As a well is downsized the collapse and internal pressure ratings of the surface and intermediate casing and liner string increase. Thus liners can be used further up the hole than with conventional hole sizes. This gives the downsized conventional approach to slim wells the capability to increase the diameter efficiency of wells.

1 Casing design

"Diameter efficiency" of wells is a term focusing on the technical efficiency of the process of drilling and completing a well. The concept is to see how efficiently the inputs, money and time are used to construct the product and deal with the environmental impact.

The concept of diameter efficiency is an iterative process of well design. It enables the team to focus on areas where quite small changes in design and construction procedures, often in seemingly independent technologies, can make worthwhile savings.

The final product of a production well is an outflow system and an inflow system. The outflow is a conduit, or tubing, of a certain capacity. The inflow system is the connectivity with the reservoir, and this is not influenced greatly by well diameter.

The final product for an exploration well is open hole section(s) through the reservoir of such diameter(s) that they can be adequately logged and that a production test string can be used which will give sufficient flow rate for the hydrocarbons and the formation to be evaluated. Additionally, cores, when required, should be sufficiently large to permit recovery and evaluation.

Cutting rock requires energy to drive the bit, transport the cuttings away from the cutters and transport it to surface. As a guiding principle: the smaller the hole, the less energy that is required to drill it, the less steel casing has to be run, the less cement has to be mixed and pumped to replace the rock which has just been drilled at such expense, and the lower the environmental impact.

Apart from using liners, the diameter efficiency during drilling of all wells can be improved by reducing the clearance between the casing and the hole. The traditional clearances between the casing and the hole were established some years ago when holes typically had much higher local dog leg severity and were, due to technology available at the time, far more rugose.

For production wells, within the constraints of leak and circulation paths and the provision of artificial lift, the diameter efficiency can be further improved by:

• ·Using a monobore completion if appropriate.
• ·Using coiled tubing as the production conduit, thus eliminating the clearance for couplings or upsets. This advantage may be negated if external accessories such as gas lift valves are required. Also a coiled tubing string cannot be rotated past an obstruction.
• ·Specifying larger drift tubing, and or reducing the surface roughness on the inside by cold rolling the tubing at the mill or downhole, using corrosion resistant alloys, minimising scale or wax build-up, etc.

For exploration wells the required hole diameter through the prospective zones can be minimised by:

• Using small petrophysical evaluation tools (LWD, and wireline logging tools) which are now becoming available.
• Production testing short intervals sequentially so that required inflow rates and drawdowns can be minimised. This can be easier if a monobore completion is used and the well is tested bottom up. Open hole production testing using a coiled tubing as a conduit is now possible.
• The use of anti-vibration technology while coring, such as is incorporated in the Integral Coring Motor, to improve core recovery in small holes.
• Whenever possible, the well design should incorporate API sizes of tubulars as:
• They are built to recognised standards and quality control is easier to organise.
• Crossovers, nipples, fishing tools, adapters, plugs, packers, centralisers and other accessories can be ordered quickly with minimum effort with the knowledge that they will all fit together.

2 Liners

Compared with full strings of casing, liners have the following advantages:

• Total weight, and hence cost of steel in the well is reduced.
• Transport and location size are reduced.
• When drilling the lower part of the hole, ECDs and swab pressures are reduced.
• Annulus pressures during the final stages of circulating out a (gas) kick are reduced.
• Tapered strings of tubing can be run, thus maximising well productive potential.
• More space is available for subsurface safety valves.
• Tapered strings of drillpipe can be used. This gives the following advantages:
• Part of the drillstring can be used for the whole well.
• Allowable hook loads are greater.
• DP internal pressure losses are less, enabling more power to be supplied to the BHA and bit.
• Less small DP is required.
• he fact that the wellhead has to accommodate one less string of casing results in:
• Reduced wellhead height, weight and cost.
• Fewer leak paths on the wellhead.
• The lower wellhead may mean that a shallower cellar or lower substructure can be used.

There are drawbacks to the use of liners:

• Running, setting and cementing a liner is an intrinsically more complex operation than running and cementing casing.
• An extra trip may have to be made to set the tieback seal.
• Access to the annulus is eliminated.
• In many shallower wells the cost of the liner hanger and associated serviceman is greater than the cost of the casing eliminated.
• It is difficult to see the weight of, or torque due to, small liners in tight or deviated holes. Rotating liner hangers are recommended. These enable the slips to be set and the running string disengaged, to see that the slips are firmly set before engaging the splines and doing the cement job with liner rotation.

3 1/2" liner hanger system for 4 1/8" and 4 3/4" hole have been.

3 Cementing for downsized conventional slim wells

Cementing of the upper strings is completely conventional. However the smaller volumes give a number of practical logistical and operational advantages. In particular, more of the cement jobs can be batch-mixed and cement displacement velocities can be higher.

The major concern during cementing of smaller deeper liners is that very high frictional pressure losses will be induced by pumping the cement slurry into a narrow annulus at a high displacement rate. The velocity of the cement slurry in the annulus is considered to be the single, most important parameter for achieving the main objective of a primary cementation, i.e. good zonal isolation by optimum mud removal (250 ft/mn).

other issues to consider:

• In trying to design low viscosity slurries, a Slag Mix formulation may be a more promising option than Portland cement.
• To avoid crumbling of the very thin cement sheath over the rathole section, liner/casing may either be set on bottom, or fibre cement may be used as a tail slurry.
• If conventional techniques fail to allow sufficient placement velocities, either the hole size can be increased slightly (oversize bits, under-reaming) or another annular sealing technique, e.g. ECPs may be used.

3.1 Conclusions and recommendations

• Cement rheology and hole size are the parameters that most influence the maximum allowable annular velocity of a cement slurry during its displacement in a slim hole annulus.
• The total frictional pressure loss in the system is expected to decrease if a heavy, brine-based, low-solids drilling fluid is used.
• A small deviation of the hole size from the bit size has a large influence on the achieved displacement velocity. In a field situation the displacement rate should therefore be based on actual hole-calliper measurements. In extreme cases, consider under-reaming the hole.
• Even with a 5" liner in a 5 7/8" hole, cementation is restricted to a maximum liner length of 2000 ft, if a conventional cement slurry is used.

4 Casing and cementing for wells drilled with continuous coring geometry

The slender drill rod connections dictated by the continuous coring geometry are unable to withstand excessive drillstring vibrations. Thus, as discussed under the section on drill rods for continuous coring, for effective trouble free drilling a small annulus is required for the total string length. This precludes the use of liners, and, as is shown in the previous section, this makes effective cementing of practically all such wells very difficult. Therefore it may be prudent for continuous coring geometry wells to consider a low probability of achieving successful zonal isolation by means of primary cementation during the design process. This may not be as important for low pressure oil wells as for gas wells.

Specific differences between cementing a hard rock well and a sedimentary basin well include the potential for cements with little fluid loss control to flash set when flowing past permeable formations or being pumped at high speed up narrow annuli, the problems of gas worm holes through setting cement giving rise to leaking annuli, the effects of pressure and shear rate on setting time, etc.

The casing used in the mining industry may have a different specification from that used in the oil industry. Threads may not be designed for sealing against pressure; accessories such as reliable float shoes, stage cementing collars, and centralisers may not be available, etc.

If mining drill rods are used as an emergency casing string, the threads may not seal at high differential pressure and there may be difficulties in installing centralisers.