Ministry of Science and Technology Department of Technical and Vocational Education Petroleum Engineering Department SAMPLE ANSWER FOR A.G.T.I FIRST YEAR 29.9.2006 (Friday) Time: 8:30 am to11:30 am PE-01011 Principle of Petroleum Engineering Attempt any five questions 1. Explain the origin of petroleum and describe the productive formations. The earth’s crust is composed of essentially of three types of rocks, igneous, metamorphic and sedimentary. Although oil and gas are found in three kinds of rocks, they are mostly associated with sedimentary rocks. Sedimentary rocks come from a variety of source, but in general are laid down on the earth by the action of wind and water, or through chemical deposition (like leaching). These sedimentary materials can be classified as (1) rocks (sand, stone, shale) (2) carbonates (certain limestones) and (3) dolomites. Although sedimentary rocks are associated with oil, not all sedimentary rocks contain oil. In order of petroleum to be present, most scientists theorized that the remain of plant and animal life, as well as the remain of certain temperature and pressure were needed. So, how did this environment occur? Early life began, in vast sea and inland lake, that covered the large portions of the present continents. As the abundant populations of marine plant and animal life died, their remains were buried rapidly and preserved in the slit and mud that continuously filtered down to the ocean floor. Rivers carried great volumes of mud and sands to be spread by currents and tides over the ever- changing seashore line. This joined the marine life remains that settled to the bottom of the sea and deltas and were repeatedly buried. The mud and seawater protected the material from further decay. As more and more layers of organic material, sand, slit, clay and lime accumulated and time passed, the weight of the overlying sediments exerted great pressure on the deeper sedimentary layers. With the increasing weight of the accumulating sediments, the sea floor slowly sank, forming and preserving thick sequences of mud, sand and carbonates. These eventually formed into sedimentary rocks. This tremendous pressure along with the high temperature, bacterial action and chemical reactions- caused the formation of crude oil and natural gas. 2. Explain the different types of bits. Before discussing about the drilling bits, I want to express different types of bit. They are one of the main factors which to a considerable elements. The bits are classified into three general types. (1) Drag type (2) Rolling cutter ( roller bit) (3) Diamond. (1) Drag bit Drag bit has no moving parts and drilled by the shoveling action of their blades on the encountered formation. Their water courses are placed such that the drilling fluid is directed on the blades, keeping them clean. Bits of this type were once widely used for drilling soft, sticky formations, but in recent years have been largely replaced by rolling water types. The bades are manufactured from various alloy steels and are normally hard- faced with tungsten carbide. (2) Rolling cutter bit There are different types of rolling cutter bit, designed according to the different kinds of formation. The first successful rolling cutter bit was designed by Howard R Huge in 1909.In these type of bit, rolling cutter bit are most widely used all over the world. Because drilling bit are justified in many area, where there long life and reduction in drilling cost. There are two types of rolling cutter bits, cone bit and cross- roller bit as shown in fig. Row of teeth are cut into the rolling member, so that these bits are also referred to as tooth- wheel bit. The surface of bit teeth is covered with tungsten carbide, in order to longer bit life. Hardness of steel is used in rock bits in about six to seven ( orthoclase , feldspar or quartz). The tooth-wheel ratates independently, as the drill string rotated, the rolling cutter turn by the virtue of their contact with the bottom of the hole. The recent adaptation for drilling of very hard rocks has been the substation of rounded tungsten carbide insert in place of the bit teeth ordinarily cut on the roller and these lather bits are also referred to as bottom bit as shown in fig. Depending on the design of their cutter, rolling cutter bit drills the rocks crushing rumbling action or chipping the combination of crushing chipping action. With respect to the size of mud fluids discharged ports and their arrangement, rolling cutter bit are classified as conventional or as jet bits. (2.1)Jet bits Jet bits are rolling cutter bits which have been equipped with fluid nozzles. Each nozzle directs a high velocity fluid jet directly on the hole bottom which rapidly removes the cuttings. This allows each bits tooth to strike new formation rather than expend some of its energy in regrinding previously lessened chips. The pressure losses through these nozzles are considerable and require extra pump capacity. (3) Diamond bits Diamond bits drill by a scraping, drag bit action of these stones which provide from a steel matrix. Their use is justified in many areas where their long life and the consequent reduction in trip time afford sufficient advantage to offset the higher bit cost. The actual cost of a diamond bit is the initial cost less, a salvage which is paid according to the weight of undamaged diamond remaining after the bit’s use. This commonly ranges from 25 to 75 percent of the initial cost. Diamond bits are normally used in hard formations. There are two types of diamond bit and cone bit are shown in fig. 3. Explain the advantages and disadvantages of positive displacement meter for liquid and gas. Advantages and disadvantages of positive displacement meter for liquid These flow meters are especially useful when the fluid to be measured is free of any entrained solids. Wear of parts introduces the major source of error over meter service life. Leakage error increases with lower viscosity fluids but remains relatively constant with time. In the large meters temperature variations and the resulting change in fluid density and viscosity must by taken into consideration. Positive displacement meters provide good accuracy (0.25% of flow) and high rangeability (15: 1). They are repeatable to 0.05% of flow. Some designs are suited for high or variable viscosity services. They require no power supplies and are available with a wide variety of readout devices. Their performance is virtually unaffected by upstream piping configuration. Positive displacement meters are excellent for batch processes, mixing, or blending applications. These meters are simple and easy to maintain by regular maintenance personal using standard tools. No specially trained crews or special calibration instruments are needed. Positive displacement meters require relatively expensive. Precision machined parts to achieve the small clearances upon which their accuracy depends. From this it follows that the liquid metered must be clean, for wear rapidly destroys accuracy. Contaminant particle size must be kept below 100 microns and most of these meters are mot adaptable to the metering of slurries because of the moving parts, maintenance is required at frequent intervals where corrosive liquids are metered this may result in high costs. Due to close tolerances the moving components are subject to wear and therefore the meter requires periodic recalibration and maintenance. Positive displacement flow meters are expensive in larger size or in special material. They can be damaged by over speeding and can require high non lubricating, or abrasive services. Advantages and disadvantages of positives displacement meter for gas. Advantages -Inherent high accuracy and good reproducibility -Available in wide range of materials -Good reliability and acceptability is high -Relatively insensitive to upstream flow conditions -Operation is based on simple principles -Designs available for metering wide range of gases -Some designs do mot require external power -Excellent for totalizing in remote locations -Most general application industrial designs are rugged Disadvantages -Suitable over limited pressure and temperature ranges -Meters are larger in size than some equivalent flow rate meters -Can be damaged by particles in the flow and filtration is often required -Not suitable for dirty or two phase flows -High performance types are expensive -Head losses can be high and increases with viscosity and flow rate -Pulsations are introduced into the flow -Usually applicable for unidirectional flows only 4. Write on the cable tool drilling and rotary drilling. In the cable-tool method, drilling is accomplished by lowering a wire line or cable into the hole. On the end of the line is a heavy chisel- shaped piece of steel called the drilling bit. An up and down motion is applied to the line at the surface. This churning action chips small pieces of rock from the formations. The bit, which weights several hundred pounds, is continuously dropped until a few feet of hole have been drilled. At this time, the line is raised by a drum at the surface and the bit is removed. Then a bailer, a metal pipe with a one way flapper valve on the lower end is lowered into the hole on another line called the sand line. The chips cut by the drilling bit are picked up in the bailer and removed from the hole so drilling can resume. In cable tool drilling, no significant amount of fluid is circulated in the hole. A small amount of water is desirable, however; if no water comes from the formations, a few gallons are dumped down hole. Often a cable tool rig drills only one tenth as fast as a rotary rig in comparable formations. However, the cost of a cable tool rig is substantially less than a rotary rig. This tends to compensate for its slower drilling rate. A distinct disadvantage of the cable tool method is that when high pressure oil and gas formations are encountered, there is no fluid in the hole to control them. The result is frequent blowouts. When a blowout occurs, the oil and gas from the subsurface formation rush to the surface and flow uncontrolled. A blowout may spray the oil and gas several hundred feet into the air and there is always great danger of a fire. Because of its slow penetration rate and the hazard of blowouts, the cable tool method is seldom used in wells deeper than3000ft. Even on shallower wells, this method has largely bin replaced by the rotary method. Rotary drilling In rotary drilling, a bit used to cut the formation is attached to steel pipe called drill pipe. The bit is lowered to the bottom of the hole. The pipe is rotated form the surface by means of a rotary table, through which is inserted a square or hexagonal piece called a Kelly. The Kelly, connected to the drill pipe at the surface, passed through the rotary table. The turning action of the rotary table is applied to the Kelly, which is turn rotate, the drill pipe and the drilling bit. Routine drilling consists of continuously drilling increments the length of one joint of pipe, making connections or adding to the drill string another single joint of pipe, generally 30 or 45ft long. This drilling continues until the drill bit must be changed. Changing the bit is also called making a trip. Three principal types of bits are used in a rotary drilling operation: (1) drag of fish- tail bits, (2) rolling- cutter bits more commonly called rock bits and (3) diamond bits. Most drilling bits are rock bits. A drilling rig consists of many components. These components are (1) mast, (2) the draw works, (3) engines, (4) the mud system, and (5) drill string. The mast or derrick is the structure placed over the well to help remove the pipe from and lower equipment into the hole. The draw works is the hoisting equipment. The engines drive the mud pumps and draw works and provide power electricity. The mud system is comprised of the mud pumps, the mud tanks, the mudflow lines, and the circulating hose. The drilling is the entire rotating assembly and consists of the Kelly, drill pipe, drill collars, and drill bit. At the bottom of the hole, the cuttings, or pieces of formation cut loose by the drilling bit are removed from the hole continuously through the circulation of drilling mud or fluid. 5. Describe the different typed of casings. (a) Conductor pipe Conductor pipe is the conduit that also raises drilling fluid high enough above ground level to return the fluid to the mud pit. And it prevents washing out around the rig’s base. Conductor pipe is set after the well location has been graded and prepared for the rig. Then the pipe is lowered into the hole and concrete is poured around it to fill the surrounding space. In swamps and offshore locations, the pipe is driven in with a pile driver. Offshore, the diameter of the pipe can range from 30-42 in, while onshore diameters are usually smaller 16-20 in. (b) Surface casing The next casing to be set is surface casing, which protects fresh water sands from contamination by oil, gas or salt water from the deeper producing formations. Since freshwater formations normally occur at shallow depths; no more than 2000 ft of surface casing are usually required. An important auxiliary function of the surface casing is to provide a place to attach the blowout preventers. Once the well is completed a production manifold or Christmas tree replaces the BOP. The outside diameter of the surface string is slightly smaller than the inside diameter of the conductor pipe. The surface casing is lowered inside the conductor pipe. The minimum depth is usually 10% of the expected total depth (TD) of the well or 500 ft. When the expected depth is reached, this string of casing is cemented to the surrounding conductor pipe. (c) Intermediate casing An intermediate casing, through not always run, protects the hole against loss of circulation in shallow formation. When drilling in areas that have abnormal formation pressure, heaving shales, or lost circulation zones, a string of casing may need to be run to minimize hazards before drilling to greater depths. Intermediate casing strings are suspended and sealed at the surface with a casing hanger. The lower portion is cemented by circulating cement down and out around the bottom of the pipe and up across the intervals where cement is needed. (d) Liner strings Unlike casing that is run from the surface to a given depth and overlaps the previous casing, a liner is run only from the bottom of the previous string to the bottom of the open hole. Liners are suspended from a previous string with a hunger. They are often cemented in place but may be suspended in the well without cementing. One advantages of using a liner is that it is not necessary to run the string back to the surface. Sometimes liners are set in a hole as a protective string, serving the same function as an intermediate string. (e) Production casing Production casing is sometimes known as the oil string or the long string. It isolates the oil and gas from undesirable fluids in the production formation and from other zones penetrated by the well bore. This casing also serves as the protection housing for the tubing and other equipment used in a well. The oil string is the last string of casing run in the well. It is a continuous length of pipe from the well surface to the producing formations. 6. Explain the different types of artificial lift methods for producing well. Gas lift A special type of gas lift is the plunger lift system for wells producing small amounts of fluids. An accumulator chamber for well fluids is installed at the lower end of tubing. When enough fluid has accumulated, a plunger pushed these fluids to the surface. Power for forcing the plunger to the surface is supplied by high pressure gas. When the plunger reaches the surface, the high pressure gas below the plunger is released, and the plunger drops back to the bottom of the tubing until its next trip to the surface. Gas lift is widely used as an artificial lift technique in offshore operations. Continuous flow gas lift is the preferred method of gas lifting offshore wells since the high and low pressure piping systems are usually of limited capacity. There are many onshore gas lift installations as well. Rod Pumping This is probably the most well known and widely used artificial lift technique. It consists of a subsurface pump at the bottom of the tubing, which is connected to the surface pumping unit by a string of sucker rods. These rods are run inside the producing tubing. The pump consists of an outer cylinder, pump barrel and an inner piston, or pump plunger, each fitted with a specially designed check valve. The pump barrel can be run into the well as part of the tubing string or it can be run in with rods and latched to the tubing. Subsurface electrical pumping A subsurface electrical pump is a specially designed centrifugal pump with a shaft that is directly connected to an electric motor in fig. The whole unit is sized it may be lowered into the well with an insulated cable extending from the surface through which electricity is supplied to the motor. The operation is controlled by a surface control box. Pump capacity may vary from 200 to 26000 b/d depending upon the depth from which the fluid is lifted and the size of casing. Subsurface hydraulic pumping Subsurface hydraulic pumping is a method of pumping oil wells using a bottom hole producing unit consisting of a hydraulic engine and a direct coupled positive displacement pump. The hydraulic power required is supplied from a pump at the surface. This system uses two strings of tubing alongside the other to the small string may be installed inside the larger tubing. Clean crude oil ((power oil) from the high pressure pumping pumped down the larger size tubing to the hydraulic engine which in turn causes the power piston to stroke (fig). This strokes the direct coupled production piston in the bottom hole pump. Fluid from the well and the exhausted power oil become mixed and return to the surface settle tank and piped to the pump for recirculation. In some instances, clean water is used as the power fluid. It is possible, by using this pumping system, to pump several wells using a central source. Another type of hydraulic pumping well system is the casing free pump. It requires only one string of tubing set on a casing packer with power oil going down the tubing string and power oil and production fluids being returned in the tubing casing annulus.
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