TBS steering improves economics in Bakken wells

Two long laterals recently drilled in the Bakken shale used Weatherford’s targeted bit speed (TBS) technology, the MotarySteerable system, as an economic alternative to rotary steerable drilling. The drilling achieved 93% rotation in the laterals compared to approximately 70% in offsets. In one of the wells sliding time was reduced from 30% to 8%, saving seven days of rig time.

In the North Dakota sector of the Bakken play an industry shift to longer laterals between 2,286 m and 3,048 m (7,500 ft and 10,000 ft) has presented significant issues with hole cleaning, ledging, and reduced ROPs. Rotating the drill-string is key to improving performance, but rotary steerable systems (RSS) are uneconomical for many operations.

By enabling full rotation and 3-D directional control using positive displacement motors (PDM) and MWD tools, the TBS technology provided a lower cost alternative that reduced drilling time and improved wellbore geometry with consequent cost savings.

Rotating conundrum

FIGURE 1. Well 1 was a horizontal well drilled in a northerly direction to a total depth of 5,984 m (9,632 ft) with 3,114 m (10,217 ft) of lateral leg. It had a total of four bit runs in the lateral leg with an average ROP of 11.6 m/hr (38.08 ft/hr). The horizontal plot shown measures true vertical depth (Y axis, left) vs. wellbore measured depth (X axis, top). (Images courtesy of Weatherford)

PDMs have been used for decades to reliably and economically steer wellbores along a desired path. Early designs had a straight motor housing, and in the early 1960s bent housings were developed for drilling directional wells.

In these applications drillstring rotation was stopped while the downhole motor was used to turn the bit. Directional drilling was achieved by orienting the bent housing along the desired toolface.

This sliding methodology, in which the drillstring is not rotated, reduced the drilling efficiency and created hole-cleaning problems – especially in tortuous wellbores.

The solution for some wells came with development of RSS in the mid-1990s. Continuous rotation and full 3-D directional control eliminated many challenges and produced a smoother wellbore that was easier to drill, case, and complete.

However, higher operating expenses and lost-in-hole costs prohibited RSS use in many lower budget operations. These costs are reduced with TBS technology, which offers the potential for full rotation (no sliding) with 3-D directional control using two well-established directional drilling tools: mud motors and MWD.

TBS technology

Directional control using TBS technology is achieved by modulating the flow of mud through the motor power section in relation to the toolface. This periodic flow is achieved with a standard MWD positive pulse telemetry device. The pressure pulses are timed to the motor housing’s angular position to precisely vary bit speed as a function of the toolface.

The result is that a disproportionately greater volume of rock is cut from a specific arc segment of the borehole, causing the hole trajectory to follow in the direction of the higher bit speed. The steering mechanism moves the well path toward the target by increasing bit rpm and ROP, and lowering them moves the path away from the target.

The smaller the hole size, the larger the impact of the system. A 4.75-in. system in a 6-in. hole can build approximately 3° per 30 m (100 ft); an 8-in. system in a 12.25-in hole may only provide 1° per 30 m. If sufficient doglegs are not generated in TBS mode, the system offers the flexibility of orienting the motor conventionally and sliding to achieve higher build rates.

Bakken drilling

In the Bakken two development wells were drilled using TBS technology. Both used the same drilling rig and crews and similar oil-based mud systems. Key performance indicators for comparison included ROP, slide time, and days on location.

Offset wells drilled with conventional mud-motor steerable assemblies typically exhibited sliding times averaging 25% to 30% of the total for the lateral; ROP while sliding was 25% to 50% of rotating ROP. Reducing sliding time offered a significant potential savings in rig time.

Well 1 was a horizontal well drilled to a total depth (TD) of 5,984 m (19,632 ft) with 3,114 m (10,217 ft) of lateral leg (Figure 1). It required four bit runs in the lateral leg with an average 11.6 m/hr (38.08 ft/hr) ROP.

An LWD failure resulted in early termination of the first run with no footage made. In the second run, the lateral leg was drilled from 2,870 m (9,415 ft) measured depth to 3,729 m (12,233 ft). Measured depth had TBS buildup rates as high as 2.3° per 30 m. Total rotary time was 47.67 hr and 9.92 hr oriented.

The third bit run continued the lateral to 4,872 m (15,983 ft) measured depth and achieved doglegs as high as 2° per 30 m with a total rotary drilling time of 82.5 hr and 20.25 hr oriented. Run 4 drilled to TD at 5,984 m (19,632 ft) measured depth. Doglegs reached 1.5° per 30 m, with a total rotary time of 77.5 hr and 30.5 hr oriented.

Well 2 was drilled to 5,557 m (18,232 ft) TD with a 2,730 m (8,956 ft) lateral. This well had two bit runs that averaged 9.35 m/hr (30.67 ft/hr) ROP (Figure 2). The first run used TBS technology to drill from 2,827 m to 4,378 m (9,276 ft to 14,363 ft) measured depth. The second bit run experienced problems after tagging bottom. A downhole software problem prevented the TBS mode from engaging. Instead of making a bit trip, drilling was continued, but increasing tortuosity ended drilling 427 m (1,400 ft) short of the target at 5,557 m (18,232 ft) measured depth. Torque and drag increased so significantly that no further sliding was possible.

FIGURE 2. The second well was another lateral application that was drilled in a northerly direction to a TD of 5,557 m (18,232 ft) with 2,730 m (8,956 ft) of lateral leg. The horizontal plot shown measures true vertical depth (Y axis, left) vs. wellbore-measured depth (X axis, top) for Bakken Well 2.

The second run demonstrated the ability when using the TBS system to seamlessly change to a conventional slide-rotate sequence without having to trip for a tool change. While the system could not be activated for this run, the ability to drill conventionally provided engineers with the option to continue.

Bakken results

In drilling the two wells the TBS system consistently achieved more than 93% rotation in the lateral section of both wells. This represents a significant improvement from offset wells, which were limited to approximately 70% rotation. On the first well sliding time was reduced from 30% to 8%, saving seven days of rig time and the associated drilling costs.

In addition, it was clear that the technology provided more precise steering control and a smoother wellbore. The second well was terminated short of the target TD because high frictional forces in the lateral leg could not be overcome. In Well 1, TD was reached with a smoother wellbore that resulted in a trouble-free casing run.

Enhanced economics, new wells

Using PDMs and MWD tools, the TBS system overcomes lateral drilling problems such as hole cleaning, ledging, and reduced ROPs that typically require a cost-prohibitive RSS. The TBS technology’s ability to rotate reduces drilling time and improves wellbore geometry for a new population of well candidates.