Minimizing Vibration - Specialy for slim hole drilling with downsized conventional or retrofit equipment, the larger relative annular clearances required to facilitate kick detection and control, low ECDs with adequate flow rate, drillpipe flexibility for directional drilling requirements etc., increase the potential for vibrations.

As the hole size decreases loads due to vibrations become more significant and the relationships between exciting forces, the coupling between different modes of vibrations, stiffness and damping change.

Torsional and bending stiffness decrease the most and hence vibrations in these modes become more important. The bending or lateral vibrations are constrained by the relatively tight radial tolerances, which limit the magnitude of the bending strains. This compensates for the substantial increase in the frequency. However, if the drillstring is buckled, friction between the string and the wall can give rise to stick-slip torsional vibrations when the string is rotating. Torsional vibrations are also the result of coupling of longitudinal and torsional vibrations via the bit. The lateral vibrations are principally due to out of balance forces in the drill collars, Moineau motor rotor, and coupling with the longitudinal vibrations. This coupling is more severe if the system is operating at or near a resonant condition.

The vibration minimisation techniques used in slim hole drilling, which can also be used in conventional drilling, can be split into three types:

• Surface equipment
• BHA components
• Overall system design and selection of operating parameters.

1 Surface equipment - the soft torque rotary table/top drive

The soft torque rotary table/top drive is a small modification to the electronics in the SCR (silicon controlled rectifier) independent electric drive system which minimises the reflection of the torsional vibrations arriving up the drillpipe during drilling. It is an "active" dampening system in the sense that the electronic feed back system senses the torsional vibrations arriving up through the drillstring and modifies the energy flow through the electric motor to minimise the vibrations. Most rotary drive systems have considerably greater mechanical impedance than the drillpipe and thus act as excellent reflectors of torsional waves.

2 Surface equipment - drawworks feed off

The drawworks feed off should be as smooth as possible during drilling. Most of the land rigs are equipped with a hydraulic feed off system which was originally installed to reduce noise levels. When drilling this can contribute to minimising longitudinal vibrations. If available, a four-quadrant control system on the drawworks motor SCR system can be used.

3 Surface equipment - Extended scale instrumentation

Extended scale instrumentation should be used. A drillers instrument panel giving a fine resolution of standpipe pressure and hook load over the selected operating range should be used. If this is unavailable, a Martin Decker compound pressure gauge, which has recently been tested and calibrated, should be fitted to the standpipe. An accurate flow rate can be obtained from the Kick Detection System (KDS). When drilling slim hole the changes in WOB, torque and standpipe pressure are very small compared to conventional hole sizes. In particular standpipe pressure and flow rate, rather than WOB and torque become the primary control variables for efficient drilling operations.

4 Surface equipment - Heave compensator

The design and engineering of passive drillstring heave compensators (DSC) was based solely on simplistic quasi-static calculation, with little consideration of dynamic effects.

Passive DSC performance is a critical component of floating SHD. Improved DSCs lead to improvements in other operations, in particular kicking off directional and horizontal wells, fishing, workover and completion operations, and landing subsea equipment.

The possible improvements on DSCs include:

• Replacing the water glycol fluid with a less dense, less viscous, non flammable, non freezing, safe to handle, environmentally friendly fluid.
• Minimising the resistance to flow of the hydraulic fluid by optimising pipe and fitting design.
• Reducing the stick-slip friction of the seals between piston and cylinder.

Even if substantial improvements were made to a passive DSC it would still be a less than optimum tool for SHD as, in order to enable it to function, it depends on the lower part of the string being supported by bit weight on the bottom of the hole, which is not the case when a thruster is in use.

5 BHA components

The BHA has to be considered as a complete subsystem with all components interacting.

5.1 Bits and coreheads

In order to integrate the bit into the overall BHA the following information should be supplied by the manufacturer: size, connection, TFA, estimated aggressiveness sharp, estimated aggressiveness blunt (for the range of formations expected to be drilled) max. rpm, max. WOB sharp, max. WOB blunt.

5.2 Moineau motors

In order to integrate the motor into the overall BHA the following information should be supplied by the manufacturer: The specific torque (i.e. torque per unit pressure drop), maximum operating differential pressure, stall differential pressure, max. RPM, max. and min flow rates, max. WOB, max. temperature. All these should be corrected for downhole conditions as far as possible.

5.3 Thruster

The thruster is a device for damping out longitudinal vibrations. The basic concept is that of a drillstring element which acts as a hydraulic piston with a higher pressure inside than outside, due to the pressure drop across the bit (and Moineau motor, if run). The thrust of the piston due to this differential pressure is the bit weight.

Important applications are:

• behind steerable motors in oriented mode
• for milling inside cased hole and for milling long stretches of casing prior to making a production sidetrack

5.4 MWD

The pulses from the MWD tool interact with mechanical vibrations. Reducing mechanical vibrations improves pulse transmission. Running a thruster reduces the interactions between mud pulses and mechanical vibrations. WOB variations due to mud pulses are reduced when a thruster is run. For optimum vibration minimisation the MWD should be located above the thruster.

5.5 Drill collars

Drill collars can be run above the thruster in vertical holes. When a thruster pushes down on the bit it also pushes upwards on the drill collars. This force will try to buckle the drill collars. Large contact forces between the buckled DC and the hole wall lead to stick-slip friction. The number of drill collars required to keep the neutral point below the DP is the same whether a thruster is run or not. Therefore the DC string should be stabilised to prevent the DC bodies between stabilisers/ roller reamers contacting the walls. As longitudinal vibrations are reduced the neutral point may be closer to the top of the collars than normal. Jars and accelerators should be run in tension. HWDP should be run above the DC as a transition.

5.6 heavy weight drillpipe (HWDP)

Heavy weight drillpipe can also be used in vertical holes in place of some or all of the drill collars if buckling can be tolerated. When such pipe is buckled substantial wall contact forces are developed which can give rise to significant stick-slip friction, both longitudinally, if the string is not rotating, and tangentially, if it is rotating. If the string is buckled while rotating then there will be a higher fatigue loading on the string and stick-slip torsional vibrations can be expected. To minimise these fatigue loads extra wear "knots", which have similar dimensions to tool joints, can be fitted to the pipe body. These geometrically constrain the buckling. This is the "knotty" pipe, which has the same internal dimensions as conventional pipe. Conventional DP with non-rotating protectors can also be used for this purpose.

The advantages of eliminating some or all of the drill collars are reductions in ECD, drag, string weight, and BHA handling time, and an ability to build round a tighter radius for horizontal wells. Hydraulic dynamic pressure drops up the annulus, and hence ECD, are dependent not only on the geometry of the annulus, but also on the drillstring rpm. Application of this would enable drilling to proceed with motor, thruster, MWD, and practically no DC, but with drillstring rotation of say 5 rpm, using a soft torque rotary drive system. Such an approach would enable drilling to safely proceed with minimum ECDs, and maximum flow rate. This would give high mechanical and hydraulic power to the bit and good cuttings transport.

6 Hydraulic buckling

Hydraulic buckling is a detailed phenomena that emerged during studies into the action of thrusters and their interaction with the rest of the BHA. This is a product of the interaction between the fluid and mechanical forces on a buckled (knotty) drillpipe, which is normally ignored in conventional drilling, but which may become significant in smaller holes. When the pipe body between two stabilisers, tool joints, or "knots" (which can be considered to act as pivots) is subject to longitudinal compression the geometric centreline of the pipe body assumes the shape of an arc. Due to the elastic deformation of the pipe body as it is bent round the arc the area of the pipe wall on the outside of the bend is slightly greater than that on the inside of the bend, but the internal pressure acting on them is the same. The resultant forces reinforce the buckling tendency of the pipe; the greater the bend in the pipe becomes due to buckling, the greater these hydraulic buckling forces become.

7 Overall system design and selection of operating parameters

Optimised BHA and operating parameter design is an important part of the total integrated approach. For slim hole drilling, close integration with the other aspects of the drilling system such as bits and hydraulics is essential.

8 Other anti-vibration technology

Surface equipment in general offers the cheapest approach to vibration minimisation.

The soft torque rotary table/top drive will form the basis of a number of developments. The hook load, motor torque (amps), speed, voltage, the control signals inside the soft torque control system, etc. will be analysed using techniques similar to those used for condition monitoring of rotating equipment. This will enable the driller to change the operating parameters to minimise vibrations.

Mud pump pulsation dampening should be optimised as the pulsations in the mud interact with other vibrations. Currently this can only be done by optimising the precharge pressure of the pulsation dampers. Concepts exist for active dampening of these pulses. This will reduce coupled vibrations, fatigue loads on surface equipment, reduce pump and drive system maintenance costs, and improve the transmission of MWD pulses, enabling higher data rates to be used.

Stick-slip torsional vibrations will be combated by lowering the threshold rpm at which they disappear. Various devices minimise the torsional friction on buckled pipe such as non-rotating stabilisers, or a coating on the outside of the tool joints and wear knots which minimises friction with the formation, or a roller reamer stabiliser design.

Advanced anti-vibration systems based on the principle of the thruster can also be considered.