Rotary Closed-Loop Steerable (RCLS) drilling continues to grow in popularity, especially in the UK North Sea, despite overall downturn in drilling programs. There are two main drivers, which facilitated this growth; the industry's need to reduce operating costs, and the technical limitations of conventional steerable drilling techniques. The degree to which this technology could provide a satisfactory solution to these two areas would depend on the operational perfor-mance of the system (directional performance, dogleg capability, real-time data acquisition and system reliability).
RCLS technology was introduced to the UK sector of the North Sea in May 1997. This technology (AutoTrak) was originally developed in conjunction with ENIAgip in Italy for potential use on extended reach drilling (ERD) type wells. Initially, the technology was limited to the 6 3/4-in. tool size to drill hole sizes in the range 8 3/8-in. to 9 1/2-in. Eighteen months later the 8 1/4-in. tool was introduced to drill hole sizes in the range 12 1/4-in. to 14 3/4-in. Since that time, this drilling technology developed by Baker Hughes INTEQ has drilled 800,000 ft, which represents approximately 78% of the total rotary steerable footage drilled in North Sea UK sector. In view of the general downturn in drilling activity in the period 1999-2000, the growth trend in RCLS activity is significant.
RCLS operations review
In the last three years this technology activity has shown 50% or better growth. Initially, the focus for utilizing rotary steerable drilling technology was in situations where directional operations were considered inefficient with conventional steerable drilling methods, and therefore the emphasis was on cost reduction. Specifically, it was deployed in situations where oriented or slide drilling proved difficult or frequent trips for bit and BHA changes were required.
As confidence in this technology developed, it was deployed on more challenging projects, such as designer well profiles, or on value-added applications, for instance, optimum placement of horizontal wellbore(s) in the reservoir. On typical horizontal well profiles, comprising a combination of build and turn to 90-degree, the use of it in one or more hole sections started to deliver better than P10 drilling performance in a number of North Sea development drilling projects. This includes fields in the West of Shetland and Central North Sea. In mature field developments, it was used to drill more demanding directional well profiles that exceeded the technical limits of conventional drilling methods. Consequently, the technology was used in almost equal measure on relatively low cost platforms and relatively higher cost semisubmersible drilling rigs.
Currently, the utilization on drilling rigs is as follows:
- Platforms: 48%,
- Semisubmersibles: 46%,
- Jack up rigs: 6%.
There are several applications for utilization. There are two main categories, namely cost reduction and value-added applications. The initial focus was on the former applications; however there has been a steady trend towards value-added applications since mid-1999. While cost reduction is a common benefit for both types of application, the potential value of the latter applications can be an order of magnitude greater.
Operational performance of RCLS
Inherently, the rotary steerable drilling operation is more efficient than conventional steerable drilling methods that feature bent housing motor (or turbine) with MWD bottomhole assemblies (BHAs). Although higher instantaneous rates of penetration (ROP) can be achieved with motor or turbine drilling, in general, the elimination of slide drilling and more efficient hole cleaning in rotary steerable drilling enables higher gross ROP to be achieved.
Key factors that determine the anticipated improvement of the operational efficiency of rotary steerable drilling operations compared to conventional drilling operations are:
- Section length, in combination with formation(s) to be drilled determines the number of bits and BHAs required and therefore the expected duration of the drilling operation,
- Amount of directional work, which reflects the degree of difficulty or complexity of the well trajectory,
- Circulation time, which when expressed as a percentage of drilling time is an indicator of potential hole cleaning problems, troublesome formations, wellbore stability ROP (slide/rotary), historically drilling in slide mode is 30-50% less than drilling in rotary mode,
- Trip Time, which is a function of depth, well bore quality, well trajectory and BHA configuration.
This multi-variable problem lends itself to solution by means of a basic spreadsheet calculation. For example in a hypothetical directional well in which a 12 1/4-in. hole section is to be drilled with the following criteria:
- Section length: 7,000 ft,
- Directional work: ratio of slide/rotary drilling is 35%,
- Circulation time: 25% of drilling time,
- ROP: 30 ft/hr slide drilling, 60 ft/hr rotary drilling,
- Trip time is 12 hours (conventional operation).
In the last three years this technology activity has shown 50% or better growth.
The net result is that a 34% improvement is anticipated in the overall efficiency of the drilling operation. This is primarily due to the elimination of slide drilling and reduced circulating time. On an actual well, analysis of offset well data will provide the appropriate range of ROPs, reaming, circulating and trip times to test the sensitivity of the operation.
A review of the 150 deployments of this technology completed thus far in the UK Sector shows that compared to conventional drilling operations, the operational efficiency lies in the range of 30-250%. The more challenging well profiles, with long section lengths and moderate ROPS (30-50 ft/hr), typically yield the highest operational efficiencies. Furthermore, P10 performance or "Technical Limit" performance for conventional drilling operations has been improved by the use of this technology, even allowing for the occurrence of failure of the tool downhole.
The marginal field case
With the likelihood that greater than 30% improvement in operational efficiency is expected with using this technology in favor of conventional drilling methods, this makes the use extremely attractive in most drilling operations including those on drilling platforms. In situations where the daily rig spread cost exceeds
There are two main categories for using RCLS, namely cost reduction and valve-added applications
While the daily operating cost will exceed the daily cost for a conventional drilling operation, the lower overall cost per foot is usually achieved with this technology due to its superior drilling efficiency. Furthermore, the technical benefits can make the difference between achieving a successful well completion and abandoning the well. It has now been widely recognized, among experienced users, that this technology represents a lower risk for drilling directional wells than traditional directional drilling methods (steerable motor or turbine assemblies). The following case study illustrates this point.
A North Sea operator had to abandon the original well after encountering wellbore stability problems while drilling the 6-in. hole section in the reservoir. Drilling the initial hole provided a better understanding of the reservoir geology. A plan was proposed to set a whipstock in the 9 5/8-in. casing prior to milling a window and then sidetrack the well positioning. The new well trajectory was approximately 20-ft TVD above a suspected fault in the problem area. This limited the sidetrack options. Specifically, the following requirements were to be met:
- Sidetrack through the window and build from 25° to 82° with a dogleg of approximately 6 degrees/100 ft
- Maintain 82° tangent for approximately 1,000 ft to ensure the well is placed above the fault
- Build to 90° at 6°/100 ft
- Drill 1,200 ft of lateral section-to-section TD
- Drill the section as quickly as possible to limit the time spent in the unstable formation.
The preference was to sidetrack the well and drill to section TD in 8 1/2-in. hole, with the 6-in. hole planned as contingency as per the original well. For the project to be successful the above requirements could not be compromised.
Field experience had shown that the RCLS system had provided superior directional control and significant improvements in drilling efficiency. However, at the time of the deployment this technology had a lower reliability than the conventional motor and MWD systems available. It was decided to use a conventional steerable motor and MWD assembly to initiate the sidetrack and then use this technology to drill the remaining hole section. It was considered that this technology represented the lower risk option to achieve the directional, TVD, and time constraints of the sidetrack plan and therefore improve the chances of delivering a successful wellbore.
Summary of operations
The sidetrack well was carried out as planned with the well being drilled to section TD in 8 1/2-in. hole section with 1,220 ft of lateral section of which 1,116 ft represented gross oil bearing sands. Comparison of this technology performance with conventional drilling operations revealed the following:
- Wellbore quality: Smoother wellbore with this technology indicated by reduced torque and drag values.
- TVD control: TVD was kept within a two-ft window throughout the lateral section. Similar TVD control was only achieved over a 370-ft section in the original hole.
- Reduced PDC wear: The PDC, which drilled 3,912 ft, showed same wear (2:3) as PDC which drilled only 1,890 ft with conventional assembly on the original hole
- Better hole cleaning: Cuttings discharge were not conclusive because of massive breakout in original hole.
- Increased gross ROP: Saved two days on planned AFE.
- Liner operation: Reduced torque of 8 kftlbs with running 5 1/2-in. liner in 8 1/2-in. sidetrack hole vs. 15 kftlbs when running 7-in. liner in original wellbore.
- Cost Comparison: Estimated cost savings of $2.6 million when comparing the 8 1/2-in. RCLS sidetrack well drilled compared to the original 8 1/2-in. and 6-in. hole sections drilled with conventional operation.
Safety and environmental performance
Following the publication of the Cullen report in 1989, drilling operations in the North Sea have been the subject of intense scrutiny with respect to safety and environmental issues. For every new process or product introduced to the drilling operation, a risk assessment is made which frequently leads to the development of new procedures to ensure that the risks to personnel and damage to the environment are minimal. The introduction of this technology to the drilling operation has facilitated a safer working environment at the rig site in the following respects:
The standard configuration is essentially a one tool BHA, requiring only the make up of the bit on the drive shaft and a stabilizer, collar or SPE HWDP made up on top. Therefore, the field engineers and rig crew work with only two connections.
To date 16% of RCLS deployments in the UK sector of the North Sea have been with water-based mud systems. Nevertheless, the potential to use water-based mud systems is made easier by RCLS.
The reliability of the RCLS system combined with its unique drilling capability has delivered significant improvements in drilling efficiency while reducing operational risk compared to conventional drilling operations. The trend towards value-added applications for RCLS has been established. Potentially, these applications can deliver greater value to the operator by an order of magnitude greater than the direct savings in operating costs. The potential exists for further improvement in operational efficiency with RCLS through reviewing existing drilling practices to ensure that they are relevant to optimum performance of the new drilling technology. The risk of a LIH incident is significantly reduced with the use of RCLS compared to conventional, steerable motor BHAs.
The authors would like to thank Baker Hughes INTEQ for permission to publish the information contained in this paper. We would also like to thank the following North Sea operators who have supported RCLS technology during the period 1997-2001: Agip (UK) Limited, Amerada Hess Limited, BP Exploration, Chevron U.K. Limited, Conoco (U.K.) Limited, Enterprise Oil plc, Kerr -McGee North Sea (U.K.) Limited, Mobil North Sea Limited, Phillips Petroleum Company UK Limited, TotalFinaElf Exploration UK PLC, Shell U.K. Limited.
Editor's Note: This SPE 71840 paper was prepared for presentation at the Offshore Europe Conference held in Aberdeen, Scotland, September 4-7, 2001.