An engineer can never go wrong by returning to the fundamentals, which allowed success in the past. Often enough though, these fundamentals tend to be forgotten in a fast-paced technological world. The oil and gas industry is no exception.
The race in the early 1990s to develop and market formation evaluation while drilling tools changed the industry's focus from traditional geometrical, to a geological well planning and steering approach. In this transition, the basic directional survey measurement took a backseat to formation evaluation measurements.
"We (as an industry) sold our soul for more information," is an often stated summary of that shift. However, "what goes around, comes around," and the fundamental directional measurement is again literally, leading the way, optimizing even further the geological measurement that put it in the back seat a decade ago.
Directional drilling originated as a geometric control technique to address the industry's need for drilling radially from a single wellbore and exposing more producing reservoir. Single - and if you were lucky, multi-shot - surveys were the norm for surveying the directional path of the wellbore. This method was cumbersome and time consuming.
Electronics technology improved over time yielding a "while-drilling" alternative for directional surveying a well, and eventually evolved into what is commonly referred to as while-drilling measurement tools. Directional surveying time decreased dramatically and kept drilling assemblies on bottom, drilling ahead.
While-drilling logging technology and geo steering techniques later developed, to optimize this geometric steering process. These techniques were used to confirm the geometric plan, achieving the required geologic goals set forth in the original well plan. Basically, the formation evaluation measurement took priority over the geometric measurement.
One effect of this change in drilling practice was the improved ability to keep the wellbore in the reservoir pay zone longer. In the case of horizontal well bores, this led to greater lateral reservoir exposure. The downside effect of this was increased tortuosity, and the inevitable depth limitations on current technology. "Running out of drill weight" is a common occurrence.
Reduction of total wellbore friction allows for greater extended well length capability.
Now, with ruggedized sensor electronics placed at the bit, the industry has returned to use of the most fundamental measurement of any measurement-while-drilling string - inclination. This geometric measurement is again being used to supplement technically advanced geological information, and to extend wells even farther than previously thought possible.
Bit inclination measurement systems were made commercial in the middle 1990s. The concept has been passed around the industry for over a decade, but not realized until recently. Mechanical integrity and operational accuracy issues in a very rough operating environment were the main hindrances to sensor development.
The measurement started, and can still be used, as a separate instrumented sub, making it a versatile addition to existing conventional drilling assemblies. Further product development has resulted in sensor electronics integrated into motors and steerable systems.
The addition of bit subs to motors and steering tools increases the bit to bend-point on the steering motor, resulting in reduced directional response and control. The shorter this distance, the more aggressive the build-response of the tool. Also, drillers have better control over the bottom hole assembly.
A small, inclination measurement package can be integrated into this configuration easily. Mounted in, or near the bit box of the motor, this measurement package is optimally placed for getting greater efficiency out of traditional steering techniques.
Horizontal wells present a unique challenge. Azimuth change in a horizontal borehole is extremely difficult with conventional steering assemblies. Trajectory change in the horizontal plane can be minimal, to impossible in some cases.
The ability to keep a bent housing motor oriented in a desired direction, with the full gravity component acting on the motor, is at best, difficult. The added problem of not getting efficient surface weight transfer to the bit limits the ability to make trajectory changes, even if a driller can keep the motor oriented properly.
Bit inclination measurements help eliminate correcting for the natural tendency of a roller cone bit in a rotary drilling assembly to have a slight right hand turn. Directional drillers now plan for this ahead of time and build the well path slightly left of the planned target on bit runs prior to reaching total depth, or production hole bit runs. The final rotary assembly then naturally right-hand turns toward the planned target.
Eliminating this "pre-alignment" of hole orientation results in reduced drilling time, less overall wellbore friction, extended total depth capability, and a better chance of logging and completion success.
The recent implementation of rotary steerable systems is eliminating some of these problems and extending wells further. A near-bit directional measurement increases the ability of these systems to automatically detect, and correct, trajectory deviations. This enhanced control leads to a more "gun barrel" wellbore and more efficient drilling.
An observation could be made that bit measurements create a "knee-jerk" reaction, causing too much over-correcting, and thus, well tortuosity related problems. This fortunately appears not to be the case.
Quicker directional trend indications allow for frequent, less aggressive corrective activities, giving more effective directional control. The positive result is reduced tortuosity of the wellbore and reduced drillstring friction.
Previous while-drilling surveying and geosteering technologies made it difficult to maintain a wellbore within small vertical tolerances. Extended distances between the survey measurement and the bit, brought about by the addition of while-drilling logging tools, resulted in hole trajectory uncertainties which could only be estimated through extrapolation techniques. Although not preferred, extrapolating a survey measurement often greater than 100 ft to the drill bit is a good estimate, in most cases.
As the overall gravity effects on the drillstring increase, so does the the error in the estimate. An increase in survey-to-bit length, decrease in drillstring stabilization, and low formation strengths, add to the downward gravity, causing a natural drop tendency effect on the lower section of the bottom hole assembly. Trajectory correction is then required by the driller, introducing more tortuosity in the wellbore. Any reduction in the frequency of corrections required will lower overall wellbore friction.
At-bit measurements have given drillers the ability to make smaller, quicker trajectory changes, steering the wellbore within vertical windows of 1-3 ft in height and lowering overall well bore tortuosity. This gives operators a very powerful technique to utilize in thin-bedded reservoirs, steering in close proximity to oil-water contacts, and steering parallel to bedding planes in dipping beds.
Hole size applications
Increased utilization of slimhole, short radius, and horizontal drilling methods, has created a proving ground for at-bit measurements. The result has been smaller tools for hole sizes less than 6 ½-in. being developed first. The success of these smaller tools has generated a demand for services in larger tool sizes.
Greater gravity force on the bottom hole assembly yields a higher potential for directional trajectory corrections in the vertical plane.
Benefits of the near-bit inclination measurement are being realized in surface hole directional drilling problems such as kicking off, nudging operations, and shallow water flow problems.
Electronics packaging in these bigger tools is easier because of the higher volume/space ratio. If popularity continues to increase expect to see bit inclination measurements become a standard service for all directional steering assemblies.