Rotary steerable drilling improves deployment of advanced completion

Bill Lloyd, Cirque Resources; Allen Starkey, Schlumberger;
and Josh Jany, Packers Plus Energy Services

In April 2008, the US Geological Survey assigned 3.65 billion bbl of technically recoverable reserves to the Bakken Formation in the Williston Basin of Montana and North Dakota, Fig.1. This assessment is, in part, incumbent upon the proper implementation of leveraging technologies that can economically recover the reserves. Success over the last four years has largely been in areas exhibiting higher than normal reservoir pressure gradient. The resulting flowing tubing pressure and high ratio of initial production to ultimate recovered reserves generates an improved cash flow profile. However, to recover the reserves indicated in the USGS report will increasingly require economically developing the areas of normally pressured reservoir that comprise the majority of the Bakken play.

Fig. 1. Map of the Bakken Formation in the Williston Basin showing Burke County, North Dakota, where the case study well was drilled.

Determining the optimum fracture stage interval length and total number of fracture stages across the horizontal wellbore has been instrumental to maximizing productivity and economics. As in other unconventional plays, Bakken operators have gravitated toward decreased stage length and increased number of stages. However, improving fracture complexity and efficiency presents challenges. Historical analysis of cemented laterals indicates that drilling fluid and filter cake removal and/or displacement is highly compromised in a lateral wellbore where insufficient pipe movement is achieved. For this reason, a cemented lateral inherently jeopardizes the ability to efficiently compartmentalize fracture stages. This limitation of cementing has led the majority of operators in the Bakken to rely on openhole isolation packers as the preferred method for stage isolation.

Openhole isolation packers have inherent risk, especially as the number of stages and packers increases. Long laterals drilled with conventional bent assemblies have resulted in multi-day reamer runs attempting to remove the tortuosity and hole rugosity commonly associated with wellbores drilled in this manner. In a number of instances, despite time-consuming reamer runs, completion assemblies with openhole packers have not been successfully run to bottom, resulting in reduced fracture efficiency, lost reserve capture opportunities and wasted capital for wellbores drilled but not completed. In addition, wellbore rugosity may compromise the differential pressure capability of certain openhole isolation packer designs during fracing operations.

In a drilling operation for Denver, Colorado-based producer Cirque Resources, the use of rotary steerable systems (RSS) was demonstrated to reduce the time and cost necessary to deliver an advanced openhole, multistage (OHMS) completion to target depth in the Bakken Formation. The combination of these drilling and completion technologies can be adapted and applied in virtually any resource play dependent on horizontal drilling and multistage fracturing.

OPENHOLE, MULTISTAGE COMPLETION

OHMS technology was pioneered in 2001 with the goal of making multistage fracturing more efficient, both in terms of time and cost, as well as more repeatable and reliable. The lateral is compartmentalized into the desired number of stages by running openhole packers as a part of the production liner to provide annular diversion while leaving the lateral uncemented. These packers typically have elastomeric elements that extrude or expand and seal against the formation through hydraulic/mechanical actuation or chemical reaction, respectively. Diversion inside the liner is provided by either plug-and-perf diversion or ball-on-seat diversion.

Plug-and-perf diversion first requires that a composite frac plug and perforating gun assembly be pumped via wireline from surface to a predetermined depth in the liner, which is isolated in the annulus by openhole packers. The frac plug is set and released, and the guns are then pulled back and fired to establish communication to the formation. The gun housings and plug-setting tool are then retrieved from the wellbore and a ball is displaced to seat in the plug, providing mechanical diversion above the plug and through the perforation tunnels into the formation. The stage is stimulated and subsequently flushed with a complete wellbore volume before the next plug-and-gun assembly can be pumped down to isolate the next stage. This process is repeated for the number of stages desired. Finally, coiled tubing or jointed pipe is used to drill out all the plugs in the wellbore before the well can be flowed back and ultimately put on production.

This method requires several service lines on location to execute the job with multiple interventions, increasing the chances for operational and safety-related issues. Common problems include premature setting of frac plugs requiring additional remedial services and time spent on location; stuck plugs/guns; and unsuccessful retrieval of the setting tool and spent gun housings. Additionally, each stage needs to be flushed with a minimum of two stage volumes to clear the wellbore of any residual proppant and displace the next plug-and-gun assembly on depth, potentially compromising near-wellbore conductivity. Efficiencies are also a concern: The requirement for multiple rig-ups of the different service lines and prolonged pump times to displace the plugs/guns extend operations over days and, in some cases, weeks. This presents a twofold problem: extended shut-in times as well as additional stand-by charges and scheduling issues with the pumping company, depending on market conditions.

Ball-on-seat diversion entails a fracture port run between openhole packers that actuates via a ball being pumped onto a seat. Hydraulic pressure applied from the surface shifts the tool open, exposing a series of ports that directly communicate to the formation. The fracture ports are run in the well with seats in ascending diameter, and balls are injected consistent with the seat diameter to stimulate the desired number of stages in the lateral. The main benefit of ball-on-seat diversion is that each ball can be timed with the flush of the previous stage to virtually eliminate over-displacement for each stage pumped. Furthermore, all stages can be pumped in a single, continuous pumping operation without the need for multiple service lines, saving time and cost as well as limiting risk exposure to operational and safety-related issues.

The cost for OHMS with plug-and-perf diversion is typically 20% more than OHMS with ball-on-seat diversion on a per-stage basis, which has historically forced operators to limit the number of stages in a single lateral to the maximum allowable with ball-on-seat diversion based primarily on economics and fracture operation efficiencies. With the recent introduction of “high density” ball-on-seat technology, operators have been provided with a more cost-effective means of increasing stage densities. Improvements in production optimization realized from higher-density staging, coupled with the coexisting trend for extended-reach laterals, have pushed operators in the Williston Basin to design hybrid OHMS consisting of ball-on-seat stages in the toe section of the lateral followed by plug-and-perf stages in the heel section, Fig. 2. This not only presents additional cost and increased mechanical risk during fracture operations due to the employment of plug-and-perf diversion, but, more importantly, it presents the challenge of successfully deploying OHMS with more external components in longer horizontal laterals.

Fig. 2. Graphic of a hybrid openhole, multistage completion system.

DRILLING AND HOLE PREPARATION

Successful deployment of OHMS is affected by the condition of the open hole. A smooth borehole improves the likelihood of running an OHMS to bottom, particularly in extended-reach laterals.

Conventional steerable assemblies. Conventional systems commonly used to drill lateral sections create spiral and porpoising effects that produce rugose and tortuous boreholes. Typical conventional assemblies consist of a bit, a downhole positive displacement motor with a 1.5° bend, a measurement-while-drilling (MWD) tool for hole surveys and gamma logging, followed by the remaining tubulars consisting of heavyweight pipe and drill pipe. The motor has a bend about 5 ft behind the bit that tilts the bit face and cutting structure from the bottomhole assembly axis. When rotating the assembly, the bit rotates off-center from the BHA axis and drills a slightly enlarged and spiral-shaped borehole. Downhole logging tools have shown this spiral effect in borehole images. Use of downhole stabilization in the BHA can minimize, but not eliminate, the spiral effect.

The MWD tool in a conventional steerable assembly is placed behind the positive displacement motor, making the measurement point for inclination, azimuth and gamma ray about 45 ft behind the bit. Because of the 45-ft lag in obtaining measurements, the hole can go off course or the formation can change long before the geologist and drillers realize it. This requires steering corrections to get back on course, leading to porpoising effects in the borehole trajectory.

Rotary steerable. RSS provide an alternative method for drilling and controlling the trajectory of laterals. The system used in this case study was chosen for its reliability and full rotating capability, the latter of which plays a critical role in effectively cleaning the borehole. The system uses a push-the-bit tool, in which force applied outward against the wellbore from three mud-actuated pads located immediately above the bit pushes it in the required direction. Every component on the system rotates at full drillstring speed, leaving nothing to drag in the borehole while drilling ahead or while back-reaming to condition the hole. With push-the-bit RSS, the bit axis is in line with the BHA axis, allowing for efficient cutting action and in-gauge bit rotation. Rugosity and cyclical changes in hole diameter are eliminated, resulting in a smooth, uniform borehole, Fig. 3.

Fig. 3. Downhole imaging shows the variation in hole diameter of a borehole that was initially drilled with a conventional steerable motor and subsequently finished using a rotary steerable system.

Hole conditioning. Borehole rugosity, spiral boreholes and porpoising effects are detrimental to running complex OHMS systems due to the increased torque and drag these conditions create, especially in long lateral sections. A reamer run is often performed to condition the borehole prior to running the OHMS. Depending on the condition of the borehole, the process can typically take between one day and a week. Reaming will improve some hole rugosity by opening up tight spots and removing minor ledges in the hole, but it will not change the overall trajectory, including spiral and porpoising effects, which can still hinder placement of the OHMS.

Cuttings removal. Effective removal of cuttings from the borehole is also important, particularly in horizontal boreholes. Due to the tight tolerances between the outside diameter of the OHMS components and inside diameter of the borehole, debris left in the borehole is likely to prove detrimental to the successful deployment of the OHMS. Periodic sweeps, in combination with fluid conditioning procedures—downhole and on surface—are commonly employed to remove cuttings from a horizontal borehole during drilling. Horizontal boreholes present a particular challenge, because flowrate is higher at the top of the well, leading to cuttings fallout and settlement on the lower side of the borehole before they can be transported to surface.

Flow in a horizontal borehole is typically laminar unless mechanical pipe rotation is fast enough to create fluid coupling and a turbulent environment that will keep cuttings suspended within the drilling fluid flow stream. Recommended drill pipe rotational speed for the openhole drilling configuration common to the Bakken is at least 60–70 rpm and ideally exceeds 120 rpm. The average rotational speed for conventional MWD assemblies is 40–45 rpm—far below the recommended speed for maintaining a turbulent environment. In addition, while a conventional system is drilling in sliding mode, there is no pipe rotation, leading to higher rates of cuttings fallout. Due to the inability of conventional drilling assemblies to clean the borehole, more time is required during the reamer run to clean the borehole.

By contrast, RSS incorporates inherently higher pipe rotational speed throughout the drilling process and eliminates slides altogether, resulting in a cleaner borehole. If the drilling procedure is designed to include last-trip borehole conditioning coming out of the hole, it may not be necessary to perform a reamer run before deployment of an OHMS.

Hole verticality. In addition to drilling smooth, uniform boreholes in the horizontal section, it is important to maintain verticality above the kickoff point. Excessive drift and doglegs lead to increased drag, adding to the challenges of drilling extended-reach laterals and deploying complex OHMS completions. Improved verticality also benefits the cost-effectiveness of artificial lift systems, enabling reduced power consumption as a result of lower rod-tubing friction, less frequent rod and/or tubing replacement, and reduced need for oversized pumping units and gear box requirements. Orientating and sliding a conventional steerable assembly are inherently slower than rotary drilling. Additionally, the doglegs placed in the borehole during course-correction slides add considerably more drag during drilling, OHMS deployment and production.

Rotary steerable technology can be programmed to maintain verticality. Rig time is not taken orientating and sliding for course corrections, and the well can be drilled straight. Figure 4 compares two offset wells in the Bakken: one drilled with a conventional steerable motor assembly and the other drilled with RSS. The well drilled with the conventional assembly had numerous course corrections and drifted more than 100 ft off course. The well drilled with RSS was much straighter, had 61% less tortuosity, and was drilled one day faster.

Fig. 4. Inclination in the vertical section of two offset wells in the Bakken—one drilled using RSS and the other with a conventional steerable assembly.

BAKKEN CASE STUDY

The subject well was drilled into the middle member of the Bakken Formation in Burke County, North Dakota. The wellbore architecture included 7-in. intermediate casing set at 90° and 41⁄2-in. liner set inside the intermediate casing near the kickoff point and run throughout the 6-in. openhole lateral. Well depth is 7,843 ft TVD, 13,770 ft MD with an effective lateral length of 5,530 ft. RSS was employed to drill both the vertical and horizontal sections of the well, and a 22-stage OHMS with ball-on-seat diversion was run to TD. Dogleg severity was limited to less than 0.3°/100 ft through the vertical section and less than 5°/100 ft through the horizontal section, resulting in a smooth, uniform borehole from surface to TD. Hole cleaning was addressed with drill pipe rotation consistently in excess of 100 rpm. The well was circulated clean with the drilling BHA at TD for a minimum of three bottoms up and again at 50% of the lateral length—halfway back to the shoe of the intermediate casing—before finally pulling out of the hole to pick up the OHMS. The OHMS completion consisted of 46 tools, including 22 fracture sleeves and 21 openhole packers. Each openhole packer included a solid body and slide-on thermoplastic centralizer on either side of the assembly to provide stand-off from the tool OD and keep the system centralized in the open hole. All of the tools were picked up in order and run in the hole on the 41⁄2-in. liner until the liner hanger packer was made up, and then 4-in., 14.0-lb/ft drill pipe was used to convey the OHMS completion to TD.

The OHMS completion was successfully run to TD without problems, and the well was delivered ahead of schedule and at reduced cost due to the absence of the reamer run budgeted for the project. Weight was never stacked out on the system to keep it moving in the open hole, and the pumps were never engaged while the system was in the open hole to attempt to circulate the OHMS completion to TD. The hookload data was later analyzed, and the resulting friction factors from the OHMS deployment were found to be 0.24 for the cased-hole section and 0.38 for the openhole section. These values are considerably lower than normally observed on similar system installations using conventional MWD. Standard friction factors used for theoretical torque-and-drag simulations in the Bakken are typically 0.30 for the cased-hole section and 0.45 for the openhole section. The use of rotary steerable technology not only drilled a nearly perfectly straight vertical hole that will later optimize artificial lift efficiencies and reduce production costs, but also drilled a high-quality lateral necessary to successfully deploy a high-density OHMS completion.  

ACKNOWLEDGMENTS

This article was prepared from SPE 137864-MS presented at the Canadian Unconventional Resources and International Petroleum Conference held in Calgary, Alberta, Oct. 19–21, 2010. The authors thank the management of Cirque Resources and Packers Plus Energy Services for their permission to publish this article, and Maria Meijer and Jackie Bourgaize at Packers Plus for their assistance in its preparation.