the well is the blowout preventer (BOP). It consists of drillpipe blowout preventers designed to stop the flow through the drillpipe and annular preventers designed to stop flow in the annulus. The drilling rig must be evaluated to determine if its BOP equipment meets the minimum specifications. Otherwise, it is common to rent the proper equipment.
Once the pilot hole is successfully drilled, the hole is often enlarged to a suitable diameter for the product pipeline. For instance, if the pipeline to be installed is 8 inches in diameter, the hole may be enlarged to 12 inches or more. This is accomplished by reaming the hole to successively larger diameters. Generally the reamer is attached to the drill string on the bank opposite the drilling rig, rotated, and pulled (pushed in some instances) back through the pilot hole. Joints of drill pipe are added as the reamer makes its way back to the drilling rig. Large quantities of slurry are pumped into the hole to maintain its integrity and to flush out cuttings. While soil conditions do have an impact, the required number of reaming runs is mainly dependent on the diameter of the product pipe and the diameter of the pilot hole. It may vary from no reaming runs to several for large-diameter product pipes.
Gas detectors (gas sniffers) are used only in air drilling operations directed at the recovery of oil and natural gas. Figure 2-14 shows the position of the gas detector on the blooey line. This detector can detect very small quantities of hydrocarbons that might enter the blooey line from the annulus. As the drill bit is advanced and hydrocarbon producing formations are drilled, the hydrocarbons are entrained in the return air flow to the surface with entrained rock cuttings. The detector alerts the drilling rig crew that hydrocarbons are in the annulus. This alert allows rig personnel to take safety precautions against subsurface and surface fires or explosions.
Figures 2-1 and 2-14 show the burn pit at the exit end of the blooey line. The burn pit should always be located away from the standard mud drilling reserve pit (water storage for an emergency mud drilling operation). This design of pit location prevents any hydrocarbon liquids from flowing into the reserve pit, thus, preventing reserve pit fires near the rig. The burn pit is located downwind from the drilling rig. Such a location keeps the smoke and any dust from the drilling operation from blowing back over the drilling rig. The burn pit must be lined with an impermeable layer of commercial clay to prevent contamination of surrounding soil and ground water. Usually the burn pit is designed with a high berm ( 6 ft) at one side of the pit (opposite the exit from the blooey line). This berm prevents high velocity rock particles and liquid slugs from passing over the burn pit. The burn pit is part of the drilling site location preparation.
The 'GK' annular preventer is designed for surface installations and is also used on offshore platforms and subsea. Standard operation requires both opening and closing pressure. Seal off is affected by hydraulic pressure applied to the closing chamber, which raises the piston, forcing the packing unit into a sealing engagement. Main features include
Augers (screw conveyors) are commonly used to move drilled cuttings and associated fluid. They can be arranged to collect the cuttings (usually relatively dry oil-based cuttings) from the individual pieces of solids-control equipment and convey them to another area of the drilling rig where they are used to load cuttings boxes (skips). The standard screw conveyor is composed of an auger or screw housed in a flanged, U-shaped trough with bolt-on covers. It is powered by an electric motor and equipped with an appropriate gearbox. The motor must be sized to provide enough horsepower and torque to permit the transport of cuttings at a rate at least equal to the maximum rate at which they are delivered to the screw. The feed and discharge ends are fitted with flanges and ports to allow the cuttings to flow into and out of the conveyor without plugging. For multiple screw sections, hanger bearings are used to support the ends of the screw sections where they are joined. Operating parameters...
Boxes are the primary method of transporting waste drilling fluid and cuttings to shore around the world. Boxes were developed as an easy method of collecting and transporting cuttings given the weight restrictions of offshore cranes on earlier drilling rigs. Boxes are typically placed near the solids-control equipment, where cuttings can be moved relatively short distances and collected in the box. When a box gets full, it is removed and an empty box is shuffled into position. When a sufficient number of full boxes are ready, they are backloaded onto a workboat and returned to shore. Empty boxes from the dock facility replace the returned boxes.
The bullnose port is large enough to accommodate all lines which might be required for operation of the well. In the original installation for Shell Oil Company, the flow-line bundle was made up of two 2 -inch diameter lines, one IVi-inch diameter line, an electrical cable with 34 conductors, and a small-diameter hydraulic hose.
The addition of trip tanks to drilling rigs significantly reduces the number of induced well kicks. The obsolete or old-system drillers filled the hole with drilling fluid with the rig pumps by counting the mud pump strokes (the volume was calculated for the displacement of the drill pipe pulled). The problem here was that a certain pump efficiency was
The rig shaker is the simpler of two types of shale shakers. A rig shaker (also called Primary Shale Shaker or Coarse Screen Shaker ) is the most common type of solids control equipment found on drilling rigs. Unless it is replaced by a fine screen shaker, the rig shaker should be the first piece of solids control equipment that the mud flows through after coming out of the hole. It is usually inexpensive to operate and simple to maintain.
Even though shales may be soft, they are not good candidates for jetting. Most medium-strength rock is too well cemented to jet with conventional drilling rig pumps, so it limits the depth to which jetting can be applied. Higher pressures and more hydraulic energy can extend the depth to which jetting is practical.
The wells are designed to permit drilling, landing the tree, and completion using a conventional floating drilling rig. Tub-ingless completions are a part of the prototype SPS, as this design fits the requirements of the system. The wells will have the capability of vertical reentry workover if necessary.
The usual criticism of turnkey drilling by operators is their lost of control over operations. This is true with most existing turnkey contracts, but as mentioned earlier in this section, it is the operator who writes the contract. If you want control, write it into the contract. Most oil companies have very definite standard procedures covering BOP, stack testing and drilling practices. It is possible to write a turnkey contract insisting on these and ensuring that they are monitored. If the contractor did not like the contract then he would not sign it so nothing would be lost.
Originally, the objective of a drill stem test was to take a representative fluid sample which, in the very early days of the oil industry, was obtained by either bailing or swabbing. Following the introduction of a packer and a downhole valve, the next step was the possibility of recording accurate bottomhole reservoir pressures and temperatures. With the development of downhole tools, which operated on annulus pressure and a downhole shut-in valve with surface read-out, drill stem testing has become a generally accepted safe method to meet the original objectives to obtain a fluid sample and reservoir data. In a drill stem test, information on the following parameters can be obtained at a point where the formation is competent enough to allow it to seal. Drill pipe is run in the hole, either empty, or with a water cushion and, by manipulating the string valves, the formation under test is allowed to flow into the drill pipe. Due to the strong manipulation required, this type of test...
HDD is a multi-billion-dollar annual industry with hundreds of contractors and thousands of drilling rigs operating on five continents. HDD in North America has grown from 12 operational units in 1984 to thousands of units today. This rapid growth is attributed at least partially to
Once the drilled hole is enlarged, the product pipeline can be pulled through it. The pipeline is prefabricated and usually tested on the bank opposite the drilling rig. A reamer is attached to the drill string and then connected to the pipeline pull head via a swivel. The swivel prevents any translation of the reamer's rotation into the pipeline string, allowing for a smooth pull into the drilled hole. The product pipe has to be supported for the pullback operation. This is usually accomplished on rollers or with some type of crane or backhoe. Caution has to be exercised during the pullback to ensure that the product pipe or its coating is not damaged. Often breakaway links that fail before pullback loads exceed the safe limits of the product pipe are utilized. The drilling rig then begins the pullback operation, rotating and pulling on the drill string and once again circulating high volumes of drilling slurry. The pullback continues until the reamer and pipeline break ground at the...
A walkover system consists of a transmitter, receiver, and remote monitor. A battery-powered transmitter is located in the bottom hole assembly near the front of the drill string it emits a continuous magnetic signal. The receiver is a portable, handheld unit that measures the strength of the signal sent by the transmitter. This information is used to determine the drill head's position, depth, and orientation. The remote monitor is a display unit installed at the drilling rig in front of the operator. It receives and displays the information provided by the receiver. This information is used to navigate the drilling head below the surface. The data is recorded to provide the as-built profile of the bore path. When access to a location directly above the bore-hole alignment is not possible or when the depth of the bore exceeds 100 feet, other types of navigation systems should be used. Two systems commonly employed are the magnetometer-ac-celerometer system and the inertial navigation...
Prior to the use of centrifugal pumps on drilling rigs, the standby reciprocating mud pumps were customarily used to operate the mud hopper. As with high-pressure mud guns, this required high-pressure pipe and connections. This was costly because the pump required enormous power and expensive piping. A small orifice in the hopper delivered a low flow at a high velocity. The jet velocity was suitable for adequate mixing, but the volume was usually less than 500 gpm. This, of course, would limit the speed of material addition. Since the 1950s the centrifugal pump has been the predominant tool for charging mud hoppers on drilling rigs. This permits the use of low-pressure equipment and the movement of large volumes of fluid rapidly. Savings were realized through reduced piping cost and higher addition rates that lowered operating cost. It also released the standby main pump from mud mixing duty.
As pointed out earlier, the original flow-line connection for Shell Oil Company wets accomplished using a preformed line with external TFL loops pulled by a winch within the service capsule. With the horizontal wellhead cellar design, the flow line approaches the cellar from the ocean floor and is lifted at a slight angle to align the flow-line bundle's bullnose with the cellar's bullnose port.
The entrance angle of the drill string should be between 8 and 20 degrees, with 12 degrees considered optimal. Shallower angles may reduce the penetrating capabilities of the drilling rig, while steeper angles may result in steering difficulties, particularly in soft soils. A recommended value for the exit angle of the drill string is in the range of 5 to 10 degrees.
4) BHA equipment and drill pipe must be inspected by non-destructive tests, as specified in the drilling rig contract, by the drilling contractor and any time as required by the ENI-AGIP representative. For severe or particular difficult drilling conditions refer to the 'Drill String Bottom Hole Assembly Monitoring Procedures For Severe or Particular Drilling Condition (STAP-M-1-M-5008)'. As a general rule, the following guidelines should be used
The flow line to the standpipe of the drilling rig acts as a manifold collecting the compressed air outputs from the primaries. These flow lines are API 2 7 8 inch (OD), or 3 1 2 inch (OD) steel line pipe (or ASME equivalent) 5 . The valves in the flow line at the booster compressor allow the air flow from the primaries to be diverted to the booster when high compression of the air is needed. When higher compression is not needed the booster compressor is isolated with the check valves in the flow line to the rig.
Within the oil industry, there are three recognized kick control procedures. 1) Driller's, 2) Weight, and 3) Concurrent. The selection of which to use will depend upon the amount and type of kick fluids that have entered the well, the rig's equipment capabilities, the minimum fracture pressure in the open hole, and the drilling and operating companies well control policies. Determination of the most suitable and safest method (assuming their company policy allows flexibility of procedures determined by the demands of the situation) involves several important considerations
Land drilling rigs do not have reserve tanks in their systems. Extra tanks are rented as needed for their operation. These tanks are typically called fractionalization (frac) tanks. Marine drilling rigs incorporate reserve or storage tanks in their design. The volume and number of these tanks depend on the space available and the available deck load capabilities of the rig. If more storage volume is required for marine drilling rigs, extra storage tanks can sometimes be installed on deck depending on space and deck load availability.
An accelerator is a chemical additive used to speed up the normal rate of reaction between cement and water which shortens the thickening time of the cement, increase the early strength of cement, and saves time on the drilling rig. Cement slurries used opposite shallow, low-temperature formations require accelerators to shorten the time for waiting-on-cement . Most operators wait on cement to reach a minimum compressive strength of 500 psi before resuming drilling operations. When using accelerators, this strength can be developed in 4 hours. It is a good practice to use accelerators with basic cements because at temperatures below 100oF, neat cement may require 1 or 2 days to develop a 500 psi compressive strength.
Drilling contractors like oil companies are in business for one thing only to make money. Oil companies have several ways of making money, but drilling contractors have only one. The contract, therefore, is vital to the contractor's profitability and hence even a mediocre contractor will be very aware of the methods of extracting funds from a contract.
All HDD installation work should be performed according to the design documents and in accordance with any permit agency requirements. Before beginning construction activities the HDD contractor should become familiar with the work area and the technical requirements of the project plans. The project limits and controls should be identified by marking or staking prior to any construction to indicate the HDD entry and exit locations and the proposed HDD alignment, using no greater than 50-foot intervals. The desired location for the entry and exit points should be established after the geotechnical and topographical surveys. When choosing the relative locations of the entry and exit points, it is important to note that steering precision and drilling effectiveness are greater close to the drilling rig. Where possible, the entry point should be located close to anticipated adverse subsurface conditions.
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