Drilling Techniques

 

If we consider a well trajectory from surface to total depth, it is helpful to look at the shallow section and the intermediate and reservoir intervals separately.

The shallow section, usually referred to as top hole, consists of rather unconsolidated sediments, hence the formation strength is low and drilling parameters and equipment have to be selected accordingly.

The reservoir section is more consolidated and is the main objective to which the well is being drilled, hence the drilling process has to ensure that any productive interval is not damaged.

Top hole drilling:

For the very first section of the borehole, a base from which to commence drilling is required. In a land location, this will be a cemented ‘cellar’ in which a conductor or 

stove pipe will be piled prior to the rig moving in. The cellar will later accommodate the ‘Christmas tree’ (an arrangement of seals and valves to control production), once the well has been completed and the rig has moved off location.

As in the construction industry, piling of the conductor is done by dropping weights onto the pipe or using a hydraulic hammer until no further penetration occurs.

In an offshore environment, the conductor is either piled (e.g., on a platform) or a large-diameter hole is actually drilled, into which the conductor is lowered and cemented.

 Once the drill bit has drilled below the conductor the well is said to have been spudded.

The top hole will usually be drilled with a large-diameter bit (between 22 and 27 in. diameter). The drill bit (roller cone type) will be designed to drill predominantly soft formations.

 As a result of the hole diameter and the rapid penetration rate, vast quantities of drilled formation will have to be treated and removed from the mud circulation system.

Intermediate and reservoir section:

Between the top hole and the reservoir section, in most cases, an intermediate section will need to be drilled. This section consists of more consolidated rocks than the top hole. The deviation angle is often increased significantly in this interval to reach the subsurface target, and lateral departures from the surface co-ordinates may reach several kilometers.

 Based on pore pressure prediction (from seismic or measured data from offset wells) the mud weight has to be determined. The pressure exerted by the mud column has to exceed the formation pressure in order to maintain overbalance and prevent the hole from collapsing but has to be lower than the fracture pressure of the formation.

 If the formation strength is exceeded, fracturing may occur, resulting in mud losses and formation damage.

Borehole/formation stability is the realm of geomechanics. Challenges in well planning arise when rock strength and thus borehole stability show considerable variations depending on hole angle and direction, as shown in the Figure.

 In this example, the small difference between fracture gradient and collapse gradient at high deviation may require a revision of the initially planned well trajectory through the intermediate and/or reservoir section.

An intermediate casing is usually set above the reservoir in order to protect the water-bearing, hydrostatically pressured zones from influx of possibly over pressured

hydrocarbons and to guarantee the integrity of the wellbore above the objective zone. In mature fields where production has been ongoing for many years, the reservoir may show depletion pressures considerably lower than the hydrostatically pressured zones above.

Before continuing to examine the aspects of drilling through the reservoir, remember that the reservoir is the prime objective of the well and a very significant future asset to the company.

If the drilling process has impaired the formation, production may be deferred or totally lost. In exploration wells, the information from logging and testing may not be sufficient to fully evaluate the prospect if the hole is not on gauge, necessitating sidetracking or even an additional well.

On the other hand, there is considerable scope to improve productivity and information value of the well by carefully selecting the appropriate technology and practices.

Directional drilling:

Directional drilling is usually done with a rotary steerable system. A downhole steering and control unit is located in the near-bit assembly. A set of small electronically controlled rotating stabilizer pads (actuators) exert a continuous directional force onto a drive shaft which orients the drill bit into the desired

direction. The drill string is rotated at the same time, allowing hole cleaning.

A control unit near the bit ensures that the hole angle is not increased or decreased rapidly creating ‘dog legs’ which will result in excessive torque and drag. The rotary steerable system is combined with logging tools in the drill string close to the bit, allowing a continuous optimization of the well trajectory.

Mud turbines and mud motors are also used for directional drilling. Rotational movement of the drill string is restricted to the motor or turbine section, whilst the rest of the drill string moves by ‘sliding’ or being rotated at a lower speed to ensure hole cleaning.

In the example of the turbine shown in the Figure, the mud is pumped between the rotor and the stator section, inducing a rotational movement which is transmitted onto the drill bit.

 Motors and turbines are being replaced by the rotary steerable system for cost and operational reasons. Their use is increasingly limited to such applications as kicking off a sidetrack or where a sharp change in angle is required in a short-radius horizontal well.

Advances in drilling and completion technology today allow us to construct complicated wells along 3D trajectories. In addition to vertical wells, directional drilling allows us to build, maintain or drop hole angle and to turn the drill bit into different directions. Thus, we are able to optimize the well path in terms of reservoir quality, production or injection requirements. Sometimes constraints at the surface (e.g., built-up areas) or subsurface (e.g., shallow gas, faults, lenticular reservoirs) may require a particular well trajectory to be followed.

The steering of the well is supported by the stabilizers which form part of the drill string. The blades can be activated and deactivated from the surface depending on whether the angle is to be maintained, increased or decreased.

High deviation angles (above 60) may cause excessive drag or torque whilst drilling and will also make it difficult to later service the well with standard wireline tools.

Horizontal drilling:

Given the lateral distribution of reservoir rock or reservoir fluids, a horizontal well may provide the optimum trajectory. the Figure shows the types of horizontal wells being drilled. The build-up rate of angle is the main distinction from a drilling point of view. Medium radius wells are preferred since they can be drilled, logged and completed with fairly standard equipment. The horizontal drilling target can be controlled within a vertical window of less than 2 m.

The success of horizontal wells was largely dependent on the development of tools which relay the subsurface position of the drill bit in real time to the drill floor.

Improvements in this technology have greatly improved the accuracy with which well trajectories can be targeted. MWD is achieved by the insertion of a sonde into the drill string close to the bit. Initially providing only directional data, the tools have been improved to the point where petrophysical data gathering (gamma ray [GR], resistivity, density and porosity) can be carried out whilst drilling.

Most reservoirs are characterized by marked lateral changes in reservoir quality corresponding to variations in lithology. Computing tools now commercially available allow the modelling of expected formation responses ‘ahead of the bit’.

This is possible in areas where a data set of the formations to be drilled has been acquired in previous wells. The expected GR and density response is then simulated and compared to the corresponding signature picked up by the tool. Thus, in theory, it is possible to direct the bit towards the high-quality parts of the reservoir.

Resistivity measurements enable the driller to steer the bit above a hydrocarbon water contact (HCWC), a technique used, for example, to produce thin oil rims.

These techniques, known as geo steering, are increasingly being applied to field development optimization. Geo steering also relies on the availability of high-quality seismic and possibly detailed paleontological sampling.