Slow and steady wins the race

Chris Gooch, Ulterra Drilling Technologies, USA, explains how incremental steps can bring large-scale changes to reliability, efficiency and economics in the drilling environment.

In the upstream drilling industry, drilling performance is often equated with records and milestones – fastest well, longest section, operator records. News feeds are saturated with these matter-of-fact stories. Few are talking about the incremental gains over time that make up the majority of good, reliable, consistent performance, even though it is this kind of continuous improvement that brings the most success. The best economic outcome, for both the service supplier and their client, comes from continuously improving the tools, equipment and drilling practices. In North American land drilling, this approach has led to the region being one of the fastest, most efficient and economical drilling markets in the world. This article will discuss how incremental improvement resulted in meaningful drilling performance gains in a critical West Texas, US, application.

In Midland County, Texas, the typical well plan would complete the vertical section in 12 ¼ in. hole size before drilling the curve and lateral in 8 ½ in. (Figure 1). The curve is difficult, building from vertical to horizontal in typically less than 1000 ft with high doglegs and near-continuous sliding. The same bit and drilling assembly are then expected to continue drilling into the horizontal as far as possible, with many completing at least half of the approximately 10 000 ft lateral. On some occasions, a single bit and bottomhole assembly (BHA) will complete the entire section in a single run. Penetration rates average above 100 ft/hr – slower in the curve section while executing directional work, but much faster when rotary drilling.

There are two primary keys to success in this kind of section: first, a stable toolface in the curve, and the second is to track straight in the lateral. To maintain a stable toolface in the curve, both the bit and the motor must work well together, along with a BHA layout that suits the directional requirement. The motor should deliver consistent torque and have sufficient torque capacity to keep doing so, even when high weight is applied. The bit, in turn, needs to develop a smooth and predictable reactive torque over a wide range of weights and revolutions per minute (RPM). The continuous balance between the driven torque from the motor and the reactive torsional force from the bit keeps a stable and predictable toolface that the directional driller can use to slide easily while drilling ahead.

Tracking straight in the lateral section depends on drill bit dynamics and the reaction to drill string orientation because of frictional forces. In a horizontal section, the natural tendency of

Figure 1. A typical well plan in the subject application.

Figure 2. The final bit design after multiple design iterations.

Figure 3. Average curve drilling times reducing over a 6-month test period.

Figure 4. Average single run lengths increased over the 6-month test period.

a neutrally balanced bit is to walk right and drop under gravity, unless supported by a near-bit stabiliser. This is counteracted by the BHA and string sitting on the low side of the hole having rolling friction to the right while tilting the bit high as it fulcrums off either a stabiliser or another outer diameter (OD) component. If all these forces are in balance, the rotating drilling system goes straight and there is no need to stop and slide. The goal then is to maintain straight, rotary drilling for as long as possible so that slides are minimised and the overall ROP for the section is increased.

Ulterra has been going through a continuous process of tweaking the balance between all these factors in a Midland County application, in conjunction with a particular operator. Over a period of 6 months and more than 30 runs, the positions of cutters were changed and backrakes altered over multiple bit designs. The result was a better-balanced bit, not fully biased to ultimate straight-line speed or extreme durability, but rather more suited to the application overall (Figure 2). This gave the operator a product that drilled smoothly and with a predictable reactive torque, so that they could start to adjust and optimise other factors in the drilling process. By making the entire system more predictable, reliable and cohesive, the operator was ultimately able to reduce curve time and increase overall run distance, which had a significant impact on drilling cost.

With Ulterra’s 8 ½ in. curve and lateral application, the operator saw a continuous curve time reduction over 6 months (Figure 3). The average curve time reduced from 14.1 to 12.7 on bottom hours, an improvement of approximately 10% over the 34-well programme. Additionally, the same smooth and more efficient drilling action that was necessary to achieve this also resulted in better durability and reliability.

At the start of the campaign, there were no runs where a single assembly drilled all the way from the casing shoe to total depth (TD) of the well. Occasionally, the assembly was pulled out of the hole for bit-related issues; mostly it would be pulled to change BHA configurations for the lateral and the bit would be replaced out of routine. In the last 2 months of this programme, 50% of runs were shoe to TD with close to 11 000 ft total drilled per run, saving significant time on expensive round trips to the surface. This indicates greater reliability, improved directional control in the curve and increased time tracking straight in the lateral, removing the need to change the BHA.

Collectively, these changes resulted in the significant increase of 60% to the average run length of these curve-lateral applications, increasing from approximately 4600 ft per run to 7300 ft (Figure 4). Over time – as the improvements were employed across additional runs – operator cost savings quickly compounded, and complete improvements to the bit, BHA and drilling process were implemented.

When assessing factors such as reliability and predictability, single run records and simple one-pad comparisons are not sufficient; instead, multiple runs over time should instead be considered in order to see the true impact. Incremental changes make smaller improvements, but ultimately modest time and cost savings made over tens or hundreds of runs quickly multiply into significant economic improvements; something that is crucial to operators and investors in the current upstream drilling market.