Install Bop Stack And Marine Riser

Fig. 1.63-Example subsea equipment installation"procedure.



(High Pressure)



Marine Riser Tensioner

(Low Pressure)

Tension, T

Fig. 1.64-Schematic of a pneumatic tensioning device.

(Low Pressure)

Tension, T

Fig. 1.64-Schematic of a pneumatic tensioning device.

action of the piston and lubricate the packing. A block-and-tackle system allows the use of a shorter piston stroke. Pneumatic tensioning devices often are used on the marine riser, the various guide lines to the subsea wellhead, and on surface motion compensators for the drillstring.

1.10 Drilling Cost Analysis

The main function of the drilling engineer is to recommend drilling procedures that will result in the successful completion of the well as safely and inexpensively as possible. The drilling engineer must make recommendations concerning routine rig operations such as drilling fluid treatment, pump operation, bit selection, and any problems encountered in the drilling operation. In many cases, the use of a drilling cost equation can be useful in making these recommendations. The usual procedure is to break the drilling costs into (1) variable drilling costs and (2) fixed operating expenses that are independent of alternatives being evaluated.

1.10.1 Example Drilling Cost Formula. The most common application of a drilling cost formula is in evaluating the efficiency of a bit run. A large fraction of the time required to complete a well is spent either drilling or making a trip to replace the bit. The total time required to drill a given depth, AD, can be expressed as the sum of the total rotating time during the bit run, tb, the nonrotating time during the bit run, tc, and trip time, tt. The drilling cost formula is

where Cy is drilled cost per unit depth, Cb is the cost of bit, and Cr is the fixed operating cost of the rig per unit time independent of the alternatives being evaluated.

Since this drilling cost function ignores risk fac tors, the results of the cost analysis sometimes must be tempered with engineering judgment. Reducing the cost of a bit run will not necessarily result in lower well costs if the risk of encountering drilling problems such as stuck pipe, hole deviation, hole washout, etc., is increased greatly.

Example 1.5. A recommended bit program is being prepared for a new well using bit performance records from nearby wells. Drilling performance records for three bits are shown for a thick limestone formation at 9,000 ft. Determine which bit gives the lowest drilling cost if the operating cost of the rig is $400/hr, the trip time is 7 hours, and connection time is 1 minute per connection. Assume that each of the bits was operated at near the minimum cost per foot attainable for that bit.


Cost ($)

Rotating Time (hours)

Connection Time (hours)

Mean Penetration Rate (ft/hr)
















Solution. The cost per foot drilled for each bit type can be computed using Eq. 1.16. For Bit A, the cost per foot is


  • 46.81 /ft.
  • 42.56/ft.

Finally, for Bit C,

The lowest drilling cost was obtained using Bit B.

1.10.2 Drilling Cost Predictions. The drilling engineer frequently is called upon to predict the cost of a well at a given location. These predictions are required so that sound economic decisions can be made. In some cases, such as the evaluation of a given tract of land available for lease, only an approximate cost estimate is required. In other cases, such as in a proposal for drilling a new well, a more detailed cost estimate may be required.

Drilling cost depends primarily on well location and well depth. The location of the well will govern the cost of preparing the wellsite, moving the rig to the location, and the daily operating cost of the drilling operation. For example, an operator may find from experience that operating a rig on a given lease offshore Louisiana requires expenditures that will average about $30,000/day. Included in this daily operating cost are such things as rig rentals, crew boat rentals, work boat rentals, helicopter

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  • tanja
    How to insall the BOP Stack?
    8 years ago

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