Well Control Well Design

Well Control - Well Design

Last Updated Thursday, 28 July 2011 13:27

This article descrobes the drilling program and other Well Design considerations for Well Control

1 Drilling programme The drilling programme is based on the information provided by the subsurface department and in summarized in the Well Planning Datasheet. It should include in particular:

A statement on shallow gas.

Formation characteristics: - permeability, fluid type, hydrocarbon depths, gas zones, etc.; - formation pore pressure gradient profile; - expected formation strength gradient at the proposed casing setting depths and the requirement of formation integrity tests (limit- or leak-off tests) at specific casing shoes.

BOP requirements/specifications including specific test requirements.

Wellhead specifications.

Any known or anticipated drilling hazards or problems.

2 Casing programme The setting depth of casing is of major importance for complete pressure integrity. Correct casing setting depths permit the maintenance of proper well control.

2.1 Stove pipe/marine conductor/foundation pile

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Well Control - Well Design

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The setting depth of the stove pipe, marine conductor, or foundation pile should be deep enough to avoid formation breakdown due to the hydrostatic head of the fluid column in the stove pipe, marine conductor, or foundation pile. When a diverter system is planned to be used, the setting depth of the stove pipe, marine conductor or foundation pile should also be deep enough to be able to withstand a shallow gas kick and subsequent dynamic kill without cratering.

In floating drilling operations, the foundation pile should be set deep enough to ensure sufficient pull-out resistance of the foundation pile when using a marine riser.

2.2 Conductor string The conductor string should be designed to withstand a burst pressure equivalent to a gradient of 22.6 kPa/m (1 psi/ft) with the annulus empty. In practice the conductor may have to support part, or all, of the vertical load due to subsequent tubing/casing strings, wellhead and BOP stack.

2.3 Surface string The surface casing should preferably be set with the shoe in an impermeable, competent formation.

Surface casing should be designed to support an internal (burst) pressure with the hole and/or casing gas filled. The design pressure at the casing shoe shall either equal the formation breakdown pressure or be based on the anticipated formation pressure in the open hole, whichever is the lowest.

When calculating the surface string burst load, the mud gradient outside the casing is considered to be equivalent to that in use when the casing is to be run.

In deep wells, and in deviated wells where the build-up section is covered by the surface casing, prior consideration should have been given to providing extra protection against rotational and trip wear. This protection may be in the form of a higher weight or grade of casing for the top

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Well Control - Well Design

Last Updated Thursday, 28 July 2011 13:27

joints and the curved parts of the casing string.

2.4 Intermediate string Intermediate casing may be installed whenever hole conditions prevent continuation of drilling, for example, in cases of serious lost circulation, unstable formations, or abnormal pore pressure gradients.

The intermediate string should be designed to support an internal (burst) pressure with the well gas filled. The design pressure at the casing shoe shall either equal the formation breakdown pressure or be based on the anticipated formation pressure in the open hole, whichever is lower. Assume the fluid gradient outside the casing to be that of the mud in use when the casing is to be run.

In highly deviated wells and when long drilling times are anticipated below the intermediate casing, a reference caliper log should be run. Also prior consideration should have been given to the provision of extra protection against rotational and trip wear. This protection may be in the form of a higher weight or grade of casing for the top joints and the curved parts of the casing. Following prolonged rotational periods, or when excessive casing wear is suspected, the casing test may be repeated to check the integrity of the casing.

2.5 Production string The production string, when completed with a production packer, shall be designed to support an internal (burst) pressure based on the anticipated wellhead pressure in addition to the hydrostatic pressure of the packer fluid. When designing the production string, an appropriate fluid gradient outside the casing will have been considered. In gas or water injection wells, the production casing will have been designed to withstand injection pressure.

2.6 Liners Setting a liner may be preferred to running a full intermediate and/or production string. If a liner is selected, the integrity of the link between casing and liner may have to be tested, depending on the following:

·presence of hydrocarbons behind the liner;

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Well Control - Well Design

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·overpressured formations behind the liner;

·well control aspects for intermediate or production string require a positive isolation between liner and casing.

Liner lap testing methods involve:

·pressure testing (only after installing a tie-back packer, or if the liner is used as a drilling liner and no tie-back packer is required. The leak-off test procedure should be followed when a pressure test is carried out);

·inflow test;

·Cement bond log/cement evaluation tool

A cement bond log shall always be run if the liner is installed as a production string, or when top of cement (TOC) is suspected to be below the minimum required TOC (e.g. when losses occurred during cementing).

The liner lap shall be inflow tested when hydrocarbons are known to be behind the liner with sufficient pressure to inflow test, and after a tie-back packer is installed. When an inflow test is considered necessary, the possibility of not being able to kill the well in case of a leaking liner lap should be considered. If the well cannot be killed, it is recommended to install a tie-back packer with PBR prior to inflow testing.

A tie-back packer shall be installed when:

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Well Control - Well Design

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·a leak in the liner lap is observed;

·drilling ahead below the liner is required and the shoe of the liner is assumed to be the weakest point in the system (well control calculations are based on the LOT results at the liner shoe, not the previous casing shoe).

The liner hanger and tie-back packer shall be provided with a tie-back arrangement, so that a full string of casing or tie-back packer can be tied into either the top of the liner or the tie-back packer at a later stage, if considered required.

In highly deviated production wells consideration should be given before drilling for the liner, to making a reference run with a casing caliper log in the intermediate string. A wear log should also be run before finally running the liner.

If a liner is selected, any formation fluid influx will fill less height in the (larger) casing when being circulated out than it would in a full length of the smaller casing extended to the surface. Using this method, less hydrostatic head will be lost, and annular pressures experienced during the well control process will be lower.

3 Mud programme To maintain primary control and borehole stability, it is essential that the mud gradient should exceed the highest pore pressure gradient of the exposed formations. The mud gradient should be sufficiently high to compensate for swabbing effects whilst tripping. The overbalance to be applied is generally in the region of 200-400 psi, except in top hole drilling operations where the overbalance margin is usually lower due to weak formations and the shallow depth of the exposed formation.

The planned mud gradient should not exceed the prognosed fracture propagation gradient. If the mud gradient is above the estimated fracture propagation gradient, drilling under these conditions is only acceptable in exceptional cases where the consequences of formation fracturing have been fully considered and manageable.

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Well Control - Well Design

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If pore pressures are not accurately known:

·use all available information to select a mud which will provide a minimum overbalance of 200-400 psi; Pressures may have to be taken at some intermediate stages during drilling to confirm formation pressure estimates. The "Drilling for Kicks" technique is not recommended and should never be used to determine formation pore pressures;

·use adequate measures for the early detection and proper control of abnormal pore pressures.

A smaller than normal overbalance has to be accepted in top hole drilling operations, when lost circulation zones are experienced, and in well servicing operations. In such situations exceptional care is needed to avoid swabbing during trips and to maintain a full hydrostatic head of fluid in the hole.

When overpressured formations are anticipated, one tank of kill mud shall be available when drilling through that section. The gradient of the kill mud shall be 10-20% higher than the gradient of the mud in use.

4 Cementing programme The cementing programme should be designed to obtain a primary cementation which will isolate and prevent intercommunication between formations and between the open hole below and shallower formations behind the casing. The surface string should preferably be cemented well into the conductor string.

Care should be taken, especially offshore, to ensure that there is no breakdown at the shoe of the conductor and surface strings when drilling for, and cementing, subsequent strings. Before cementing, a circulation test should be carried out to determine maximum circulation rates at which no losses occur. The equivalent circulating density (ECD), calculated with a computer programme, should not exceed the Equivalent Mud Gradient (EMG) of the leak-off test result at the previous casing shoe or at the weakest point in the open hole section. The maximum cement displacement rate should be less than the maximum achieved circulating rate (without losses).

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Well Control - Well Design

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The cement job should be designed in such a way that the minimum required overbalance is maintained at all stages of the cementation, including unexpected conditions such as circulating out spacers. Beware also for possible losses of spacers when placed opposite permeable formation(s) after the cementation is completed.

5 Deviation control Deviation surveys shall be taken to ensure that the course of the well is within the limits given in the programme. This is to avoid collision with wells already drilled and to establish the complete path and bottom hole position of the well.

Positional uncertainties must be considered in any interpretation of the position of the borehole course, especially when there is a potential collision risk with any other completed, suspended, or abandoned well. When the cones of uncertainty coincide, drilling must be terminated and the well plugged back.

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