Because of the inherent curvature (angle build sections) and angled bottomhole segment of directional and horizontal wells, optimization of a progressive cavity pump (PCP) system design for such applications begins with the drilling program. The proposed well geometry, or directional plan, should take into consideration the design and operation attributes of a PCP system, including equipment selection, to contend with potential rod/tubing-wear and rod-string fatigue problems, the preferred pump seating location for achieving optimal production rates throughout the well life, and possible issues related to gas and solids production. The first line of defense against rod/tubing-wear and sucker-rod fatigue problems in deviated and horizontal wells is a good wellbore profile (see previous sections on rod-string/tubing wear and rod loading).
A directional well can be divided into three main sections--the surface hole, overburden section, and reservoir penetration. Different factors are involved at each stage within the overall constraints of optimum reservoir penetration. Most directional wells are drilled from multiwell installations, platforms, or drillsites. Minimizing the cost or environmental footprint requires that wells be spaced as closely as possible. It has been found that spacing on the order of 2 m (6 ft) can be achieved.
Directional drilling is defined as the practice of controlling the direction and deviation of a wellbore to a predetermined underground target or location. This section describes why directional drilling is required, the sort of well paths that are used, and the tools and methods employed to drill those wells. Field developments, particularly offshore and in the Arctic, involve drilling an optimum number of wells from a single platform or artificial island. Directional drilling has helped by greatly reducing the costs and environmental impact of this application. A well is directionally drilled to reach a producing zone that is otherwise inaccessible with normal vertical-drilling practices.
A properly designed and maintained drilling fluid performs essential functions during well construction such as transporting cuttings to the surface, preventing well-control issues and wellbore stability, minimizing formation damage, cooling and lubricating the drillstring and providing information about the wellbore. Transporting drilled cuttings to the surface is the most basic function of drilling fluid. To accomplish this, the fluid should have adequate suspension properties to help ensure that cuttings and commercially added solids, such as barite weighing material, do not settle during static intervals. The fluid should have the correct chemical properties to help prevent or minimize the dispersion of drilled solids, so that these can be removed efficiently at the surface. Otherwise, these solids can disintegrate into ultrafine particles that can damage the producing zone, and impede drilling efficiency.
There are limitations, as well as advantages, to underbalanced drilling (UBD). Before embarking on a UBD program, the limitations of the process must be reviewed. There are technical limitations as well as safety and economic limitations to the UBD process. Wellbore stability is one of the main limitations of UBD. Borehole collapse as the result of rock stresses is one issue to consider.
No other technology used in petroleum-well construction has evolved more rapidly than measurement while drilling (MWD) and logging while drilling (LWD). Early in the history of the oil field, drillers and geologists often debated conditions at the drillbit. With advances in electronic components, materials science, and battery technology, it became technically feasible to make measurements at the bit, and transmit them to the surface so that the questions could be answered. Directional measurements were the first measurements to have commercial application, with almost all use in offshore, directionally drilled wells. As long as MWD achieved certain minimum-reliability targets, it was less costly than single shots, and it gained popularity accordingly.
The following are some of the most common sources of error in directional drilling. The survey instrument's performance depends on the package design elements, calibration performance, and quality control during operation. System performance will functionally depend on the borehole inclination, azimuth, geomagnetic-field vector, and geographical position. Because of the dependency on sensing Earth's spin rate, the performance of gyro compassing tools is inversely proportional to the cosine of the latitude of wellbore location. Gyros suffer from the additional problem of time-related drift uncertainty.
The bottom hole assembly (BHA) is a portion of the drillstring that affects the trajectory of the bit and, consequently, of the wellbore. The BHA design objective for directional control is to provide the directional tendency that will match the planned trajectory of the well. The bit side force is the most important factor affecting the drilling tendency. The direction and magnitude of the bit side force determine the build, drop, and turn tendencies. Note: Rotary Steerable Assemblies are a notable exception to the comments below and are used as directional assemblies that can be steered and are used to build, drop, or hold angle and can be controlled from surface.