Theodore Levitt once said people may buy hand drills, but it is the holes they want. Provide a better, more cost-effective way of making holes, and people will buy it. Is our industry any different?

During the past decade, rotary inclination control has been proven as a better, more cost-effective way of making holes, especially in horizontal, extended-reach, S-shaped or slant wells. For instance, in BP's Harding or Total's Tierra del Fuego fields, an Andergauge tool has controlled true vertical depth to ±3ft (1m) over section lengths of 3,300ft (1,000m). This degree of accuracy has met such geological objectives as maximizing the productive life of the well or maintaining standoff between gas-oil contact and the water-oil contact. In the Tunu S-shaped wells of Indonesia, the technology routinely has helped drill the tangent and drop-off sections in single bit runs. In all these well types, drilling is accompanied by a host of invisible improvements to hole quality.
Hole quality
The trouble with buying holes is that you can't see the quality of your purchase. However, the industry recognizes several steps to ensure the hole is in good shape. One is to reduce the number of doglegs, or abrupt changes, in curvature. This creates a smoother wellbore with lower tortuosity and an improved profile. The lack of high doglegs is the real beauty of the system, as changes in hole curvature are smoothed out over entire sections (Figure 1).
In contrast, oriented inclination control can create a series of kinks in the hole each time a "slide" is conducted, increasing the likelihood of transition ledges, keyseating and reaming. These kinks, or miniature doglegs, can increase torque and drag within the hole and casing.
Holes with low curvature tend to generate lower wall-contact forces. This, in turn, lessens the need for bottomhole assembly (BHA) or drillstring torque and drag reduction devices. Typically, these are time-consuming, with nonrotating drill-pipe protectors or subs made up between connections. Less torque and drag means a lower dependence on low-torque drilling fluids or additives. Additionally, higher specification top-drive systems become optional, not obligatory.
Smoother hole profiles permit casing to be set and cemented more easily. Casing wear, caused by constantly rotating drill pipe through highly tortuous wells, also is reduced. Consequently, there is less likelihood of such costly operations as replacing or recladding casing.
Another step to a quality hole is good hole cleaning. It is no secret rotary drilling mechanically agitates cuttings so they are circulated out instead of forming beds. This decreases the time spent circulating at section total depth
to improve hole conditions.
Low tortuosity also makes it easier for tubulars and production tubing to pass through the wellbore without damaging anything. In the end, the benefits of holes with low tortuosity go beyond drilling and production. Consider re-entries - it is easier to cut and pull casing out of a smooth hole than a tortuous one.
Optimized wellbore placement
Apart from drilling a good quality hole, rotary inclination control can maximize production and increase the value of the well. Extensions of up to 1,200ft (366m) in the reservoir section have been documented in the Austin Chalk. Data from other wells drilled in the area showed how such sections had ended prematurely due to an inability to drill in oriented mode. In such cases, oriented drilling can dramatically affect a well's cost and production. For instance, drilling costs can increase due to nonproductive orienting time; the horizontal section may be terminated earlier than planned, thereby limiting production; or in a high day-rate environment, the cost of an extremely low rate of penetration (ROP) may render drilling prohibitively expensive. However, rotary drilling consistently yields higher ROPs and reduced drilling time.
PDC synergies
Orienting with a polycrystalline diamond compact (PDC) bit is recognized as being difficult, and in certain formation types this can limit optimal bit choice. PDC bits can be used with an Andergauge tool to drill horizontal sections effectively and efficiently. This has led to fewer rock bit trips and better ROPs. Considering PDC bits have a tendency to drill straight and a large number of horizontal sections are drilled with PDC bits, bit walk is not a problem. (Rock bits tend to walk, usually to the right).
Many industry studies and analyses report directional corrections are unlikely within 90% of horizontal or tangent sections, and a rotary inclination system often can drill to target depth in a single bit run. One possible explanation for this is as wellbore inclination increases, bit walk becomes a less significant consideration to the directional driller. Therefore, it is not directional control, but rather inclination control that is required in the majority of horizontal or tangent sections.
3D rotary steerable system
Where directional corrections are expected, the tool can be configured above a motor. This can minimize oriented drilling for inclination control, resulting in higher gross ROP and reduced time in drilling the section. The Andergauge tool is simply cycled between full gauge and undergauge to maintain an optimal inclination. Any bit walk problems can be solved or azimuth targets met without the need for sophisticated technology.
Slide analysis
In today's market conditions, where workload can outweigh workforce, operators or directional drilling companies may not be able to dedicate resources to analyze slide data. Consequently, the bottom-line costs of low ROP and the time spent orienting for inclination control may go unrecognized.
Sometimes when a slide analysis is conducted, sections may simply be classified as "good" and filed away. These classifications usually refer to a lack of equipment failure or relatively high total ROPs with minimal sliding. These "good" sections can obscure the costs associated with oriented drilling. At other times, the tendency is to express sliding as a percentage of total section distance.
This creates the common misconception that a relatively short length of sliding is involved, which then may be labeled "minimal sliding." Sliding should be analyzed in terms of cost, not just distance or time involved. For example, analysis of "minimal sliding" can reveal sizeable but preventable hidden costs.
Operations
A typical horizontal BHA could comprise a 6in. bit, a near-bit Andergauge, a 10ft drill collar and a 55/8in. first string stabilizer. The latter also is known as a control stabilizer because its diameter dictates the possible range of inclination responses of the near-bit or fulcrum stabilizer - the rotary inclination control system.
When the tool is in the full gauge position, this creates a hold or a slight build tendency. Conversely, in the minimum gauge position, the BHA has a drop tendency.
Let's suppose this BHA initially holds angle, but due to a change in formation conditions, it begins to build angle. Clearly, the directional driller will want to maintain the designated inclination; he will deactivate the tool. This action dramatically changes a fulcrum or build assembly into a pendulum or drop assembly. The build tendency is arrested, and inclination is controlled. The exact response will depend on the ability of the BHA to flex. This is determined by the diameter of the first string stabilizer, the length and rigidity of the drill collar, the length of the pendulum assembly, the inclination of the wellbore and the ability to apply weight on bit.
Two points are worth noting. The first concerns dogleg severity (DLS), or hole curvature between two points 100ft (30m) apart. A 3° DLS created by rotary drilling is a true expression of hole curvature, because changes in inclination are effected by rotary trends, not instantaneous doglegs. In contrast, a 3° DLS resulting from oriented drilling can obscure a series of mini doglegs or a large dogleg that was created to maintain inclination. Figure 1 shows a typical rotary-drilled wellbore, which is a smooth curve, whereas the curvature of an oriented wellbore is a series of doglegs (sliding high or low side) interspersed with straight sections (rotary drilling).
The Andergauge Rotary Inclination Control System has been successfully used to control the inclination of more than 4,500 sections in near-bit, string, above- and below-motor configurations in differing well profiles. Being used in some 500 horizontal wells has built the tool's reputation for drilling horizontal, tangent and drop-off sections effectively and efficiently, routinely meeting tight total vertical depth corridor objectives (with an accuracy of ±3ft or 1m) as well as yielding a host of benefits related to hole quality.
Acknowledgments
The author thanks G. Wood of Baker Hughes Inteq and A. Eddison of Andergauge Ltd. for their advice and comments, as well as D. Tulloch for her work with the Andergauge Ltd. run database. This article is based on SPE Paper 65504, presented at the 2000 SPE/Petroleum Society of CIM International Conference on Horizontal Well Technology in Calgary, Alberta, Nov. 6-8, 2000.