Steerable liner drilling

Under development since 2006, the first-of-its-kind drilling system was successfully field tested in the Norwegian sector of the North Sea.

Arne Torsvoll, Jafar Abdollahi, Morten Eidem, Tore Weltzin, Arne Hjelle and S. A. Rasmussen, Statoil; Sven Krueger, Sascha Schwartze, Carsten Freyer, Trung Huynh and Tore Sorheim, Baker Hughes

Historically, operators and service companies focused on drilling performance optimization and reducing the time to get from spud to total depth. Parameters such as rate of penetration, reduction of non-drilling time and minimization of the overall trip time were targeted for improvement—and certainly continue to be today.

Over time, operators’ growing need to enter mature and depleted reservoirs and areas with high pressure variations brought more complex operational risks, such as narrow drilling margins, hole instability and collapse, and lost circulation. New approaches were needed to deal with these challenges safely and economically.

Starting in 2006, Baker Hughes and Statoil closely collaborated to develop a steerable drilling liner (SDL) system capable of operation in mature and depleted reservoirs. Two SDL system sizes have been developed, a 7-in. system for 8½-in. hole sections and a 9⅝-in. system for 12¼-in. hole sections. In April 2009, after extensive testing of both systems, the 9⅝-in. system was successfully implemented in a field pilot at Brage Field. The 7-in. system was successfully field tested in January 2010 on the Statfjord B platform.

BACKGROUND

Since the early 1990s, several operators have used casing or liner drilling systems to overcome formation and wellbore stability problems, but with limited functionality. Because the market for these systems was then considered a niche market, development of more versatile systems languished. Improvements in other drilling and formation evaluation techniques and liner hanger technologies paved the way for the steerable drilling liner system.

Casing while drilling (CWD) and liner while drilling (LWD) are established techniques with proven potential to reduce operational time and to mitigate operational risks when drilling in hazardous formations. Many of the operated fields on the Norwegian Continental Shelf (NCS) have such hazards. For instance, some high-temperature, high-pressure fields with an initially high reservoir pressure are rapidly depleted in the early production phase. In other fields, formations with varying pore pressures present challenges. The uncertainty of pressures and narrow drilling margins often make well planning and execution a challenge to achieve with proper safety margins.

LWD has been recognized as a very promising technology to overcome the challenges when drilling in such environments. Several design concepts have been reviewed based on field requirements. In some applications, existing CWD techniques might be the solution of choice. However, the majority of reservoir sections are completed with a liner instead of a casing. One reason is that CWD does not fit the requirements for drilling subsea wells from a floating rig. Also, CWD may also not apply in deepwater wells because of limited rig load capacity to handle the potentially heavy casing string.

Baker Hughes and Statoil closely collaborated in the development of the SDL system. The system uses standard drill pipe as the inner string to handle drilling torque and tripping of the drilling BHA and incorporates a conventional rotary steerable system with full steering and logging capabilities.

SYSTEM AND COMPONENTS

The SDL system consists of a retrievable and changeable inner string with a pilot BHA and an outer liner string. Inner and outer strings are connected via a running tool that is located at the top of the liner. The liner rotates slowly (10–40 rpm at surface) while the reamer bit and pilot BHA/bit rotate with an additional 100–135 rpm provided by a modified positive-displacement motor.

As shown in Fig. 1, the running (setting) tool provides the mechanical connection between the drill pipe and the liner. It transmits the torque required to rotate the liner and the axial force that is needed for the liner to RIH or POOH. The running tool is based on conventional equipment with some modifications for this application. It has a ball-activated hydraulic release mechanism, which is isolated during drilling to prevent premature release as a result of drilling pressure spikes. It is also possible to release the tool by applying left-hand torque to the tool from surface. The tool can be re-latched downhole after being serviced at surface.

Fig. 1. SDL components.

For length compensation between the inner and outer string, a thruster is placed on top of the drilling BHA. The thruster has an increased stroke compared with standard thrusters to enable re-drilling of the pilot hole if needed. The created thrust force pushes the landing splines (integral parts of the motor) into a profile inside the liner shoe to define the axial position of the pilot BHA relative to the liner. While drilling, the thrust force is adjusted so that it is higher than the weight on bit (WOB) transmitted to the pilot and reamer bit to avoid axial movement of the pilot BHA. A position sensor enables monitoring of this condition in real time and adjustment of the drilling parameters as required. Part of the failsafe strategy, however, is to avoid axial locking of the inner BHA.

The landing splines are integral parts of the drilling motor, which was modified to provide increased torque capability. The increased torque is necessary because the motor drives both the reamer bit and the pilot BHA, including the bit.

To transmit weight and torque to the reamer bit, the reamer drive sub carries extendable pad elements that provide a reliable connection between the reamer bit and the inner string and can transfer a multiple of the required WOB and torque on bit (TOB). The drilling forces on the reamer bit and the drilling dynamics of the pilot BHA are taken by the inner string and not by the liner shoe. The reamer bit and the liner shoe are decoupled while drilling. This allows for a simplified liner shoe design, requiring no advanced bearing assembly to support the reamer bit.

The pad elements of the reamer drive sub are hydraulically actuated and can be switched on and off via downlink from the surface. For failsafe operation, the tool deactivates automatically after a preset time if no circulation is present. The tool status and additional information such as the activation pressure are sent to surface.

A unique feature of the system is the possibility to change the pilot BHA while the liner remains on bottom. This can be performed by deactivating the reamer drive sub and releasing the liner running tool. Subsequently the inner string can be POOH while the liner remains on bottom. For reconnection downhole, the inner string is simply RIH until the landing splines detect the target position and the liner running tool re-latches. If required, the pilot hole can be worked free by moving the inner string up and down.

The pilot BHA can be configured according to the needs of a particular drilling application. For the first field deployments, a standard AutoTrak X-treme configuration was used, comprising a steering unit; directional, gamma and resistivity measurements; the bidirectional communication and power module (BCPM) for power and communication; and a modular motor to drive the pilot and reamer bit. In addition, a sensor sub was placed into the BHA directly below the reamer bit to monitor downhole vibrations and WOB/TOB distribution.

In selecting the pilot bit, the focus was on steerability, durability and hydraulics. To address the steerability needs of 3°/100 ft, the bit was designed with proven depth-of-cut control technology to provide both steerability and buildup rate capability. The depth-of-cut control features incorporated into the bit were designed specifically for the rate of penetration range planned to be drilled. In addition to providing steerability, this feature also controls pilot bit aggressiveness.

In drilling with reamers and pilot bits, it is very important that the pilot bits are not more aggressive than the reamer bits. By controlling the bit aggressiveness, the balance between weight on reamer (WOR) and WOB can be maintained. An overly aggressive pilot bit will translate into excessive WOR and cause pilot string instability. The pilot bit was designed with five blades, and the hydraulics were optimized for balling applications. The nozzles sizes were chosen to achieve the desired hydraulic horsepower per square inch for the application.

The reamer bit was designed with five blades, similar to the pilot bit. The blades were designed to be thin to provide sufficient junk slot area to evacuate the cuttings generated by both the pilot bit and reamer bit. The reamer bit does not have any nozzles to clean cuttings away, but instead is cleaned using the fluid flowing up the annulus. Reamer balling was a concern due to the low velocity of the annular flow. Placement of the stabilizer below the reamer was optimized using computational fluid dynamics to ensure optimal fluid flow to the reamer. The cutting structure was designed for durability in the targeted formations, but also with more aggressiveness than the pilot bit.

The hydraulically releasable liner running tool was modified to make the release mechanism pressure-neutral during drilling. With a conventional setup, the pressure loss over drilling BHA components would cause unintentional release of the liner running tool during drilling. This was solved by including a pressure isolation sleeve on the inside of the liner running tool to prevent hydraulic pressure from entering the release mechanism. Once the running tool is meant to release, a ball is dropped from surface and lands in the isolation sleeve. The sleeve is then shifted to allow for hydraulic pressure to release the liner running tool as normal.

OPERATIONAL PROCEDURE

Figure 2 shows the SDL system makeup, drill and release procedures. When reaching total depth or in the event of a downhole BHA or inner string failure, the reamer drive sub is deactivated by downlink mud pulse telemetry, and a ball is dropped to hydraulically release the liner running tool from the liner. Once at surface, the running tool is reconfigured or replaced; if the POOH is caused by a failed BHA component, the BHA or component can be changed out.

Fig. 2. Makeup, drill and release procedures.

Well control when applying the SDL system is similar to that used when running a liner combined with sand screens, since the screens are activated by using an inner string. The system’s established well control procedures are based on this procedure:

Running open-ended liner. Well control equipment is the same as when running a conventional liner. Since there is no float in the liner shoe, closing the annular BOP around the liner is insufficient. A conventional swedge premade to a kelly cock is made available throughout the process.

Running BHA and inner string into liner. A high-performance liner quick-connect (QC) tool was developed as a well control feature for handling a potential live well during the installation of the inner string; the lower half of the QC is placed in rotary, a false rotary table is mounted over the QC, and the inner string is run into the liner.

A dedicated QC kick stand is readily available at the drill floor during installation of the inner string. The connection of the QC kick stand to the inner string and liner string is done without the need for a casing tong. The inner string is made up to the kick stand, and the QC ensures proper connection to the liner. With the kick stand in place, well control can be regained per normal practices.

The QC kick stand includes a flow path between the inner string and the inner-string/liner annulus. This allows for circulation and bleed-off possibility from the volumes both inside and outside the inner string.

The QC makes the planned connection of the drill pipe inner string to the liner easy. With the inner stringmade up to the liner top assembly, connection to the upper liner joint can be done without having to rotate the potentially long and heavy inner string to get a proper connection.

Drilling. Conventional well control procedures apply, as there will only be drill pipe through the BOP.

PREPARATION FOR FIELD TRIALS

The 9⅝-in. and 7-in. SDL systems were tested at the Baker Hughes Experimental Test Area (BETA) in Tulsa, Oklahoma, in August 2008 and April 2009, respectively, using a medium-sized conventional land rig with full drilling capacity. The tests verified handling and running procedures; system functionality and integrity; and drilling performance and steering capability.

Following these tests, the 9⅝-in. system was implemented in the 12¼-in. section of Brage Well 31/4-A-13 in July and August 2009. A multidisciplinary piloting task group was established to ensure that all aspects of drilling with the system were thoroughly addressed and that lessons learned during the project development and test phases were included in the planning and execution phase. Drilling logistics and preparation when applying unconventional drilling methods are normally time-consuming, so efforts were made to minimize logistics and handling time.

Because the operation includes running an open-ended liner through the BOP (no float in the liner shoe) and having both liner and drill pipe through the BOP simultaneously when making up the system, special well control procedures apply. Fit-for-purpose procedures and equipment were developed.

The liner was fully centralized by having one centralizer per liner joint. To minimize rig time and handling, all centralizers were mounted onshore.

BRAGE FIELD TRIAL

Because the planned operation was unprecedented and as the well trajectory was planned as a 1,170-m horizontal section, risk-reduction measures were applied, such as drilling the first 990 m of the 12¼-in. section conventionally and the remaining 180 m of the section with the SDL system, Fig. 3.

Fig. 3. Brage pilot well trajectory. The LDS system was used in the purple part of the curve.

After drilling with a conventional 12¼-in. BHA to 3,873 m, the drilling assembly was pulled out of the hole and replaced with the 9⅝-in. SDL system, including the 1,228-m, fully centralized liner.

The system had to be reamed down the last 220 m to 3,873 m due to a tight hole. Once at TD, drilling began carefully until full drilling parameters were established. Table 1 shows the comparison between the average recorded drilling parameters for the conventional drilling (just before total depth of conventional 12¼-in. drilling) and for the SDL system immediately after drilling new formation with the reamer bit.

TABLE 1. Recorded data for conventional drilling and SDL at Brage Field

While drilling, the running tool unintentionally parted, leaving the inner string and the liner downhole. Two separate fishing trips were executed before the inner string and BHA were re-run and reconnected to liner, which, at this stage, had been left stationary downhole for almost five days. It took some effort to free the liner, but after liner rotation and mud circulation were reestablished, the well was successfully drilled to TD of the 12¼-in. section at 4,053.5 m.

After the well was circulated clean, the reamer drive sub was deactivated, and the ball was dropped to release the running tool from the liner to POOH the inner string. Running tool release was unsuccessful, however, and several attempts were executed without success until the backup mechanical release was achieved. The running tool design was later modified to prevent these issues from occurring in future applications.

Apart from the issues noted above, the system proved to be very stable, as very low shock, vibration and stick-slip levels were recorded. Directional control was excellent and equal to conventional rotary steerable drilling.

Liner cementing. After reaching TD, the liner was left in the well and the inner string was pulled. With the current system, there is no backflow (float) valve in the shoe and there is no packer in the liner top. First, a cement retainer was run and the cement job was executed, then the liner top packer was run and activated in a separate trip. The cement operation was particularly important in this well, and to minimize introduction of new operations, the cementing operation was performed with conventional tools and procedures.

However, the SDL procedure includes a time-optimized cement operation where installation of the cement retainer, the cement job and setting of the liner top packer are done in the same run. This was successfully performed on the Statfjord test.

Observed torque and drag. The measured torque and drag matched the simulated values very well on all field tests. For example, the simulated torque of the 9⅝-in. SDL on Brage was 36,000 ft-lb. The average measured value at surface was 34,000 ft-lb.

Torque and drag of an SDL application with the added weight of the liner is higher than that of an application with a conventional drillstring. In the Brage case, the torque of the standard rotary steering BHA was 7,000 ft-lb lower than for the SDL BHA.

Hydraulic profile and hole cleaning. The hydraulic profile of the annulus can be separated into two main parts and two sub-distributions. The two main hydraulic profiles are: 1) the annulus between the open hole/casing and the liner and 2) the annulus between the drill pipe and the previous casing (from the liner running tool to surface). The annulus between the liner and the open hole requires less flowrate to clean the borehole (minimum cutting lifting capacity), while the section above the liner running tool requires higher flowrate due to its larger cross-section.

Vibrations. All SDL operations, for the tests and both the Brage and Statfjord (discussed below) field trials, were started in pre-drilled ratholes—12¼ in. for the 9⅝-in. system and 8½ in. for the 7-in. system. When beginning to drill the pilot hole (6-in. and/or 8½-in.), whirl can be expected due to the fact that the pilot BHA is not stabilized within the bigger rathole. As soon as the first stabilizer is in the new formation, the pilot BHA will be stabilized and the whirl will be minimized.

In the Brage case, the BHA had to be reamed to bottom. The 6¾-in. pilot BHA was not stabilized during the reaming operations in the 12¼-in. open hole. These circumstances led to moderate lateral vibrations. Reducing the flowrate to reduce the bit speed helped slightly, but it did not help to run the tools out of specifications. During reaming operations, when the pilot BHA is out of the pilot hole, lateral vibrations can be expected.

Directional survey quality. Analysis of the raw MWD data compared to the post-section gyro logging of the well showed a good match. Having the liner this close to the MWD tool will have a dramatic effect on the magnetic interference; therefore, all surveys were corrected for magnetic interference in real time.

Rate of penetration. The observed ROP was in the same range as for conventional drilling. All the onshore test wells were drilled in the tophole section, and the average ROP of the last onshore test was 11 m/hr. The average ROP was around 6 m/hr at the Brage well; however, the ROP was controlled to mitigate the operational risk.

The pilot was technically successful; however, the overall operational time was longer than desired. The 9⅝-in. liner was drilled to total depth and cemented in place, and the issues encountered while drilling make the final results even more impressive as several of the SDL system’s key functionalities were successfully performed—such as the procedure for pulling and rerunning the inner string, reconnecting it downhole and continue drilling—as a result of the failures experienced while drilling. The cause for the running tool failure was analyzed, leading to a redesign for future applications.

STATFJORD FIELD TRIAL

The 7-in. SDL was successfully tested at Statfjord Field in January 2010. The section was drilled from 3,000 m MD to 3,181 m MD. The start depth for the SDL was at 3,005 m MD; the first 5 m of the section were drilled with a drillout assembly to drill the float equipment, the casing shoe and a 5-m rathole. The full 176 m of the section were drilled with the 7-in. SDL.

In the first run, the standard SDL configuration was used to drill the pilot BHA to TD. An SDL stand-alone service with the BCPM as a master was successfully tested in the second run. This system setup is a non-steerable BHA option with a very short stick-out of 1.5 m. In the second run, the liner shoe was drilled down into the reservoir. The liner was successfully set to the designated liner depth and cemented. A new 4¾-in. rotary steerable system with near-bit gamma was used for the run and performed very well in conjunction with the SDL system. The near-bit gamma was needed for geo-stopping. All test objectives were achieved.