Ministry of Science and Technology Department of Technical and

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					                             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)
       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)

        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
        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
       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)
        (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)

       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.

                       A1    A   A1 
        L  DM sin  A         cos           ----------------------------------(1.23)
                       2             2      
                       A1    A   A1 
        M  DM sin  A         cos           ---------------------------------(1.24)
                       2             2      

The TVD can be calculated by

                      A1 
        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)

         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( F2 / F1 ) 
                                 46.95 10    6
              F4                           2  ( F2 / F1 ) 
                      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.
       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
       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
       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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