The output of this process is a preliminary well configuration specifying the minimum casing diameter and the minimum casing-shoe setting depth for all strings. This serves as input for the detailed design phase.

• The casing diameter is mainly determined by the availability of downhole drilling equipment, logging tools and production requirements. The casing-shoe setting depth is usually a function of the strength of the formation to be drilled through and the wellbore loading during the drilling operation.
• Selection of the optimum (most cost-effective) casing scheme for the anticipated development plan can play a major role in cutting overall well costs, and guaranteeing formation integrity during drilling under all realistic loading conditions.
• Casing diameters should be the minimum feasible given the formation evaluation requirements and drilling and production equipment sizes. Recent developments in drilling, evaluation and completion techniques have increased the application of slimhole drilling and monobore completions to allow for slimmer casing-scheme selection.
• The casing-shoe setting depth is a function of the strength of the formation to be drilled and the loads on the wellbore during drilling or lithological/geological related considerations. Casing setting depths are determined by comparing formation strength with the loads to which the formation may be subjected.
• The primary method of estimating formation strength is still the use of leak-off and limit tests, although pore pressure prediction and wellbore stability models are available to assist
• The preliminary casing scheme selection should be considering the casing diameters from the inner strings towards the outer strings and by evaluating the casing setting depths from the total depth upwards to surface.

1 Minimum casing diameter

Preliminary casing sizing is the most important phase of casing design in terms of well costs.

Design criterion

Maximum monetary value, without compromising safety and environment, for the total field development.

• By considering the well objective in detail this requirement can be achieved for exploration and appraisal wells by taking the latest evaluation techniques into account
• For development wells alternative completion systems should be considered. Consequently, by determining the well configuration from the inside working outwards, the most cost effective casing scheme should be selected.

The final hole size or production tubing determine the well configuration.

Contingencies should be justified on the basis of an explicit probability analysis. Too much contingency is frequently included in designs, at unnecessary cost.

Slimming down requires a more widespread use of drilling and production liners. The improved integrity of liner hangers and reduction of casing wear due to the use of mud motors support a careful re-consideration of established principles.

Exploration and appraisal wells

The ability to test the well at adequate flow rates represents perhaps the most critical factor with respect to the conduit size and well configuration.

Also the minimum diameter of core material may play a role in selecting the hole size across coring intervals. Coring After Drilling (CAD) is emerging as a valuable option. This technology allows full mud log and electric log evaluation before picking core intervals.

Development wells

Production wells can be visualised as an inflow/ outflow system.

a. Inflow system

Technological advances allow boosting of the well inflow to a considerable extent, all be it at a cost. In many cases, it will be profitable to maximise well inflow.

The Well Inflow Quality Indicator (WIQI) is a measure of impairment. For oil wells, this factor equates to the ratio PI (actual)/PI(theoretical, excluding any avoidable inflow damage). The Productivity Index (PI) is the production rate per unit applied drawdown. Hence, the WIQI can be interpreted as the actual stabilised production rate divided by the ideal production rate at the same drawdown. The ideal rate is derived by excluding any avoidable inflow damage. The determination of the WIQI is not always unambiguous, but a consistent method of calculation will provide valuable trend information.

Another factor is the Production Improvement Factor (PIF). The PIF is the ratio PI (horizontal)/PI (vertical), or more generally PI (new inflow system configuration)/PI (conventional vertical).

b. Outflow system

The outflow system is essentially a conduit with flow controls and, where necessary - artificial lift or pressure boosting facilities.

The smallest suitable conduit diameter should normally be selected to handle current and future well flow to permit the design of the most economic well configuration around the conduit.

It is essential that future artificial lift be addressed up front, as this may have a major impact on well design (minimum acceptable casing diameter, conduit size, sand control policy). Artificial lift systems include screw pumps, intermittent gas lift, plunger lift, beam pumping, hydraulic jet pumping, through to higher horse power advanced multiphase ESPs and gas lift.

In some instances it may be more advantageous to drill a larger number of lower capacity, low cost development wells rather than a small number high cost high capacity wells.

The monobore completion (MB) is a completion with fullbore access across the payzone, without diameter restrictions, but not necessarily with a constant diameter from top to bottom. The MB concept optimises the opportunity for well intervention through the Xmas tree, i.e. rig-less, and is applicable to any completion diameter. By working through the Xmas tree, many operations can be conducted without killing the well, which mitigates impairment.

The MB concept in conjunction with High Integrity Corrosion Resistant (HICR) tubing may offer very profitable characteristics in situations with high rig re-entry costs.

2 Minimum casing-shoe setting depth

The minimum setting depth is usually driven by several considerations:

• to isolate instable formations;
• to isolate shallow hydrocarbons;
• to isolate lost circulation zones;
• to isolate fresh water horizons;
• to prevent failure of formations by induced circulating pressures during drilling operations like circulating, drilling and tripping;
• to prevent failure of formations by induced circulating pressures during well control operations when closing in and circulating out an influx.

2.1 Design criterion

• The estimated Formation Breakdown Pressure (FBP) of any formation below the casing shoe should not be exceeded during normal operating conditions, including well control, drilling, circulating and tripping.
• The mud weight gradient, required to balance the anticipated pore pressures in the open hole section, should never be higher than the estimated equivalent mud gradient of the Fracture Closure Pressure (FCP) in any of the formations in the open hole section.

If these requirements are met, the well bore will not fracture, and the well will not experience uncontrolled losses under design conditions. These design conditions relate to the maximum influx that can be closed in and circulated out, and to the maximum circulating rate and trip speed to be experienced. In addition, if the formation accidentally fractures and a loss- or kick/loss-situation develops, it will be possible to return the damaged well to a stable situation, without significant gains or losses, once the well has been circulated to mud.

2.2 Determination of wellbore pressure load

The wellbore will be subjected to the following pressure loads during drilling operations.

Pressure loading during drilling, circulating and tripping operations.

It is established that transient pressures induced by pipe accelerations can be much higher than the pressures created by constant tripping speeds. The pressures induced at the bit due to tripping will propagate through the whole well to bottom. Gelling does not seem to have a significant effect on the swab and surge pressures induced. Both swab and surge pressures are induced in either of the pipe movement directions.

Pressure loading during well control operations.

The determination of the pressure loading on the wellbore when circulating out an influx can be divided into two aspects: influx volume determination and wellbore pressure calculation. It is possible to calculate the design influx under a given set of circumstances and the kick pressure profile can be calculated using the kick volume calculated.

2.3 Determination of wellbore strength

Formation strength is the other critical design parameter for casing shoe setting depth.

In the well design phase, the preparation of the best estimate of the lithological model, formation strength profile and pore pressure profile is addressed. This will determine the number and setting depths of casings. A best possible estimate can be done using a regional formation strength model, offset well data, or a simple empirical relationship for those wells, where no other data is available. In the absence of a more accurate formation strength model, the leak off-pressure (LOP) of offset wells should be used as a conservative approximation for the formation breakdown pressure (FBP).

During the drilling phase, the assumptions of the FBP made during the casing design phase must be checked by carrying out Limit or Leak-off tests. For every well, a Limit or Leak-off test should be carried out at each casing shoe. If drilling through a BOP from the conductor casing will be done, a test below this conductor casing shoe should be scheduled. If drilling will be carried out below a production casing, it should be considered as another intermediate casing and a normal Limit or Leak-off test should be carried out. In addition, a Limit or Leak-off test should be repeated at every formation where the FBP can be expected to be significantly less than the strength measured during the previous test, and where further drilling will be done in that section. Note that during a Leak-off test, the exposed formations have been subjected to higher pressures than the LOP.

When drilling wells in new areas, or in those cases where additional regional information is valuable, it should always be considered to carry out a more complete formation strength test, including formation breakdown. This way, useful data on formation breakdown, fracture closure and in-situ stress can be obtained. The advantage of a good theoretical/empirical formation strength model, may well offset the risk associated with a small reduction in formation strength caused by a fractured casing shoe. Consider doing these tests on abandonment of wells.