ADVANCES IN DRILLING COVERED AT SPE/IADC CONFERENCE

Drilling efficiency may increase with new methods of bit analysis that model polycrystalline diamond compact cutter loads and that incorporate risk analysis with bit run time.

By maximizing extended-reach drilling technology to develop additional offshore gas reserves, an operator did not have to set another platform. Better air drilling tools reduce the cost of horizontal wells drilled with aerated fluid.

Other advances in technology include the use of four wiper plugs to prevent cement contamination in long liners and the development of a cement specially designed to seal tight casing leaks.

These were among the topics discussed at the most recent meeting of the Society of Petroleum Engineers/international Association of Drilling Contractors drilling conference earlier this year in Amsterdam.

PDC CUTTER LOADS

S.M. Behr, T.M. Warren, L.A. Sinor, and J.F. Brett of Amoco Production Co. described a three-dimensional (3-D) polycrystalline diamond compact (PDC) bit model that is capable of simulating cutter loading for PDC bits.

Previous PDC bit models assumed that the cutter forces were constant for each full bit revolution. Cutter breakage from impact loads is more significant, however, than shown in the two-dimensional (2-D) models.

The 3-D model tested PDC cutters as the bit drilled through two different formations across a tilted bed boundary. Two different types of rock were cut at 45 angles and then glued together to make one specimen.

The test bit drilled with a constant weight on bit and a varying rate of penetration (ROP), similar to actual drilling operations. The load on the cutters remained constant while the bit drilled through the homogeneous sections of the rock.

However, the cutter loads cycled rapidly while the bit drilled through the bed boundary. ROP decreased tremendously during this period.

The vibration and varying loads contributed to early cutter failure.

Drilling nodules (small spherical concretions of calcite embedded in shales) have a similar effect on PDC cutters. As a bit drills through nodules, however, a drop in ROP may last only 1-2 min and may not be noticed on the rig floor.

As the bit blades encounter the nodules, the force on the bit face is no longer constant, and the bit may pound the borehole wall. This can lead to bit whirl.

As a bladed bit drills through nonhomogeneous rock, the changing lateral forces can initiate bit whirl. As the bit whirls, the cutters intermittently contact the rock with high force, At high rotation speeds, the centrifugal force can increase PDC cutter stresses to the point of breaking.

BIT BEARING ANALYSIS

M.J. Fear, J.L. Thoroughgood, O.P. Whelehan, and H.S. Williamson of BP Exploration developed a risk analysis approach to study roller-cone-bit bearing life relationships to various drilling events to improve bit-run cost calculations.

Bit-run costs are typically minimized by manipulating controllable variables such as bit type, weight on bit, rotary speed, and bit hydraulics. However, an inappropriate combination of the drilling variables may lead to catastrophic bit failure and costly remedial action.

An operator must consider the additional risk of bottom hole assembly failure as a factor in any increase in rate of penetration.

Bearing failure is more important than wearing of the bit teeth because failed bearings could lead to a serious disruption of drilling, that is, a fishing job.

One common drilling strategy that maximizes bit on-bottom time has been to turn a bit until it fails. Because this approach may lead to increased fishing jobs, an alternative strategy is to run all bits for a fixed time before tripping and replacement. The length of time is a function of product reliability and past performance of similar bits under similar circumstances.

With this method, some bits will be pulled before being completely worn. Thus, the optimization procedure should include the probability of detection of bit failure before junk is left in the hole. Optimum run time decreases as the probability of detection of failure decreases.

This bit optimization analysis was applied to elastomeric and metal seal bits run in the North Sea. According to these techniques, metal seal bits were more cost effective because they could run longer for a given probability of detection.

Effective bit life must combine the reliability of the bit and bottom hole assembly, the probability of bit failure as drilling continues, and the consequences of bit failure.

FOUR-PLUG LINER CEMENTING

A four-plug system can improve liner cement jobs, said H. Dreikhausen of BEB Erdgas & Erdol GmbH.

Statistical analysis of liner cementations between 1982 and 1986 in northern Germany indicated that cement quality was poor behind long, 3,000-7,000 ft, 7-in. liners. The extent of cement contamination increased with increasing liner length.

The severe cement contamination resulted from the top plug collecting mud that adhered to the inner walls of the liner and drill pipe. A successful liner cementation requires hard set cement above the liner top near the calculated top of cement and hard set cement between the landing collar and the casing shoe.

A four-plug system was developed to separate the drill fluids, the spacers, and the cement to ensure uncontaminated cement in the liner annulus. The system consists of a bottom wiper plug, a top wiper plug, a mandrel with two sets of shear pins for these plugs, and two pump down plugs.

The first pump down plug is released followed by pumping of the cement slurry. The second pump down plug is then released followed by the spacer fluid.

The first plug latches into the bottom wiper plug, and the pair are pumped to the bottom of the liner, and the cement then circulates around the pipe. The second pump down plug lands into the top wiper plug, and this pair is displaced to the landing collar to complete the liner cementation.

The pump down plugs clean the inner drill pipe, and the wiper plugs clean the inner walls of the liner. The four-plug cementing system resulted in greater than 90% high quality cement from the liner top to the shoe, with no effect from liner length.

CASING LEAK REPAIR

Tight casing leaks can be repaired with small particle size cement, according to J.W. Meek, Oryx Energy Co. and K.L. Harris, Halliburton Services.

Tight casing leaks are such that a continuous injection rate cannot be established, but the applied pressure leaks off 300-500 psi in less than 30 min.

These leaks are typically found in old well bores. Tight casing leaks become major problems in injection wells that cannot pass the routine mechanical integrity tests of the local regulatory agencies. These tests require injection wells to hold a certain pressure in the annulus for a short, determined period.

The most common method of repairing tight casing leaks is to spot acid or increase pump pressure to establish an injection rate followed by a repetition of squeezing, drilling out, and testing until the well holds pressure.

Small particle size cement is better suited for these squeezes than Class H cement because of its improved leak-off properties. Maximum Class H cement particle size is 120 m, whereas the largest particle in small particle size cement is 10 times smaller than that.

This material is defined by the following:

Maximum size is less than 30 m.
90% of the particles are less than 27 m.
50% of the particles are less than 10 m.
Surface area-mass is not less than 6,000 sq cm/g.

In lab tests with slots of varying widths, the small particle size cement passed more volume than Class C, G, or H cements.

In the first 9 months of field testing small particle size cement, more than 100 squeeze jobs were performed on wells considered to have tight casing leaks. Many of the wells had undergone unsuccessful conventional squeezes. Better than 94% of the small particle size cement squeeze jobs were successful; that is, pressure did not leak off after the first squeeze was drilled out.

EXTENDED-REACH WELLS

P.W. Scott of Woodside Offshore Petroleum Pty. Ltd. presented a paper on the equipment modifications to an existing production and drilling platform required to drill wells with an extended reach of 16,400 ft.

Offshore Western Australia, the North Rankin A platform is the only production platform draining a 1,640-ft thick reservoir at a depth of 9,200 ft covering 15.4 sq miles. Because the second, planned platform was not installed, substantial gas reserves were out of reach of the present platform's drilling radius of 9,840 ft.

The target well profile consists of build rates of 1.0-1.5/100 ft with long tangent sections compared to typical wells characterized by build rates of 2.5-3.5/100 ft with S-shaped well paths.

The long, extended-reach of these wells requires substantially higher flow rates during drilling. Maximum standpipe pressure was set at 4,000 psi-a compromise between drilling efficiency and increased pump maintenance.

The rig added a third mud pump capable of 4,700 psi and 1,500 gpm to provide the minimum 3 hydraulic hp/sq in.

All liquids-solids separation equipment had to be upgraded to handle 1,000 gpm of oil based mud. Two high-performance centrifuges replaced the original desander, desilter, and centrifuge.

A high-torque top drive system was installed to reduce stuck pipe problems by providing back reaming abilities. However, back-reaming problems in some of the medium-radius wells led to more "gentle" drilling and reaming techniques.

Before drilling began, all crews were classroom-trained in new-equipment operation, new-equipment maintenance, and drilling techniques.

The final cost of the project was $9.5 million with greater than 25% of the cost for power supply modifications.

AERATED HORIZONTAL DRILLING

According to S.B. Claytor and K.J. Manning of Smith International Inc. and D.L. Schmalzried of Marathon Oil Co., Marathon drilled a medium-radius horizontal well in the Stoney Point field in Michigan with an aerated mud system.

The well was drilled using an aerated mud with an equivalent density of 6.7 ppg, close to the bottom hole pressure of the vugular formation.

The well was designed with a build rate of 18/100 ft and a final angle of 95 for a horizontal length of 388 ft. The horizontal section sloped toward the well for gravity drainage, and the length was limited because of 40-acre spacing.

The medium radius and short displacement required an exact bottom hole assembly (BHA). The BHA was designed by computer models to consider hole inclination, hole curvature, dip angle, formation anisotropy, and bit weight.

The BHA consisted of a high-torque, slow-speed positive displacement motor with a bent housing and a bent sub.

The steerable system was designed to remain as close to neutral as possible with no build or drop tendency during rotary drilling.

An electromagnetic telemetry-link measurement while drilling system sent signals to the surface by inducing an electric current into the surrounding rock formation and creating an electromagnetic wave that channels up the drill pipe. This system permitted communication from the surface to the BHA, as well as transmission of data during trips.

Although the aerated brine cleaned the hole adequately, high-volume centrifuges should be used on future wells because the cuttings were pulverized into very small particles in the horizontal section.

The well was drilled from spud to total depth in 29 days, 14 of which were for directional work. The total cost of this well was 2.5 times greater than that of a typical vertical well for the area.