Ministry of Science and Technology Department of Technical and Vocational Education Petroleum Engineering Department SAMPLE ANSWER FOR B.E PE – Advanced Drilling Engineering 1. Explain the pneumatic tensioning system for a marine riser system. (20 Marks) Solution The Pneumatic Tensioning System: Most floating drilling vessels are now equipped with an arrangement of pneumatic cylinders. These are designed to provide pneumatically controlled tension for each of several lines attached to the marine riser. Tow equipment manufacturers now market units suitable for this service. One common riser-tensioning unit has a 12-in. diameter piston acting within a cylinder, with dual 42-in. diameter sheaves mounted on opposite ends of the unit. The unit has a 10-ft piston stroke but, through sheaving of the lines, provides compensation for 40 ft of vessel movement. Air pressure up to 2,200 psi acts on the pistons to exert line tensions up to 60,000 lb. the rod end of the cylinders are filled with a hydraulic fluid to perform the dual purpose of dampening the action of the piston and lubricating the packing. The principal components of the unit then are: the cylinder with the air-balanced piston and sheaves; an air-oil reservoir to supply hydraulic fluid to the piston end of the cylinder; and air accumulators that supply air to the high-pressure side of the piston and regulate the tension (Fig. 4.17). Most drilling vessels today are equipped with four of these units, or have a rated line- tensioning capacity of 240,000 lb. a few vessels are equipped with six, or a rated line- tensioning capacity of 360,000 lb. from a practical standpoint, the units probably should not be used on a continuous basis to supply more than about 80% of rated load, or 48,000 lb per unit. This would mean that the 4-unit and 6-unit installations actually have a continuous line- tensioning capability of 192,000and 288,000 lb, respectively. Some problems have been reported with piston leakage when operating at higher than the 80% capacity loads. New designs of pneumatic tensioners incorporate an oil bath on each side of the piston that may increase the life of the packing on the piston and extend its performance capacity. The pneumatic tensioning system has proven helpful in landing and latching the subsea blowout-preventer package on the subsea wellhead. When the preventer stack has been run on the riser pipe, the tensioners are connected to the telescopic joint just before landing the stack. The weight of the riser and stack are then suspended on the tensioneers and, gradually, lowered into place. After latching, the tensioners should be brought up to the desired tension in increments of about 40,000 lb and tensions verified with portable cable- tension indicators. Pressure gauges normally used to monitor the tension on the riser lines should be calibrated quarterly to insure accuracy. NOTE; pressure gauges measure tension in the lines. Tension for the riser, however, is a function of the line tension and the angle between the lines and the riser. 2. Write the short notes on the following off-shore drilling equipment. (a) Foundation pile (b) Temporary guide base (c) Permanent guide structure (d) Marine riser system (e) Flexible joint (f) Telescopic joint (20 Marks) Solution Foundation Pile: The shoe of the foundation pile is equipped with a break-away guide frame. These arms ride in the guide lines that will guide the bottom of the pile into the center opening of the temporary guide base. They shear away as the shoe enters the hole. To the top of the foundation pile is attached the foundation pile housing assembly which support the foundation pile and provides a landing base for the next casing string. The permanent guide structure is attached around the housing and is run as the same time as the foundation pile. The foundation pile is cemented in place by displacing cement down the drill pipe handling string and through a stringer string extending through the foundation pile. Temporary Guide Base: Once the drill vessel has been positioned on location, the temporary guide base is the initial piece of equipment lowered to the ocean floor. It serves the dual purpose of; (1) providing the anchor for the guide lines; and (2) ultimately being the foundation for the permanent guide structure. The temporary guide base (Fig. 4.4) is equipped with a J-type tool (Fig. 4.5) on drill pipe. The base also has sawtooth legs to penetrate the ocean floor and prevent rotation either during disconnect form the J-slot or subsequent drilling operations. Provision made for additional cables which can guide a television camera for monitoring subsequent underwater operations. As the guide base is readied for installation, weight material is added to compartments in the base. Enough is used to give sufficient weighty for tensioning the guide lines and for the operations to follow. The guide base itself weighs about 8,000 lb. about 20,000 to 25,000 lb of weight material are added to that sacked barite is normally used for the weighting. Permanent Guide Structure: The permanent guide structure is attached to, and installed with, the foundation pile. When the foundation is set and cemented, a permanent structure base has been established on the ocean floor for further operations. At this point the unit still has no pressure integrity in that only one short section of pipe has been installed below the ocean floor (Fig. 4.4). The permanent guide structure carries a bottom gimbal base which seats in the funnel section of the temporary guide base and there by guarantees vertical positioning of the guide posts. The guide posts are normally about 8 in. in diameter and vary in length form 10 to 20 ft depending on the height and arrangement of the subsea blow-out preventer stack. The posts are of a slotted-tube-type construction; split and hinged guide-line traps at the top and bottom of the posts provide for easy installation on the guide lines. The external configuration of the post heads permits the use of a remotely operated connector to reestablish broken guide lines, if needed. In actual operations, guidelines have broken in water depths greater than 1,000 ft. By cutting them off at top of the guide posts, it has been possible to reestablish the lines without the aid of divers. Spacing of guide-line posts has varied according to individual customer requirements. In general, the industry seems to be standardizing on a 6-ft radius. Marine Riser System: Marine drilling risers are used to provide a return fluid-flow path between the well bore and the drill vessel and to guide the drill string to the wellhead on the ocean floor. No pressure integrity is required of the marine riser other than for the differential in hydrostatic pressure between the drilling fluid and the sea water. The marine riser, however, must withstand the lateral forces of the waves, currents, and vessel displacement. It must also withstand the axial loads imposed on by the buoyancy weight of the drilling mud, drill pipe, and the marine riser itself. Then, too, with a tensioned riser system, the riser must withstand the axial tension imposed on the surface. The marine-riser system (Fig.4.14), as discussed in this chapter, includes (from bottom to top): the marine-riser connector; a lower flexible joint; individual riser joints with their connectors; and a telescopic joint. In some riser systems a second flexible joint is used between the telescopic joint and the top riser joint. Flexible Joint: Flexible joints are used in the marine-riser system to minize the bending moments and stress concentrations. They are commonly placed in the bottom of the system just above the blowout-preventer stack. In deepwater operations or in unusually severe sea conditions, a flexible joint should also be provided in the top ot the system just below the telescopic joint. This reduces stress concentrations created by wave forces in this zone and by the change in section between the telescopic joint and the top marine riser joint. Tidwell and Ilfrey presented data supporting this top flexible member. Flexible joints should be selected on the basis of; (1) providing adequate angle of flexure for the total floating-drilling system design usually about 10; (2) having sufficient strength for the tension to be applied; and (3) rotating with minimum resistance while under the full anticipated tension load. Telescopic Joint: The telescopic joint serves as a connection between the marine riser and the drilling vessel, compensating for the vertical movement of the vessel. In operating position, the upper member (or inner barrel) is connected to and moves with, the drill vessel. The lower member (or outer barrel) is then an integral part of the marine riser and remains stationary in respect to the ocean floor (Fig. 4.15). Support brackets are mounted on the lower member for the riser-tensioning system and for the kill and choke-line connections. The upper member is usually fabricated with a bell nipple as a part of the joint. Tie bars and locking clamps are installed to hold the joint in a collapsed position to facilitate the handling and installation of the unit. When installed, the tie bars act as the support members for the upper sliding member and are connected to the drill vessel. 3. Make a component of Driller’s Method and Wait and Weight method based on (i) Time (ii) Surface Pressure (iii) Down Hole Stresses (20 Marks) Solution (i) Time: The most important time consideration, is not the initial waiting time but the overall time required for the complete procedure to be implemented. Fig. 3.14 shows that the one circulation method requires one complete fluid displacement (drill pipe and annulus), while the two circulation methods (Fig.3.15) requires that the annulus be displaced twice in addition to the drill pipe displacement. In certain situations, the extra time increment required for the two circulation methods may be a serious matter with respect to hole stability or preventer wear. (ii) Surface Pressures : Fig. 3.16 points out the different surface pressure requirements for several different kick situations utilizing the one circulation method. The first major difference is noted immediately after the drill pipe is displaced with kill mud. The necessary casing pressure begins to decrease as a result of the increased kill mud hydrostatic pressure in the one circulation procedure. This decrease is not seen in the two circulations method since this procedure does not circulate kill mud initially. In fact, the casing pressure increases as a result of the gas bubble expansion displacing mud from the hole. The second major surface pressure difference is observed as the gas approaches the surface. The two circulations procedure again has higher pressure as result of circulation of the lower density original mud weight. It is interesting to note at this point that these high necessary casing pressures suppress the gas expansion to a small degree resulting in a later arrival of the gas at the surface. After one complete circulation has been made, it can be observed that the one circulation method has theoretically killed the well resulting in zero surface pressures. The alternate method has pressure remaining on the casing exactly equal to the drill pipe pressure. It will be necessary at this point to introduce kill weight mud and complete another circulation. Casing pressure curve for saltwater kick is shown in Fig. 3.17. (iii) Downhole Stresses: Fig. 3.18 and Fig. 3.19 illustrate a very important principle. It can be seen that the maximum stresses occur very early in the circulation for the deeper depth and not at the maximum casing pressure intervals. This can be interpreted to mean that the maximum lost-circulation possibilities will not occur at the gas-to-surface conditions as might seem logical to the casual observer. For all practical considerations, it can be stated that if a fracture is not created at shut-in, it will probably not occur throughout the remainder of the process. 4. Explain the planning the X-Y trajectory in which angle averaging method is used to calculate the north/south (L) and east/west (M) coordinates. (20 Marks) Solution Planning the X-Y Trajectory: The first step in planning a well is to determine the two-dimensional X-Y trajectory (Fig 1.8). The next is to account for the X component of the trajectory that departs form the vertical plane section between the surface location and the bottom hole target. (Fig. 1.9) is a plan view, looking down on the straight line projected path from Well 2’s surface location to the bull’s-eye of a target with a 100 feet radius. The dashed line indicates a possible path the bit could follow because of certain influences exerted by the bit, the BHA configuration, the geology, general hole-condition. The target area provides a zone of tolerance for the wellbore trajectory to pass through. The size and dimensions of the target are usually based on factors pertaining to the drainage of the reservoir, geological criteria, and lease boundary constraints. When a well is kicked off, the practice is to orient the trajectory to some specific direction angle called “lead”. This lead usually is to the left of the target departure line and ranges from 5 to 25. The value used is generally based on local experience or some rule of thumb more recent research on direction variation (or, to use an older term, “bit walk”) indicates that the lead can be selected on basis of analysis of offset wells and of factors that might cause bit walk. As the drilling progresses after the lead is set the trajectory varies in the X and Y planes as the bit penetrates in the Z plane. Fig 1.10 and Fig 1.11 are vertical and horizontal (elevation and plan) views of a typical trajectory path. Past the lead angle, the trajectory shows a clockwise, or right-hand tendency or bit walk. A counter-clockwise curvature is called left-hand tendency or bit walk. The initial trajectory design did not account for the excursion of the bit away form the vertical plane that goes through the surface location and target’s bull’s-eye. There are many ways to calculate the three-dimensional path of the wellbore. The most common method used in the field is “angle averaging” which can be performed on a hand calculator with trigonometric functions. Consider the vertical section as depicted by Fig. 1.10. The distance form the surface to the kickoff point is Dt. at A1 the well is kicked off and drilled to A2. The inclination angle at the kickoff is zero. Fig. 1.11 shows the top or plan, view of the trajectory. Point A1 on the vertical section corresponds to the starting point, A1, on the plan view. Using the angle-averaging method, the following equations can be derived for the north/south (L) and east/west (M) coordinates. A1 A A1 L DM sin A cos ----------------------------------(1.23) 2 2 and A1 A A1 M DM sin A cos ---------------------------------(1.24) 2 2 The TVD can be calculated by A1 D DM cos A --------------------------------------------------(1.25) 2 5. Compute the corrected collapse-pressure rating for the casing of 20-in, 133lb/ft. K-55 casing with 0.635 in thickness for in service conditions where the axial tension will be 1,000,000 lb. Also compute the minimum external pressure required for failure if the internal pressure will be 1,000 psig. Data for casing specification: Body tension rating = 2,125,000 lb Non-stressed collapse rating = 1,490 psi Burst rating = 3,060 psi Steel area = 38.631 in2 Wall thickness = 0.635 in ID = 18.730 D/t = 31.496 (20 Marks) Solution 2 1,000 ,000 / 38 .632 25,886 psi 1 p j 25,886 1000 0.48883 yield 55,000 Inserting 0.48883 into Eq.3.5 yields. ( yield ) e 1 0.75 0.48883 2 0.5 0.48883 yield = 0.66155 ( yield ) e yield 0.66155 55,000 0.66155 36 ,385 psi At equivalent yield strength of 36.385 psi and D/t = 38.6, collapse will be in transition mode. Then, collapse pressure is p cr ( yield ) e FA /( D / t ) F5 where F is determined at 36.385 psi rather than at the original 55,000 psi. F at differential values of yield strength can be obtained form the following equations shown in API Bull. 5C3, fourth edition. For convenience in writing, set ( yield ) e (Y ) F1 2.8762 0.10679 10 5 (Y ) 0.21301 10 10 (Y ) 2 0.53132 10 16 (Y ) 3 F2 0.026233 0.50609 10 6 (Y ) F3 465 .93 0.030867 (Y ) 0.10483 10 7 (Y ) 2 0.36989 10 13 (Y ) 3 3 3( F2 / F1 ) 46.95 10 6 F4 2 ( F2 / F1 ) 2 3( F2 / F1 ) 3( F2 / F1 ) (Y ) ( F2 / F1 ) 1 2 ( F2 / F1 ) 2 ( F2 / F1 ) and F5 = F4(F2/F1) For yield e 36,386 psi, F1 2.941, F2=0.0446, F3=645.1, F4=2.101, F5=0.0319 2.101 p cr 36 ,385 0.0319 1,267 psi 31 .496 6. Discuss types of casing string. Solution Types of casing string Fig 3.1 shows typical casing programs for deep wells in several different sedimentary basins. A well that will not encountered abnormal formation pore pressure gradients, lost circulation zones, or salt sections may required only conductor casing and surface casing to drill to the depth objective for the well. The conductor casing is needed to circulate the drilling fluids to the shale shaker without eroding the surface sediments below the rig and rig foundations when drilling is initiated. The conductor casing also protects the subsequent casing string from corrosion and may be used to suppo9rt structurally some of the wellhead load. A diverter system can be installed on the conductor casing to divert flow from rig personnel and equipment in case of an unexpected influence of formation fluids during drilling to surface casing depth. The surface casing prevents cave-in of unconsolidated, weaker, near-surface sediments and protects the shallow, fresh-water sands from contaminatin. Surface casing also supports and protects corrosion any subsequent casing strings run in the well. In the event of the kick, surface casing generally allows the flow to be contained by closing the BOP’s. The BOP’s should not be closed unless the casing to which the BOP’s are attached has been placed deep enough into the earth to prevent a pressure-induced formation fracture initiated below the casing seat form reaching the surface. Subsequent flow through such fractures eventually can erode a large crater, up to several hundred feet in diameter, which could completely engulf the rig. Surface-casing-setting depths are usually from 300 to 5000 ft. into the sediments. Because of the possibility of contamination of shallow-water-supply aquifers, surface-casing-setting depths and cementing practices are subject to government regulations. Deeper wells that penetrate abnormally pressured formations, lost circulation zones, unstable shale sections, or salt sections generally will required one or more strings of intermediate casing between the surface casing depth and final well depth (Fig 3.1.b). When abnormal pore pressures are present in the deeper portions of a well, intermediate casing is needed to protect formations below the surface casing from the pressures created by the required high drilling-fluid density. Similarly, when normal pore pressures are found below sections having abnormal pore pressures, an additional intermediate casing permit lowering the mud density to drill deeper formations economically. Intermediate casing may also be required after a troublesome lost circulation zone or an unstable shale or salt section is penetrated, to prevent well problems while drilling below these zones. Liners are casing strings that do not extend the surface but are suspended form the bottom of the next larger casing strings Fig.3.1.c. Several hundred feet of overlap between the liner top and the casing seat are provided to promote a good cement seal. The principal advantages of the liner is its lower cost. However, problems sometimes arises form hanger seal and cement leakage. Also, using a liner exposes the casing string about it to additional wear during subsequent drilling. A drilling-liner is similar to intermediate casing in that it serves to isolate troublesome zones that tend to cause well problems during drilling operations. Production casing is casing set through the productive interval. This casing string provides protection for the environment in the event of a failure of the tubing string during production operations and permits the production tubing to be replaced or repaired later in the life of the well. A production liner is a liner set through the productive interval of a well. Production liners generally are connected to the surface well head using a tie-back casing string when the well is completed. Tie-back casing is connected to the top of the liner with a specially designed connector. Production liners with tie-back casing strings are most advantageous when exploratory drilling below the productive interval is planned. Casing wear resulting form drilling operations is limited to the deeper portion of the well, and the productive interval is not exposed to potential damage by the drilling fluid for an extended period. Use of production liners with tie-back casing strings also result in lower hanging weights in the upper parts of the well ad thus often permit a more economical design.
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